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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)


☒			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2021


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File No. 1-2921

PANHANDLE EASTERN PIPE LINE COMPANY, LP

(Exact name of registrant as specified in its charter)


Delaware			44-0382470
(State or other jurisdiction of incorporation or organization)			(I.R.S. Employer Identification No.)

8111 Westchester Drive, Suite 600, Dallas, Texas 75225

(Address of principle executive offices) (zip code)

(214) 981-0700

(Registrant’s telephone number, including area code)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x

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 x

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 x 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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x 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 x 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 an 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 issues its audit report. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes ☐ No x

Panhandle Eastern Pipe Line Company, LP meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format. Items 1, 2 and 7 have been reduced and Items 10, 11, 12 and 13 have been omitted in accordance with Instruction I.

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PANHANDLE EASTERN PIPE LINE COMPANY, LP

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		Page
PART I
ITEM 1.	BUSINESS	5
ITEM 1A.	RISK FACTORS	8
ITEM 1B.	UNRESOLVED STAFF COMMENTS	21
ITEM 2.	PROPERTIES	21
ITEM 3.	LEGAL PROCEEDINGS	21
ITEM 4.	MINE SAFETY DISCLOSURES	21
PART II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	22
ITEM 6.	[RESERVED]	22
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	22
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	24
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	24
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	24
ITEM 9A.	CONTROLS AND PROCEDURES	25
ITEM 9B.	OTHER INFORMATION	25
ITEM 9C.	DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS	25
PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	26
ITEM 11.	EXECUTIVE COMPENSATION	26
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS	26
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	26
ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	26
PART IV
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	28
ITEM 16.	FORM 10-K SUMMARY	28
	SIGNATURES	31

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RiskDefinitions

The following is a list of certain acronyms and terms generally used throughout this annual report on Form 10-K:


/d						per day

ARO						Asset retirement obligation



Bcf						Billion cubic feet

Energy Transfer						Energy Transfer LP, the parent company of PEPL





ETO						Energy Transfer Operating, L.P., the former parent company of PEPL

Exchange Act						Securities Exchange Act of 1934



FERC						Federal Energy Regulatory Commission





NGA						Natural Gas Act of 1938

ROU						Right-of-use

Sea Robin						Sea Robin Pipeline Company, LLC

SEC						Securities and Exchange Commission

Southwest Gas						Pan Gas Storage LLC (d.b.a. Southwest Gas)

TBtu						Trillion British thermal units

Trunkline						Trunkline Gas Company, LLC

Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by Panhandle Eastern Pipe Line Company, LP, and its subsidiaries (“PEPL” or the “Company”) in periodic press releases and some oral statements of Company officials during presentations about the Company, 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,” “believe,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Company believes 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 Company’s actual results may vary materially from those anticipated, projected, forecasted, estimated or expressed 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 the risk factor summary below and “Item 1A. Risk Factors” included in this annual report.

Risks Related to the Company’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:

•fluctuations in energy commodity prices;

•contracts that must be renegotiated periodically;

•the outbreak of COVID-19;

•financial soundness of our customers;

•failure to retain or replace existing customers or volumes due to declining demand or increased competition;

•risks incident to handling, storing, transporting and providing customers with natural gas;

•terrorist attack;

•union disputes and strikes or work stoppages by unionized employees;

•cybersecurity breaches and other disruptions or failures of our information systems;

•the inability to access or continue to access lands owned by third parties;

•risks associated with constructing new facilities;

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•the Company’s ability to access natural gas reserves;

•the costs of providing pension and other postretirement health care benefits and related funding requirements; and

•failure to attract and retain qualified employees.

Indebtedness. Our business, results of operations, cash flows and financial condition, could be impacted by a downgrade of our credit ratings.

Regulatory Matters. Our business, results of operations, cash flows, financial condition and future growth could be impacted by the following:

•laws, regulations and policies governing the rates and terms and conditions of service;

•costs and liabilities resulting from performance of pipeline integrity programs and related repairs;

•laws and regulations regulating the environmental aspects of our business;

•climate change legislation or regulations restricting emissions of greenhouse gases;

•climate-related decreases in demand for natural gas could negatively affect our business;

•deepwater drilling laws and regulations, delays in the processing and approval of drilling permits; and

•competition for water resources or limitations on water usage for hydraulic fracturing.

Risks Related to our Structure. Our stakeholders could be impacted by risks related to our general partner being controlled by Energy Transfer.

Risks Related to Conflicts of Interest. Our stakeholders could be impacted by conflicts of interest, including:

•potential conflicts of interest faced by our executive officers and directors; and

•our affiliates may compete with us.

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PART I

ITEM 1. BUSINESS

Overview

The Company primarily operates interstate pipelines that transport natural gas from the Gulf of Mexico, South Texas and the Panhandle region of Texas and Oklahoma to major United States markets in the Midwest and Great Lakes regions, as well as natural gas storage assets. These operations are subject to the rules and regulations of the FERC. PEPL’s subsidiaries are Trunkline, Sea Robin and Southwest Gas.

Southern Union Panhandle LLC, an indirect wholly-owned subsidiary of Energy Transfer, owns a 1% general partner interest in PEPL and Energy Transfer indirectly owns a 99% limited partner interest in PEPL. Prior to April 1, 2021, ETO owned Southern Union Panhandle LLC as well as the 99% limited partner interest in PEPL. On April 1, 2021, ETO merged with and into Energy Transfer with Energy Transfer surviving the merger.

Asset Overview

The Company owns and operates a large natural gas open-access interstate pipeline network. The pipeline network, consisting of the Panhandle, Trunkline and Sea Robin transmission systems, serves customers in the Midwest, Gulf Coast and Midcontinent United States with a comprehensive array of transportation and storage services. The Company’s transmission system consists of four large diameter pipelines 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. Trunkline’s transmission system consists of one large diameter pipeline extending approximately 1,400 miles from the Gulf Coast area of Texas and Louisiana through Arkansas, Mississippi, Tennessee, Kentucky, Illinois, Indiana and to Michigan. Sea Robin’s transmission system consists of two offshore Louisiana natural gas supply systems extending approximately 120 miles into the Gulf of Mexico. The Company has five natural gas storage fields located in Illinois, Kansas, Louisiana, Michigan and Oklahoma. Southwest Gas operates four of these fields and Trunkline operates one.

The Company earns most of its revenue by entering into firm transportation and storage contracts, providing capacity for customers to transport and store natural gas in its facilities. The Company provides firm transportation services under contractual arrangements to local distribution company customers and their affiliates, natural gas marketers, producers, other pipelines, electric power generators and a variety of end-users. The Company’s pipelines offer both firm and interruptible transportation to customers on a short-term and long-term basis. Demand for natural gas transmission on the Company’s pipeline systems peaks during the winter months, with the highest throughput and a higher portion of annual total operating revenues occurring during the first and fourth calendar quarters. Average reservation revenue rates realized by the Company are dependent on certain factors, including but not limited to rate regulation, customer demand for capacity, and capacity sold for a given period and, to an extent, utilization of capacity. Commodity or utilization revenues, which are more variable in nature, are dependent upon a number of factors including weather, storage and pipeline capacity availability levels, and customer demand for firm and interruptible services, including parking services. The majority of PEPL’s revenues are related to firm capacity reservation charges, of which reservation charges accounted for 74% of total revenues in 2021.

The following table provides a summary of pipeline transportation (including deliveries made throughout the Company’s pipeline network) in TBtu:


	Years Ended December 31,
	2021	2020
Panhandle transportation	731	759
Trunkline transportation	504	569
Sea Robin transportation	58	67

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The following table provides a summary of certain statistical information associated with the Company at December 31, 2021:


Approximate Miles of Pipelines
Panhandle						6,000
Trunkline						2,000
Sea Robin						1,000
Peak Day Delivery Capacity (Bcf/d)
Panhandle						2.8
Trunkline						0.9
Sea Robin						2.0
Underground Storage Capacity-Owned (Bcf)						71.1
Underground Storage Capacity-Leased (Bcf)						12.0

Weighted-Average Remaining Life in Years of Firm Transportation Contracts (1)
Panhandle						4.9
Trunkline						6.4
Sea Robin (2)						N/A
Weighted-Average Remaining Life in Years of Firm Storage Contracts (1)
Panhandle						4.4
Trunkline						2.3

(1)Weighted by firm capacity volumes.

(2)Sea Robin’s contracts are primarily interruptible.

Regulation

Rate Regulation

The Company is subject to regulation by various federal, state and local governmental agencies, including those specifically described below.

FERC has comprehensive jurisdiction over Panhandle, Trunkline, Sea Robin and Southwest Gas. In accordance with the Natural Gas Act of 1938, FERC’s jurisdiction over natural gas companies encompasses, among other things, the acquisition, operation and disposition of assets and facilities, the services provided and rates charged.

FERC has authority to regulate rates and charges for transportation and storage of natural gas in interstate commerce. FERC also has authority over the construction and operation of pipeline and related facilities utilized in the transportation and sale of natural gas in interstate commerce, including the extension, enlargement or abandonment of service using such facilities. Panhandle, Trunkline, Sea Robin, and Southwest Gas hold certificates of public convenience and necessity issued by FERC, authorizing them to operate the pipelines, facilities and properties now in operation and to transport and store natural gas in interstate commerce.

The Company is also subject to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”) and the Pipeline Safety Improvement Act of 2002, which regulate the safety of natural gas pipelines.

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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 issued an order denying requests for rehearing and clarification of its Revised Policy Statement. In the rehearing order, 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 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 impact that 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 recent 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 return on equity (“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. 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.

By the Order issued January 16, 2019, the FERC initiated a review of PEPL’s existing rates pursuant to Section 5 of the NGA to determine whether the rates currently charged by PEPL are just and reasonable and set the matter for hearing. On August 30, 2019, PEPL 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. A hearing in the combined proceedings commenced on August 25, 2020 and adjourned on September 15, 2020. The initial decision by the administrative law judge was issued on March 26, 2021. On April 26, 2021, PEPL filed its brief on exceptions to the initial decision. On May 17, 2021, PEPL filed its brief opposing exceptions in this proceeding. This matter remains pending before FERC.

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. We are unable to predict what, if any, changes may be proposed as a result of the Pipeline Certification NOI that will affect our natural gas pipeline business or when such proposals, if any, might become effective. Comments in response to the Pipeline Certification NOI were filed by us on May 26, 2021. We do not expect that any change in this policy would affect us in a materially different manner than any other natural gas pipeline company operating in the United States.

For additional information regarding the Company’s regulation and rates, see “Item 1. Business – Environmental” and “Item 1A. Risk Factors.”

Competition

The interstate pipeline and storage systems of the Company compete with those of other interstate and intrastate pipeline companies in the transportation and storage of natural gas. The principal elements of competition among pipelines are rates, terms of service, flexibility and reliability of service.

Natural gas competes with other forms of energy available to the Company’s customers and end-users, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability or price of natural gas and other forms of

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energy, the level of business activity, conservation, legislation and governmental regulation, the capability to convert to alternate fuels and other factors, including weather and natural gas storage levels, affect the ongoing demand for natural gas in the areas served by the Company. In order to meet these challenges, the Company will need to adapt its marketing strategies, the types of transportation and storage services provided and its pricing and rates to address competitive forces. In addition, FERC may authorize the construction of new interstate pipelines that compete with the Company’s existing pipelines.

Environmental

The Company is subject to federal, state and local laws and regulations regarding water quality, hazardous and solid waste management, air quality control and other environmental matters. These laws and regulations require the Company to conduct its operations in a specified manner and to obtain and comply with a wide variety of environmental regulations, licenses, permits, inspections and other approvals. Failure to comply with environmental requirements may expose the Company to significant fines, penalties and/or interruptions in operations. The Company’s environmental policies and procedures are designed to achieve compliance with such laws and regulations. These evolving laws and regulations and claims for damages to property, employees, other persons and the environment resulting from current or past operations may result in significant expenditures and liabilities in the future. The Company engages in a process of updating and revising its procedures for the ongoing evaluation of its operations to identify potential environmental exposures and enhance compliance with regulatory requirements. For additional information concerning the impact of environmental regulation on the Company, see “Item 1A. Risk Factors” and Note 8 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”

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. 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 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.

ITEM 1A. RISK FACTORS

The risks and uncertainties described below are not the only ones faced by the Company. Additional risks and uncertainties that the Company is unaware of, or that it currently deems immaterial, may become important factors that affect it. If any of the following risks occurs, the Company’s business, financial condition, results of operations or cash flows could be materially and adversely affected.

Risks Related to the Company’s Business

Results of Operations and Financial Condition

Fluctuations in energy commodity prices could adversely affect the business of the Company.

If natural gas prices in the supply basins connected to the pipeline systems of the Company are not competitive with prices in other natural gas producing regions able to serve the Company’s customers, the volume of natural gas transported by the Company may be negatively impacted. Natural gas prices can also affect customer demand for the various services provided by the Company.

The pipeline revenues of the Company are generated under contracts that must be renegotiated periodically.

The pipeline revenues of the Company are generated under natural gas transportation contracts that expire periodically and must be replaced. Although the Company will actively pursue the renegotiation, extension and/or replacement of all of its contracts, it cannot assure that it will be able to extend or replace these contracts when they expire or that the terms of any renegotiated contracts will be as favorable as the existing contracts. If the Company is unable to renew, extend or replace these contracts, or if the Company renews them on less favorable terms, it may suffer a material reduction in revenues and earnings.

The outbreak of COVID-19 could adversely impact our business, financial condition and results of operations.

On January 30, 2020, the World Health Organization (“WHO”) announced a global health emergency because of a new strain of coronavirus known as COVID-19 due to the risks it imposes on the international community as the virus spreads globally. In March 2020, the WHO classified the COVID-19 outbreak as a pandemic, based on the rapid increase in exposure globally. The

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global spread of COVID-19 caused a significant decline in economic activity and a reduced demand for goods and services, particularly in the energy industry, due to reduced operations and/or closures of businesses, “shelter in place” and other similar requirements imposed by government authorities, or other actions voluntarily undertaken by individuals and businesses concerned about exposure to COVID-19. The extent to which the COVID-19 pandemic continues to impact our business, operations and financial results depends on numerous evolving factors that we cannot accurately predict, including: the duration and scope of the pandemic; governmental, business and individuals’ actions taken in response to the pandemic and the associated impact on economic activity; the effect on the level of demand for natural gas; our ability to procure materials and services from third parties that are necessary for the operation of our business; our ability to provide our services, including as a result of travel restrictions on our employees and employees of third parties that we utilize in connection with our services; the potential for key executives or employees to fall ill with COVID-19; and the ability of our customers to pay for our services if their businesses suffer as a result of the pandemic.

Reduced demand for natural gas caused by the COVID-19 pandemic may result in the shut-in of production from U.S. oil and gas wells, which in turn may result in decreased utilization of our services related to natural gas.

The factors discussed above could have a material adverse effect on our business, results of operations and financial condition. We may be forced to delay some of our capital projects and our customers, who may be in financial distress, may slow down decision-making, delay planned projects or seek to renegotiate or terminate agreements with us. To the extent our counterparties are successful, we may not be able to obtain new contract terms that are favorable to us or to replace contracts that are terminated.

Further, the effects of the pandemic and geopolitical developments have market impacts, such that additional capital may be more difficult for us to obtain or available only on terms less favorable to us. Our inability to fund capital expenditures could have a material impact on our results of operations.

At this time, we cannot estimate the magnitude and duration of potential social, economic and labor instability as a direct result of COVID-19. Should any of these potential impacts continue for an extended period of time, it will have a negative impact on the demand for our services and an adverse effect on our financial position and results of operations. To the extent these factors adversely affect our business and financial results, they may also have the effect of heightening many of the other risks described in this “Risk Factors” section, as well as the risks discussed or referenced in any applicable prospectus supplement, including in the documents we incorporate by reference herein or therein, such as those relating to our indebtedness, our need to generate sufficient cash flows to service our indebtedness and our ability to comply with the covenants contained in the agreements that govern our indebtedness.

The financial soundness of the Company’s customers could affect its business and operating results and the Company’s credit risk management may not be adequate to protect against customer risk.

As a result of macroeconomic challenges that may impact the economy of the United States and other parts of the world, the Company’s customers may experience cash flow concerns. As a result, if customers’ operating and financial performance deteriorates, or if they are unable to make scheduled payments or obtain credit, customers may not be able to pay, or may delay payment of, accounts receivable owed to the Company. The Company’s credit procedures and policies may not be adequate to fully eliminate customer credit risk. In addition, in certain situations, the Company may assume certain additional credit risks for competitive reasons or otherwise. Any inability of the Company’s customers to pay for services could adversely affect the Company’s financial condition, results of operations and cash flows.

The pipeline business of the Company is dependent on a small number of customers for a significant percentage of its sales.

Historically, a small number of customers has accounted for a large portion of the Company’s revenue. The loss of any one or more of these customers could have a material adverse effect on the Company’s business, financial condition, results of operations or cash flows.

The pipeline business of the Company is subject to competition.

The interstate pipeline and storage business of the Company competes with those of other interstate and intrastate pipeline companies in the transportation and storage of natural gas. The principal elements of competition among pipelines are rates, terms of service and the flexibility and reliability of service. Natural gas competes with other forms of energy available to the Company’s customers and end-users, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability or price of natural gas and other forms of energy, the level of business activity, conservation, legislation and governmental regulations, the capability to convert to alternate fuels and other factors, including weather and natural gas storage levels, affect the demand for natural gas in the areas served by the Company.

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The Company is subject to operating risks.

The Company’s operations are subject to all operating hazards and risks incident to handling, storing, transporting and providing customers with natural gas, including adverse weather conditions, explosions, pollution, release of toxic substances, fires and other hazards, each of which could result in damage to or destruction of its facilities or damage to persons and property. If any of these events were to occur, the Company could suffer substantial losses. Moreover, as a result, the Company has been, and likely will be, a defendant in legal proceedings and litigation arising in the ordinary course of business. While the Company maintains insurance against many of these risks to the extent and in amounts that it believes are reasonable, the Company’s insurance coverages have significant deductibles and self-insurance levels, limits on maximum recovery, and do not cover all risks. There is also the risk that the coverages will change over time in light of increased premiums or changes in the terms of the insurance coverages that could result in the Company’s decision to either terminate certain coverages, increase deductibles and self-insurance levels, or decrease maximum recoveries. In addition, there is a risk that the insurers may default on their coverage obligations. As a result, the Company’s results of operations, cash flows or financial condition could be adversely affected if a significant event occurs that is not fully covered by insurance.

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 the 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, 2021, 206 employees of the Company, representing approximately 39% of our workforce, are 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 is 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 (“DDoS”) 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 by our or our service providers’ employees and contractors (e.g., due to social engineering or phishing attacks). In addition, the COVID-19 pandemic has presented additional operational and cybersecurity risks to our information technology infrastructure and physical assets due to our providers’ work-from-home arrangements.

We and certain of our service providers have, from time to time, been subject to cyberattacks and security incidents. The frequency and magnitude of cyberattacks is expected to increase and attackers are becoming more sophisticated. 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, and have a material adverse effect on our operations, financial position and results of operations. A successful cyberattack or other security incident could

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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, 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 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..

The inability to continue to access lands owned by third parties could adversely affect the Company’s ability to operate and/or expand its pipeline and gathering and processing businesses.

The ability of the Company to operate in certain geographic areas will depend on the Company’s success in maintaining existing rights-of-way and obtaining new rights-of-way. The Company cannot assure that it will be able to acquire all of the necessary new rights-of-way or maintain access to existing rights-of-way upon the expiration of the current rights-of-way or that all of the rights-of-way will be obtainable in a timely fashion. The Company’s financial position could be adversely affected if the costs of new or extended rights-of-way materially increase or the Company is unable to obtain or extend the rights-of-way timely.

The expansion of the Company’s pipeline systems by constructing new facilities subjects the Company to construction and other risks that may adversely affect the financial results of the pipeline businesses.

The Company may expand the capacity of its existing pipeline and storage facilities by constructing additional facilities. Construction of these facilities is subject to various regulatory, development and operational risks, including:

•the Company’s ability to obtain necessary approvals and permits from FERC and other regulatory agencies on a timely basis and on terms that are acceptable to it;

•the ability to access sufficient capital at reasonable rates to fund expansion projects, especially in periods of prolonged economic decline when the Company may be unable to access capital markets;

•the availability of skilled labor, equipment, and materials to complete expansion projects;

•adverse weather conditions;

•potential changes in federal, state and local statutes, regulations, and orders, including environmental requirements that delay or prevent a project from proceeding or increase the anticipated cost of the project;

•impediments on the Company’s ability to acquire rights-of-way or land rights or to commence and complete construction on a timely basis or on terms that are acceptable to it;

•the Company’s ability to construct projects within anticipated costs, including the risk that the Company may incur cost overruns, resulting from inflation or increased costs of equipment, materials, labor, contractor productivity, delays in construction or other factors beyond its control, that the Company may not be able to recover from its customers;

•the lack of future growth in natural gas supply and/or demand; and

•the lack of transportation, storage and throughput commitments.

Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs. There is also the risk that a downturn in the economy and its potential negative impact on natural gas demand may result in either slower development in the Company’s expansion projects or adjustments in the contractual commitments supporting such projects. As

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a result, new facilities could be delayed or may not achieve the Company’s expected investment return, which may adversely affect the Company’s business, financial condition, results of operations and cash flows.

The success of the Company depends on the continued development of additional natural gas reserves in the vicinity of its facilities and the ability to access additional reserves to offset the natural decline from existing sources connected to its system.

The amount of revenue generated by the Company ultimately depends upon the access to reserves of available natural gas. As the reserves available through the supply basins connected to the Company’s system naturally decline, a decrease in development or production activity could cause a decrease in the volume of natural gas available for transmission. If production from these natural gas reserves is substantially reduced and not replaced with other sources of natural gas, such as new wells or interconnections with other pipelines, and certain of the Company’s assets are consequently not utilized, the Company may have to accelerate the recognition and settlement of asset retirement obligations. Investments by third parties in the development of new natural gas reserves or other sources of natural gas in proximity to the Company’s facilities depend on many factors beyond the Company’s control. Revenue reductions or the acceleration of asset retirement obligations resulting from the decline of natural gas reserves and the lack of new sources of natural gas may have a material adverse effect on the Company’s business, financial condition, results of operations and cash flows.

The costs of providing postretirement health care benefits and related funding requirements are subject to changes in other postretirement fund values and fluctuating actuarial assumptions and may have a material adverse effect on the Company’s financial results. In addition, the passage of the Health Care Reform Act in 2010 could significantly increase the cost of providing health care benefits for Company employees.

The Company provides postretirement healthcare benefits to certain of its employees. The costs of providing postretirement health care benefits and related funding requirements are subject to changes in postretirement fund values and fluctuating actuarial assumptions that may have a material adverse effect on the Company’s future financial results. In addition, the passage of the Health Care Reform Act of 2010 has increased the cost of health care benefits for its employees. While certain of the costs incurred in providing such postretirement healthcare benefits are recovered through the rates charged by the Company’s regulated businesses, the Company may not recover all of its 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.

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.

Indebtedness

Credit ratings downgrades could increase the Company’s financing costs.

The Company is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of the Company’s lending agreements. However, if its current credit ratings were downgraded below investment grade, the Company could be negatively impacted as follows:

•Borrowing costs associated with existing debt obligations could increase in the event of a credit rating downgrade;

•The costs of refinancing debt that is maturing or any new debt issuances could increase due to a credit rating downgrade; and

•FERC may be unwilling to allow the Company to pass along increased debt service costs to natural gas customers.

The Company’s credit rating can be impacted by the credit rating and activities of its parent company. Thus, adverse impacts to Energy Transfer and its activities, which may include activities unrelated to the Company, may have adverse impacts on the Company’s credit rating and financing and operating costs.

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Regulatory Matters

The Company’s business is highly regulated.

The Company’s transportation and storage business is subject to regulation by federal, state and local regulatory authorities. FERC, the United States Department of Transportation and various state and local regulatory agencies regulate the interstate pipeline business. In particular, FERC has authority to regulate rates charged by the Company for the transportation and storage of natural gas in interstate commerce. FERC also has authority over the construction, acquisition, operation and disposition of these pipeline and storage assets.

The Company’s rates and operations are subject to extensive regulation by federal regulators as well as the actions of Congress and state legislatures and, in some respects, state regulators. The Company cannot predict or control what effect future actions of regulatory agencies may have on its business or its access to the capital markets. Furthermore, the nature and degree of regulation of natural gas companies has changed significantly during the past several decades and there is no assurance that further substantial changes will not occur or that existing policies and rules will not be applied in a new or different manner. Should new and more stringent regulatory requirements be imposed, the Company’s business could be unfavorably impacted and the Company could be subject to additional costs that could adversely affect its financial condition or results of operations if these costs are not ultimately recovered through rates.

The Company’s transportation and storage business is also influenced by fluctuations in costs, including operating costs such as insurance, postretirement and other benefit costs, wages, outside contractor services costs, asset retirement obligations for certain assets and other operating costs. The profitability of regulated operations depends on the business’ ability to collect such increased costs as a part of the rates charged to its customers. To the extent that such operating costs increase in an amount greater than that for which revenue is received, or for which rate recovery is allowed, this differential could impact operating results. The lag between an increase in costs and the ability of the Company to file to obtain rate relief from FERC to recover those increased costs can have a direct negative impact on operating results. As with any request for an increase in rates in a regulatory filing, once granted, the rate increase may not be adequate. In addition, FERC may prevent the business from passing along certain costs in the form of higher rates. Competition may prevent the recovery of increased costs even if allowed in rates.

FERC may also exercise its Section 5 authority to initiate proceedings to review rates that it believes may not be just and reasonable. FERC has recently exercised this authority with respect to several other pipeline companies. If FERC were to initiate a Section 5 proceeding against the Company and find that the Company’s rates at that time were not just and reasonable due to a lower rate base, reduced or disallowed operating costs, or other factors, the applicable maximum rates the Company is allowed to charge customers could be reduced and the reduction could potentially have a material adverse effect on the Company’s business, financial condition, results of operations or cash flows.

A rate reduction is also a possible outcome with any Section 4 rate case proceeding for the regulated entities of the Company, including any rate case proceeding required to be filed as a result of a prior rate case settlement. A regulated entity’s rate base, upon which a rate of return is allowed in the derivation of maximum rates, is primarily determined by a combination of accumulated capital investments, accumulated regulatory basis depreciation, and accumulated deferred income taxes. Such rate base can decline due to capital investments being less than depreciation over a period of time, or due to accelerated tax depreciation in excess of regulatory basis depreciation. By the Order issued January 16, 2019, the FERC initiated a review of PEPL’s existing rates pursuant to Section 5 of the NGA to determine whether the rates currently charged by PEPL are just and reasonable and set the matter for hearing. On August 30, 2019, PEPL 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. A hearing in the combined proceedings commenced on August 25, 2020 and adjourned on September 15, 2020. The initial decision by the administrative law judge was issued on March 26, 2021. On April 26, 2021, PEPL filed its brief on exceptions to the initial decision. On May 17, 2021, PEPL filed its brief opposing exceptions in this proceeding. This matter remains pending before FERC.

Our interstate 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

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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 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.

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 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 rates. 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. 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 Energy Transfer’s cost of service components and the outcomes of any challenges to our rates by the FERC or our shippers.

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2021. On April 26, 2021, PEPL filed its brief on exceptions to the initial decision. On May 17, 2021, PEPL filed its brief opposing exceptions in this proceeding. This matter remains pending before FERC.

Our interstate 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 pipelines, including:

•terms and conditions of service;

•the types of services interstate pipelines may or must offer their customers;

•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 do so in a timely manner and free from potentially burdensome conditions. Future changes to laws, regulations, policies and interpretations thereof in these and other applicable areas 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 Natural Gas Act. A technical conference was held on November 19, 2021, and post-technical conference comments were submitted to the FERC on January 7, 2022. The FERC has not taken any further action regarding the 2018 NOI, 2021 NOI, or Technical Conference on Greenhouse Gas Mitigation, and we are unable to predict what, if any, changes may be proposed as a result of the NOIs or following the technical conference that might affect our natural gas pipeline or LNG facility operations, or when such proposals, if any, might become effective. We do not expect that any change in this policy would affect us in a materially different manner than any other similarly sized natural gas pipeline company operating in the United States.

We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.

Pursuant to authority under the NGPSA, the Pipeline and Hazardous Materials Safety Administration (“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 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:

•perform ongoing assessments of pipeline integrity;

•identify and characterize applicable threats to pipeline segments that could impact an HCA;

•improve data collection, integration and analysis;

•repair and remediate the pipeline as necessary; and

•implement preventive and mitigating actions.

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

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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 maximum allowable operating pressure, 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 changes adopted by these rulemakings could have a material adverse effect on our results of operations and costs of transportation services.

The Company is subject to extensive federal, state and local laws and regulations regulating the environmental aspects of its business that may increase its costs of operations, expose it to environmental liabilities and require it to make material unbudgeted expenditures.

The Company is subject to extensive federal, state and local laws and regulations regulating the environmental aspects of its business (including air emissions), which are complex, change from time to time and have tended to become increasingly strict. These laws and regulations have necessitated, and in the future may necessitate, increased capital expenditures and operating costs. In addition, certain environmental laws may result in liability without regard to fault concerning contamination at a broad range of properties, including currently or formerly owned, leased or operated properties and properties where the Company disposed of, or arranged for the disposal of, waste.

The Company is currently monitoring or remediating contamination at several of its facilities and at waste disposal sites pursuant to environmental laws and regulations and indemnification agreements. The Company cannot predict with certainty the sites for which it may be responsible, the amount of resulting cleanup obligations that may be imposed on it or the amount and timing of future expenditures related to environmental remediation because of the difficulty of estimating cleanup costs and the uncertainty of payment by other potentially responsible parties.

Costs and obligations also can arise from claims for toxic torts and natural resource damages or from releases of hazardous materials on other properties as a result of ongoing operations or disposal of waste. Compliance with amended, new or more stringently enforced existing environmental requirements, or the future discovery of contamination, may require material unbudgeted expenditures. These costs or expenditures could have a material adverse effect on the Company’s business, financial condition, results of operations or cash flows, particularly if such costs or expenditures are not fully recoverable from insurance or through the rates charged to customers or if they exceed any amounts that have been reserved.

Climate change legislation or regulations restricting emissions of greenhouse gases (“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 greenhouse gas 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. 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

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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 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, 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 November 2021, the EPA issued a proposed rule that, if finalized, would establish 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 would 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 EPA plans to issue a supplemental proposal enhancing this proposed rulemaking in 2022 that will contain proposed rule text, which was not included in the November 2021 proposed rule, and anticipates issuing a final rule by the end of 2022. 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.

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. 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 final recommendations are expected in early 2022. 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 is also increasing financial risk 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. 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 activities or for us to obtain funding for growth projects, and consequently could both indirectly affect demand for our services and directly affect our ability to fund construction or other capital projects. Additionally, the SEC announced its intention to promulgate rules requiring climate disclosures. 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 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. 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 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 natural gas could negatively affect our business.

Supply and demand for natural gas 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 natural gas, thereby potentially causing a reduction in the demand for such product. A broader transition to alternative fuels or energy sources, whether resulting from potential new government regulation, carbon taxes or consumer preferences could result in decreased demand for hydrocarbon products like natural gas. Any decrease in demand for could consequently reduce demand for our services and could have a negative effect on our business.

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 United States Department of the Interior, 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 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

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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 October 2020, BOEM and BSEE published a proposed rule regarding financial assurance requirements for offshore leases, particularly regarding requirements for bonds above base amounts prescribed by regulation. 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 has 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 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.

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.

Risks Related to our Structure

Our General Partner.

The Company is controlled by Energy Transfer.

The Company is an indirect wholly-owned subsidiary of Energy Transfer. Energy Transfer executives serve as the board of managers and as executive officers of the Company. Accordingly, Energy Transfer controls and directs all of the Company’s business affairs, decides all matters submitted for member approval and may unilaterally effect changes to its management team. In circumstances involving a conflict of interest between Energy Transfer, on the one hand, and the Company’s creditors, on the other hand, the Company can give no assurance that Energy Transfer would not exercise its power to control the Company in a manner that would benefit Energy Transfer to the detriment of the Company’s creditors.

Risks Related to Conflicts of Interest

Some of our executive officers and directors face potential conflicts of interest in managing our business.

Certain of our executive officers and directors are also officers and/or directors of Energy Transfer. These relationships may create conflicts of interest regarding corporate opportunities and other matters. The resolution of any such conflicts may not always be in our or our creditors’ best interests. In addition, these overlapping executive officers and directors allocate their time among us and Energy Transfer. These officers and directors face potential conflicts regarding the allocation of their time, which may adversely affect our business, results of operations and financial condition.

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Our affiliates may compete with us.

Our affiliates and related parties are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act. Forward-looking statements are based on management’s beliefs and assumptions. These forward-looking statements, which address the Company’s expected business and financial performance, among other matters, are identified by terms and phrases such as: anticipate, believe, intend, estimate, expect, continue, should, could, may, plan, project, predict, will, potential, forecast and similar expressions. Forward-looking statements involve risks and uncertainties that may or could cause actual results to be materially different from the results predicted. Factors that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

•changes in demand for natural gas and related services by customers, in the composition of the Company’s customer base and in the sources of natural gas accessible to the Company’s system;

•the effects of inflation and the timing and extent of changes in the prices and overall demand for and availability of natural gas as well as electricity, oil, coal and other bulk materials and chemicals;

•adverse weather conditions, such as warmer or colder than normal weather in the Company’s service territories, as applicable, and the operational impact of natural disasters;

•changes in laws or regulations, third-party relations and approvals, and decisions of courts, regulators and/or governmental bodies affecting or involving the Company, including deregulation initiatives and the impact of rate and tariff proceedings before FERC and various state regulatory commissions;

•the speed and degree to which additional competition, including competition from alternative forms of energy, is introduced to the Company’s business and the resulting effect on revenues;

•the impact and outcome of pending and future litigation and/or regulatory investigations, proceedings or inquiries;

•the ability to comply with or to successfully challenge existing and/or or new environmental, safety and other laws and regulations;

•unanticipated environmental liabilities;

•the uncertainty of estimates, including accruals and costs of environmental remediation;

•the impact of potential impairment charges;

•the ability to acquire new businesses and assets and to integrate those operations into its existing operations, as well as its ability to expand its existing businesses and facilities;

•the timely receipt of required approvals by applicable governmental entities for the construction and operation of the pipelines and other projects;

•the ability to complete expansion projects on time and on budget;

•the ability to control costs successfully and achieve operating efficiencies, including the purchase and implementation of new technologies for achieving such efficiencies;

•the impact of factors affecting operations such as maintenance or repairs, environmental incidents, natural gas pipeline system constraints and relations with labor unions representing bargaining-unit employees;

•the performance of contractual obligations by customers, service providers and contractors;

•exposure to customer concentrations with a significant portion of revenues realized from a relatively small number of customers and any credit risks associated with the financial position of those customers;

•changes in the ratings of the Company’s debt securities;

•the risk of a prolonged slow-down in growth or decline in the United States economy or the risk of delay in growth or decline in the United States economy, including liquidity risks in United States credit markets;

•the impact of unsold pipeline capacity being greater than expected;

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•changes in interest rates and other general market and economic conditions, and in the Company’s ability to obtain additional financing on acceptable terms, whether in the capital markets or otherwise;

•declines in the market prices of equity and debt securities and resulting funding requirements for other postretirement benefit plans;

•acts of nature, sabotage, terrorism or other similar acts that cause damage to the facilities or those of the Company’s suppliers’ or customers’ facilities;

•market risks beyond the Company’s control affecting its risk management activities including market liquidity, commodity price volatility and counterparty creditworthiness;

•the availability/cost of insurance coverage and the ability to collect under existing insurance policies;

•the risk that material weaknesses or significant deficiencies in internal controls over financial reporting could emerge or that minor problems could become significant;

•changes in accounting rules, regulations and pronouncements that impact the measurement of the results of operations, the timing of when such measurements are to be made and recorded and the disclosures surrounding these activities;

•the effects of changes in governmental policies and regulatory actions, including changes with respect to income and other taxes, environmental compliance, climate change initiatives, authorized rates of recovery of costs (including pipeline relocation costs), and permitting for new natural gas production accessible to the Company’s systems;

•market risks affecting the Company’s pricing of its services provided and renewal of significant customer contracts;

•actions taken to protect species under the Endangered Species Act and the effect of those actions on the Company’s operations;

•the impact of union disputes, employee strikes or work stoppages and other labor-related disruptions; and

•other risks and unforeseen events, including other financial, operational and legal risks and uncertainties detailed from time to time in filings with the SEC.

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of the Company’s forward-looking statements. Other factors could also have material adverse effects on the Company’s future results. In light of these risks, uncertainties and assumptions, the events described in forward-looking statements might not occur or might occur to a different extent or at a different time than the Company has described. The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by law.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

See “Item 1. Business” for information concerning the general location and characteristics of the important physical properties and assets of the Company.

ITEM 3. LEGAL PROCEEDINGS

The Company and certain of its affiliates are occasionally parties to lawsuits and administrative proceedings incidental to their businesses involving, for example, claims for personal injury and property damage, contractual matters, various tax matters, and rates and licensing. The Company and its affiliates are also subject to various federal, state and local laws and regulations relating to the environment, as described in “Item 1. Business – Regulation.” Several of these companies have been named parties to various actions involving environmental issues. Based on the Company’s current knowledge and subject to future legal and factual developments, the Company’s management believes that it is unlikely that these actions, individually or in the aggregate, will have a material adverse effect on its consolidated financial position, results of operations or cash flows. For additional information regarding various pending administrative and judicial proceedings involving regulatory, environmental and other legal matters, reference is made to Note 8 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.” Also see “Item 1A. Risk Factors.”

ITEM 4. MINE SAFETY DISCLOSURE

Not applicable.

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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

(Tabular dollar amounts are in millions)

The information in Item 7 has been prepared pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K. Accordingly, this Item 7 includes only management’s narrative analysis of the results of operations and certain supplemental information.

Overview

The Company’s business is conducted through both short- and long-term contracts with customers. Shorter-term contracts, both firm and interruptible, tend to have a greater impact on the volatility of revenues. Short-term and long-term contracts are affected by changes in market conditions and competition with other pipelines, changing supply sources and volatility in natural gas prices and basis differentials. Demand for natural gas transmission services on the Company’s pipeline system is seasonal, with the highest throughput and a higher portion of annual total operating revenues occurring in the traditional winter heating season, which occurs during the first and fourth calendar quarters. Since the majority of the Company’s revenues are related to firm capacity reservation charges, which customers pay whether they utilize their contracted capacity or not, volumes transported do not have as significant an impact on revenues over the short-term. However, longer-term demand for capacity may be affected by changes in the customers’ actual and anticipated utilization of their contracted capacity and other factors. For additional information concerning the Company’s related risk factors and the weighted-average remaining lives of firm transportation and storage contracts, see “Item 1A. Risk Factors” and “Item 1. Business,” respectively.

The Company’s regulated transportation and storage businesses can file, or be required to file, for changes in their rates, which are subject to approval by FERC. Although a significant portion of the Company’s contracts are discounted or negotiated rate contracts, changes in rates and other tariff provisions resulting from regulatory proceedings have the potential to impact negatively the Company’s results of operations and financial condition. For information related to the status of current rate filings, see “Item 1. Business – Regulation.”

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Results of Operations


	Years Ended December 31,
	2021		2020
OPERATING REVENUES:
Transportation and storage of natural gas	$	486	$	528

Operational gas sales	67		—
Other	18		19
Total operating revenues (1)	571		547
OPERATING EXPENSES:

Operating and maintenance	206		177
General and administrative	36		37
Depreciation and amortization	104		116

Total operating expenses	346		330
OPERATING INCOME	225		217
OTHER EXPENSE:
Interest expense, net	(14)		(14)
Interest expense - related company	(17)		(32)

Other, net	1		(3)
Total other expense, net	(30)		(49)
INCOME BEFORE INCOME TAX BENEFIT	195		168
Income tax benefit	(1)		(3)
NET INCOME	$	196	$	171


Natural gas volumes transported (TBtu): (2)
Panhandle	731		759
Trunkline	504		569
Sea Robin	58		67

(1)Reservation revenues comprised 74% and 88% of total operating revenues for the years ended December 31, 2021 and 2020, respectively.

(2)Includes transportation deliveries made throughout the Company’s pipeline network.

The following is a discussion of the significant items and variances impacting the Company’s net income during the periods presented above:

•Transportation and storage of natural gas. Transportation and storage of natural gas revenues decreased for the year ended December 31, 2021 compared to the prior year primarily due to lower capacity sold and lower utilization of capacity sold.

•Operational gas sales. Operational gas sales increased for the year ended December 31, 2021 compared to the prior year due to the impact of Winter Storm Uri in February 2021.

•Operating and maintenance. Operating and maintenance expenses increased for the year ended December 31, 2021 compared to the prior year primarily due to higher employer costs and expenses associated with asset retirement obligations.

•Depreciation and amortization. Depreciation and amortization decreased for the year ended December 31, 2021 compared to the prior year primarily due to changes in certain estimates.

•Interest expense - related company. Interest expense - related company decreased for the year ended December 31, 2021 compared to the prior year primarily due to lower average borrowings outstanding under a note payable due to the Company’s parent.

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OTHER MATTERS

Environmental Matters

The Company is subject to federal, state and local laws and regulations relating to the protection of the environment. These evolving laws and regulations may require expenditures over a long period of time to control environmental impacts. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures. These procedures are designed to achieve compliance with such laws and regulations. For additional information concerning the impact of environmental regulation on the Company, see Note 8 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”

Contingencies and Regulatory Matters

See “Item 1. Business - Regulation” and Note 8 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of December 31, 2021, the Company had $54 million of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of less than $1 million annually.

Commodity Price Risk

The Company is exposed to some commodity price risk with respect to natural gas used in operations by its interstate pipelines. Specifically, the pipelines receive natural gas from customers for use in generating compression to move the customers’ natural gas. Additionally, the pipelines may have to settle system imbalances when customers’ actual receipts and deliveries do not match. When the amount of natural gas utilized in operations by the pipelines differs from the amount provided by customers, the pipelines may use natural gas from inventory or may have to buy or sell natural gas to cover these or other operational needs, resulting in commodity price risk exposure to the Company. In addition, the Company has other indirect exposure to the extent commodity price changes affect customer demand for and utilization of transportation and storage services provided by the Company. At December 31, 2021, the Company had no hedges outstanding.

Credit Risk

Credit risk refers to the risk that a shipper may default on its contractual obligations resulting in a credit loss to the Company. A credit policy has been approved and implemented to govern the Company’s portfolio of shippers with the objective of mitigating credit losses. This policy establishes guidelines, controls, and limits, consistent with FERC filed tariffs, to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential shippers, monitoring agency credit ratings, and by implementing credit practices that limit credit exposure according to the risk profiles of the shippers. Furthermore, the Company may, at times, require credit support under certain circumstances in order to mitigate credit risk as necessary.

The Company’s shippers consist of a diverse portfolio of customers across the energy industry, including oil and gas producers, midstream companies, municipalities, electric and gas utilities, and commercial and industrial end users. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that could impact our shippers 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 shipper non-performance.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The financial statements starting on page F-1 of this report are incorporated by reference.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

An evaluation was performed under the supervision and with the participation of our management, including the Co-Chief Executive Officers and Chief 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 the Co-Chief Executive Officers and Chief Financial Officer, concluded that our disclosure controls and procedures were adequate and effective as of December 31, 2021.

Management’s Report on Internal Control over Financial Reporting

The Company’s management 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, 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”).

Based on our evaluation under the COSO framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2021.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting (as defined in Rules 13a–15(f) or Rule 15d–15(f)) that occurred in the three months ended December 31, 2021 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

“Item 10. Directors, Executive Officers and Corporate Governance” has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

ITEM 11. EXECUTIVE COMPENSATION

“Item 11. Executive Compensation” has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

“Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

“Item 13. Certain Relationships and Related Transactions, and Director Independence” has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table sets forth fees billed by Grant Thornton LLP for the audits of our annual financial statements and other services rendered (dollars in thousands):


	Years Ended December 31,
	2021		2020
Audit fees (1)	$	688	$	667
Audit related fees (2)	33		32


Total Fees	$	721	$	699

(1)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.

(2)Includes fees in connection with the services organization control report on PEPL’s centralized data center.

The Energy Transfer Audit Committee is responsible for the oversight of our accounting, reporting and financial practices, pursuant to the charter of the Energy Transfer Audit Committee. Prior to the merger of ETO into Energy Transfer in April 2021, the ETO Audit Committee was responsible for such oversight under its charter. The Energy Transfer Audit Committee (and previously the ETO 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 Energy Transfer Audit Committee (and previously the ETO Audit Committee) also oversees and directs our internal auditing program and reviews our internal controls.

The Energy Transfer Audit Committee (and previously the ETO 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 Energy Transfer Audit Committee (and previously the ETO Audit Committee). All fees paid or expected to be paid to Grant Thornton LLP for fiscal years 2021 and 2020 were pre-approved by the Energy Transfer Audit Committee or the ETO Audit Committee in accordance with the respective policy.

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The Energy Transfer Audit Committee (and previously the ETO 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.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)The following documents are filed as a part of this Report:

(1)Financial Statements - see Index to Financial Statements appearing on page F-1.

(2)Financial Statement Schedules - None.

(3)Exhibits - see Index to Exhibits set forth on page 28.

ITEM 16. FORM 10-K SUMMARY

None.

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INDEX TO EXHIBITS

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.


Exhibit Number						Description

3(a)						Certificate of Formation of Panhandle Eastern Pipe Line Company, LP (incorporated by reference to Exhibit 3.A to Form 10-K (File No. 001-02921) filed March 16, 2005)

3(b)						Limited Partnership Agreement of Panhandle Eastern Pipe Line Company, LP, dated as of June 29, 2004, between Southern Union Company and Southern Union Panhandle LLC (incorporated by reference to Exhibit 3.B to Form 10-K (File No. 001-02921) filed March 16, 2005)

3(c)						Amendment No. 1, dated January 10, 2014, to Agreement of Limited Partnership of Panhandle Eastern Pipe Line Company, LP (incorporated by reference to Exhibit 3.1 to Form 8-K (File No. 001-02921) filed January 10, 2014)

4(a)						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)

4(b)						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)









4(c)						Second Supplemental Indenture between Southern Union Company and The Bank of New York, N.A., as Trustee, dated as of October 23, 2006 (incorporated 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 Form 8-K/A (File No. 001-06407) filed October 26, 2006)

4(d)						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)

4(e)						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)

4(f)						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)

4(g)						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)

4(h)						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)














31.1*						Certification of Co-Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2*						Certification of Co-Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.3*						Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1**						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

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Exhibit Number						Description

32.2**						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

32.3**						Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002





101*						Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets; (ii) our Consolidated Statements of Operations and Comprehensive Income; (iii) our Consolidated Statements of Partners’ Capital; (iv) our Consolidated Statements of Cash Flows; and (v) the notes to our Consolidated Financial Statements








104						Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)



*						Filed herewith.
**						Furnished herewith.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, Panhandle Eastern Pipe Line Company, LP has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		PANHANDLE EASTERN PIPE LINE COMPANY, LP




February 18, 2022	By:	/s/ A. Troy Sturrock
		A. Troy Sturrock
		Vice President and Controller
		(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 by the following persons on behalf of Panhandle Eastern Pipe Line Company, LP, in the capacities and on the dates indicated:

Signature

Title

Date

(i)

/s/ Marshall S. McCrea, III

Co-Chief Executive Officer

February 18, 2022

Marshall S. McCrea, III

(Co-Principal Executive Officer)

(ii)

/s/ Thomas E. Long

Co-Chief Executive Officer

February 18, 2022

Thomas E. Long

(Co-Principal Executive Officer)

(iii)

/s/ Bradford D. Whitehurst

Chief Financial Officer

February 18, 2022

Bradford D. Whitehurst

(Principal Financial Officer)

(iv)

The Managers of Southern Union Panhandle LLC, General Partner of Panhandle Eastern Pipe Line Company, LP

Signature

Title

Date

/s/ Kelcy L. Warren

Manager

February 18, 2022

Kelcy L. Warren

Southern Union Panhandle LLC

/s/ Thomas E. Long

Manager

February 18, 2022

Thomas E. Long

Southern Union Panhandle LLC

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Panhandle Eastern Pipe Line Company, LP and Subsidiaries


Financial Statements and Supplementary Data:			Page:
Report of Independent Registered Public Accounting Firm (PCAOB ID Number 248)			F - 2
Consolidated Balance Sheets			F - 4
Consolidated Statements of Operations and Comprehensive Income			F - 5
Consolidated Statements of Partners’ Capital			F - 6
Consolidated Statements of Cash Flows			F - 7
Notes to Consolidated Financial Statements			F - 8

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors of Southern Union Panhandle LLC and

Member of Panhandle Eastern Pipe Line Company, LP

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Panhandle Eastern Pipe Line Company, LP (a Delaware limited Partnership) and subsidiaries (the “Company”) as of December 31, 2021 and 2020, the related consolidated statements of operations and comprehensive income, changes in partners’ capital, and cash flows for each of the three years in the period ended December 31, 2021, 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 Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.

Basis for opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

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.

Pension and Other Postretirement Benefit Obligations

At December 31, 2021, the Company’s aggregate pension and other postretirement benefit obligations were $98 million and were exceeded by the fair value of the pension and other postretirement plan assets of $218 million, resulting in overfunded pension and other postretirement benefit obligations of $120 million. As explained in Note 5 to the consolidated financial statements, the Company utilized key assumptions to determine the pension and other postretirement benefit obligations. We identified the determination of the pension and other postretirement benefit obligations as a critical audit matter.

The principal consideration for our determination that the pension and other postretirement benefit obligations was a critical audit matter is that there was high estimation uncertainty due to significant judgments with respect to assumptions used to project the pension and other postretirement benefit obligations, including discount rates, future compensation levels, mortality rates, and expected returns on plan assets. Changes in these assumptions could have a significant effect on the pension and other postretirement benefit obligations.

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Our audit procedures related to the determination of the pension and other postretirement benefit obligations included the following procedures, among others:

•We tested management’s process for determining the pension and other postretirement benefit obligations, including evaluating the methodologies used and the appropriateness of significant actuarial assumptions, including discount rates, future compensation levels, mortality rates, and expected returns on plan assets;

•We compared the actuarial assumptions used by management to historical trends and evaluated the reasonableness of changes in the funded status from prior year;

•We tested completeness and accuracy of the underlying data used to determine the pension and other postretirement benefit obligations, including participant data;

•We utilized an internal valuation specialist to evaluate the qualification of the third-party actuarial specialist engaged by the Company as well as the appropriateness and reasonableness of the valuation methods used by management’s third-party actuarial specialist, including the methodology for determining the discount rates, future compensation levels, mortality rates, and the expected returns on plan assets.

/s/ GRANT THORNTON LLP

We have served as the Company’s auditor since 2012.

Houston, Texas

February 18, 2022

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PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)


	December 31,
	2021		2020
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	—
Accounts receivable, net	50		47
Accounts receivable from related companies	8		8
Exchanges receivable	7		6

Inventories	57		86
Other current assets	5		6
Total current assets	127		153

Property, plant and equipment	3,421		3,349
Accumulated depreciation	(813)		(717)
Property, plant and equipment, net	2,608		2,632


Operating lease right-of-use assets	4		5
Other non-current assets, net	192		172



Total assets	$	2,931	$	2,962


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:

Accounts payable	$	39	$	4
Accounts payable to related companies	25		14
Exchanges payable	22		71



Other current liabilities	62		33
Total current liabilities	148		122

Long-term debt, less current maturities	243		245
Note payable to related company	221		550



Non-current operating lease liabilities	3		5
Other non-current liabilities	312		246
Commitments and contingencies
Partners’ capital:
Partners’ capital	2,001		1,803
Accumulated other comprehensive income (loss)	3		(9)
Total partners’ capital	2,004		1,794

Total liabilities and partners’ capital	$	2,931	$	2,962

The accompanying notes are an integral part of these consolidated financial statements.

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PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Dollars in millions)


	Years Ended December 31,
	2021		2020		2019
OPERATING REVENUES:
Transportation and storage of natural gas	$	486	$	528	$	556

Operational gas sales	67		—		—
Other	18		19		22
Total operating revenues	571		547		578
OPERATING EXPENSES:

Operating and maintenance	206		177		193
General and administrative	36		37		30
Depreciation and amortization	104		116		112
Impairment losses	—		—		12
Total operating expenses	346		330		347
OPERATING INCOME	225		217		231
OTHER EXPENSE:
Interest expense, net	(14)		(14)		(17)
Interest expense - related company	(17)		(32)		(25)

Other, net	1		(3)		(2)
Total other expense, net	(30)		(49)		(44)
INCOME BEFORE INCOME TAX BENEFIT	195		168		187
Income tax benefit	(1)		(3)		(402)
NET INCOME	196		171		589



OTHER COMPREHENSIVE INCOME, NET OF TAX:
Actuarial gain relating to postretirement benefits, net of tax amounts of $3, $6, and $4, respectively	14		21		23

COMPREHENSIVE INCOME	$	210	$	192	$	612

The accompanying notes are an integral part of these consolidated financial statements.

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PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(Dollars in millions)


	Partners’ Capital		Accumulated Other Comprehensive Income (Loss)		Total












Balance, December 31, 2018	$	1,409	$	(47)	$	1,362
Net income	589		—		589
Distributions to partners	(375)		—		(375)
Other comprehensive income, net of tax	—		23		23
Other	3		—		3
Balance, December 31, 2019	1,626		(24)		1,602
Net income	171		—		171
Deemed contribution from partners	4		—		4
Other comprehensive income, net of tax	—		21		21
Other	2		(6)		(4)
Balance, December 31, 2020	1,803		(9)		1,794
Net income	196		—		196
Other comprehensive income, net of tax	—		14		14
Other	2		(2)		—
Balance, December 31, 2021	$	2,001	$	3	$	2,004

The accompanying notes are an integral part of these consolidated financial statements.

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PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)


	Years Ended December 31,
	2021		2020		2019
OPERATING ACTIVITIES:
Net income	$	196	$	171	$	589
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	104		116		112
Impairment losses	—		—		12
Deferred income taxes	(2)		(3)		(13)


Amortization of deferred financing fees	(2)		(2)		(4)




PEPL Restructuring income tax benefit	—		—		(428)
Other non-cash	31		9		13
Changes in operating assets and liabilities	76		(25)		(51)
Net cash flows provided by operating activities	403		266		230
INVESTING ACTIVITIES:



Capital expenditures	(74)		(84)		(101)




Net cash flows used in investing activities	(74)		(84)		(101)
FINANCING ACTIVITIES:
Distributions to partners	—		—		(375)

Related company note activity	(329)		(182)		376

Repayment of long-term debt	—		—		(150)



Net cash flows used in financing activities	(329)		(182)		(149)
NET CHANGE IN CASH AND CASH EQUIVALENTS	—		—		(20)
CASH AND CASH EQUIVALENTS, beginning of period	—		—		20
CASH AND CASH EQUIVALENTS, end of period	$	—	$	—	$	—

The accompanying notes are an integral part of these consolidated financial statements.

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PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Tabular dollar amounts are in millions)

1.OPERATIONS AND ORGANIZATION:

On July 1, 2019, ETO executed a series of internal restructuring transactions that resulted in PEPL becoming a subsidiary of a non-corporate subsidiary of ETO (“PEPL Restructuring”). As a result, PEPL’s tax status changed from a disregarded entity for federal income tax purposes wholly owned by a corporate entity to a disregarded entity for federal income tax purposes wholly owned by a limited partnership. In connection with this restructuring, PEPL’s tax sharing agreement with its former corporate parent was terminated, and PEPL reversed all of its existing deferred tax assets and liabilities in July 2019, which resulted in the recognition of a $428 million non-cash benefit in the consolidated statement of operations.

Certain prior period amounts have been reclassified to conform to the 2021 presentation. These reclassifications had no impact on net income, total partners’ capital, or cash flows.

2.ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:

Basis of Presentation. The Company’s consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The consolidated financial statements include the accounts of all majority-owned subsidiaries, after eliminating significant intercompany transactions and balances. Investments in which the Company has significant influence over the operations of the investee are accounted for using the equity method.

The Company is subject to regulation by certain state and federal authorities. The Company has accounting policies which are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The Company does not apply Accounting Standards Codification (“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. If ASC Topic 980 were applied, certain transactions would be reported differently in the Company’s GAAP-basis consolidated financial statements, including, among others, recording of regulatory assets, the capitalization of an equity component of invested funds on regulated capital projects and depreciation differences. The Company periodically reviews its level of discounting and negotiated rate contracts, the length of rate moratoriums and other related factors to determine if ASC Topic 980 should be applied.

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 disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash and Cash Equivalents. Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have original maturities of three months or less. The Company places cash deposits and temporary cash investments with high credit quality financial institutions. At times, cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.

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Non-cash investing and financing activities and supplemental cash flow information are as follows:


	Years Ended December 31,
	2021		2020		2019
Non-cash investing and financing activities:





Settlement of affiliate liability - related company payables	$	—	$	(4)	$	—


Supplemental cash flow information:
Accrued capital expenditures	$	8	$	4	$	11
Cash paid for interest, net of interest capitalized	15		16		23

Cash paid for interest on note payable to related company	18		33		23

Inventories. System natural gas and operating supplies consist of natural gas held for operations and materials and supplies, both of which are carried at the lower of weighted average cost or net realizable value, while natural gas owed back to customers is valued at market. The natural gas held for operations that the Company does not expect to consume in its operations in the next twelve months is reflected in non-current assets.

The following table presents the components of inventory:


	December 31,
	2021		2020

Natural gas (1)	$	36	$	63
Materials and supplies	21		23
	$	57	$	86

(1)Natural gas volumes held for operations at December 31, 2021 and 2020 were 11.4 TBtu and 29.2 TBtu, respectively.

Natural Gas Imbalances. Natural gas imbalances occur as a result of differences in volumes of natural gas received and delivered. The Company records natural gas imbalance in-kind receivables and payables at cost or market. Net imbalances that have reduced system natural gas are valued at the cost basis of the system natural gas, while net imbalances that have increased system natural gas and are owed back to customers are priced, along with the corresponding system natural gas, at market.

Fuel Tracker. The fuel tracker is the cumulative balance of compressor fuel volumes owed to the Company by its customers or owed by the Company to its customers. The customers, pursuant to each pipeline’s tariff and related contracts, provide all compressor fuel to the pipeline based on specified percentages of the customer’s natural gas volumes delivered into the pipeline. The percentages are designed to match the actual natural gas consumed in moving the natural gas through the pipeline facilities, with any difference between the volumes provided versus volumes consumed reflected in the fuel tracker. The tariff of Trunkline, in conjunction with the customers’ contractual obligations, allows the Company to record an asset and direct bill customers for any fuel ultimately under-recovered. The other FERC-regulated PEPL entities record an expense when fuel is under-recovered or record a credit to expense to the extent any under-recovered prior period balances are subsequently recouped as they do not have such explicit billing rights specified in their tariffs. Liability accounts are maintained for net volumes of compressor fuel natural gas owed to customers collectively. The pipelines’ fuel reimbursement is in-kind and non-discountable. As of December 31, 2021 and 2020, the Company had a fuel tracker balance of $15 million and $2 million, respectively, included in other current liabilities.

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Property, Plant and Equipment.

The following table presents the components of property, plant and equipment:


		December 31,
	Lives in Years	2021		2020
Land and improvements		$	4	$	4
Buildings and improvements	6 – 46	195		197
Pipelines and equipment	5 – 46	2,684		2,631
Natural gas storage facilities	26 – 46	368		360





Other	3 – 21	145		142
Construction work in progress		25		15
Property, plant and equipment		3,421		3,349
Accumulated depreciation and amortization		(813)		(717)
Property, plant and equipment, net		$	2,608	$	2,632

Additions. Ongoing additions of property, plant and equipment are stated at cost. The Company capitalizes all construction-related direct labor and material costs, as well as indirect construction costs. Such indirect construction costs primarily include capitalized interest costs and labor and related costs of departments associated with supporting construction activities. The indirect capitalized labor and related costs are largely based upon results of periodic time studies or management reviews of time allocations, which provide an estimate of time spent supporting construction projects. The cost of replacements and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs and replacements of minor property, plant and equipment items is charged to expense as incurred.

Retirements. When ordinary retirements of property, plant and equipment occur, the original cost less salvage value is removed by a charge to accumulated depreciation and amortization, with no gain or loss recorded. When entire regulated operating units of property, plant and equipment are retired or sold, the original cost less salvage value and related accumulated depreciation and amortization accounts are removed, with any resulting gain or loss recorded in earnings.

Depreciation. The Company computes depreciation expense using the straight-line method.

Interest Cost Capitalized. The Company capitalizes interest on certain qualifying assets that are undergoing activities to prepare them for their intended use. Interest costs incurred during the construction period are capitalized and amortized over the life of the assets. For the years ended December 31, 2021 and 2020, the Company recognized no capitalized interest. For the year ended December 31, 2019 the Company recognized capitalized interest of $2 million.

Related Party Transactions. Related party expenses primarily include payments for services provided by Energy Transfer and other affiliates, as well as interest expense on a note payable to Energy Transfer.

Environmental Expenditures. Environmental expenditures that relate to an existing condition caused by past operations that do not contribute to current or future revenue generation are expensed. Environmental expenditures relating to current or future revenues are expensed or capitalized as appropriate. Liabilities are recorded when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. Remediation obligations are not discounted because the timing of future cash flow streams is not predictable.

Other Current Liabilities. Other current liabilities consisted of the following:


	December 31,
	2021		2020
Deposits from customers	$	14	$	8
Accrued expenses	34		13
Accrued capital expenditures	8		4


Other	6		8
Total other current liabilities	$	62	$	33

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Other Non-Current Liabilities. Other non-current liabilities consisted of the following:


	December 31,
	2021		2020
Pension liability	$	110	$	97
ARO	56		37
Provision for rate refunds (1)	57		24
Other	89		88
Total other non-current liabilities	$	312	$	246

(1) Provision for rate refunds represents future amounts to be settled with the Company’s shippers under FERC regulation.

Revenues. The Company’s revenues from transportation and storage of natural gas are based on capacity reservation charges and, to a lesser extent, commodity usage charges. Reservation revenues are based on contracted rates and capacity reserved by the customers and are recognized monthly. Revenues from commodity usage charges are also recognized monthly, based on the volumes received from or delivered for the customer, based on the tariff, with any differences in volumes received and delivered resulting in an imbalance. Volume imbalances generally are settled in-kind with no impact on revenues, with the exception of Trunkline, which settles certain imbalances in cash pursuant to its tariff, and records gains and losses on such cashout sales as a component of revenue, to the extent not owed back to customers. Because the Company is subject to FERC regulation, revenues collected during the pendency of a rate proceeding may be required by FERC to be refunded in the final order. The Company establishes reserves for such potential refunds, as appropriate.

Accounts Receivable and Allowance for Expected Credit Losses. The Company has a large number of customers in the electric and gas utility industries as well as oil and natural gas producers and municipalities. The large number of customers in these energy segments may impact our overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. The Company manages trade credit risk to mitigate credit losses and exposure to uncollectible trade receivables. Prospective and existing customers are reviewed regularly for creditworthiness based upon pre-established standards consistent with FERC filed tariffs 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.

The Company establishes an allowance for expected credit losses on trade receivables based on the expected ultimate recovery of these receivables and considers 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. Increases 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 the Company’s efforts have been unsuccessful in collecting the amount due.

The allowance for expected credit losses was not material as of December 31, 2021 and 2020.

The following table presents the relative contribution to the Company’s total operating revenue from operations of each customer that comprised at least 10% of its operating revenues:


	Years Ended December 31,
	2021		2020		2019
Customer A	12	%	12	%	10	%
Customer B	17		17		16
Other top 10 customers	29		31		31
Remaining customers	42		40		43
Total percentage	100	%	100	%	100	%

Accumulated Other Comprehensive Income (Loss). The main components of accumulated other comprehensive income (loss) are net actuarial gain and prior service costs on pension and other postretirement benefit plans.

Retirement Benefits. The Company 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

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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 other comprehensive income in partners’ capital in the year in which the change occurs.

Fair Value Measurement. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about nonperformance risk, which is primarily comprised of credit risk (both the Company’s own credit risk and counterparty credit risk) and the risks inherent in the inputs to any applicable valuation techniques. The Company places more weight on current market information concerning credit risk (e.g. current credit default swap rates) as opposed to historical information (e.g. historical default probabilities and credit ratings). These inputs can be readily observable, market corroborated, or generally unobservable. The Company endeavors to utilize the best available information, including valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. A three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value, is as follows:

•Level 1 – Observable inputs such as quoted prices in active markets for identical assets or liabilities;

•Level 2 – Observable inputs such as: (i) quoted prices for similar assets or liabilities in active markets; (ii) quoted prices for identical or similar assets or liabilities in markets that are not active and do not require significant adjustment based on unobservable inputs; or (iii) valuations based on pricing models, discounted cash flow methodologies or similar techniques where significant inputs (e.g., interest rates, yield curves, etc.) are derived principally from observable market data, or can be corroborated by observable market data, for substantially the full term of the assets or liabilities; and

•Level 3 – Unobservable inputs, including valuations based on pricing models, discounted cash flow methodologies or similar techniques where at least one significant model assumption or input is unobservable. Unobservable inputs are used to the extent that observable inputs are not available and reflect the Company’s own assumptions about the assumptions market participants would use in pricing the assets or liabilities. Unobservable inputs are based on the best information available in the circumstances, which might include the Company’s own data.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of these assets and liabilities and their placement within the fair value hierarchy.

The Company had $39 million and $34 million available for sale securities, included in other non-current assets, at December 31, 2021 and 2020, respectively. At December 31, 2021, $26 million in equity securities were valued at Level 1 and $13 million in fixed income securities were valued at Level 2. At December 31, 2020, $22 million in equity securities were valued at Level 1 and $12 million in fixed income securities were valued at Level 2. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value.

Asset Retirement Obligations. Legal obligations associated with the retirement of long-lived assets are recorded at fair value at the time the obligations are incurred, if a reasonable estimate of fair value can be made. Present value techniques are used which reflect assumptions such as removal and remediation costs, inflation, and profit margins that third parties would demand to settle the amount of the future obligation. The Company did not include a market risk premium for unforeseeable circumstances in its fair value estimates because such a premium could not be reliably estimated. Upon initial recognition of the liability, costs are capitalized as a part of the long-lived asset and allocated to expense over the useful life of the related asset. The liability is accreted to its present value each period with accretion being recorded to operating expense with a corresponding increase in the carrying amount of the liability. To the extent the Company is permitted to collect and has reflected in its financials amounts previously collected from customers and expensed, such amounts serve to reduce what would be reflected as capitalized costs at the initial establishment of an ARO.

Income Taxes. Income taxes are accounted for 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.

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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 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.

Commitments and Contingencies. The Company is subject to proceedings, lawsuits and other claims related to environmental and other matters. Accounting for contingencies requires significant judgment by management regarding the estimated probabilities and ranges of exposure to potential liability.

3.RELATED PARTY TRANSACTIONS:

Accounts receivable from related companies reflected on the consolidated balance sheets primarily related to services provided to Energy Transfer and other affiliates. Accounts payable to related companies reflected on the consolidated balance sheets related to various services provided by Energy Transfer and other affiliates.

The following table provides a summary of related party activity included in our consolidated statements of operations:


	Years Ended December 31,
	2021		2020		2019
Operating revenues	$	90	$	90	$	95

Operating and maintenance	19		15		27
General and administrative	25		23		18


Interest expense — related company	17		32		25

The Company settled affiliate payables with a subsidiary of Energy Transfer through non-cash contributions during the year ended December 31, 2020 for $4 million.

As of December 31, 2021 and 2020, the Company had $221 million and $550 million, respectively, outstanding under a note payable to Energy Transfer. The note payable accrues interest monthly with an annual interest rate of 4.898% as of December 31, 2021 and matures on July 31, 2027.

4.DEBT OBLIGATIONS:

The following table sets forth the debt obligations of the Company:


	December 31,
	2021		2020



7.60% Senior Notes due February 1, 2024	$	82	$	82
7.00% Senior Notes due July 15, 2029	66		66
8.25% Senior Notes due November 15, 2029	33		33
Floating Rate Junior Subordinated Notes due November 1, 2066	54		54

Unamortized fair value adjustments	8		10
Total long-term debt outstanding	$	243	$	245

Based on the estimated borrowing rates currently available to the Company and its subsidiaries for loans with similar terms and average maturities, the aggregate fair value of the Company’s consolidated debt obligations at December 31, 2021 and 2020 was $253 million and $256 million, respectively. The fair value of the Company’s consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

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As of December 31, 2021, the Company has scheduled long-term debt principal payments as follows:


Years Ending December 31,
2022	$	—
2023	—
2024	82
2025	—
2026	—
Thereafter	153
Total	$	235

Floating Rate Junior Subordinated Notes

The interest rate on PEPL’s junior subordinated notes due 2066 is a variable rate based upon the three-month London Interbank Offered Rate plus 3.0175%. The balance of the floating rate junior subordinated notes was $54 million at December 31, 2021 and 2020 at an effective interest rate of 3.149% and 3.232%, respectively.

Compliance With Our Covenants

The Company’s notes are subject to certain requirements, such as the maintenance of a fixed charge coverage ratio and a leverage ratio, which if not maintained, restrict the ability of the Company to make certain payments and impose limitations on the ability of the Company to subject its property to liens. Other covenants impose limitations on restricted payments, including dividends and loans to related companies, and additional indebtedness. As of December 31, 2021, the Company is in compliance with these covenants.

The Company will continue to opportunistically evaluate alternatives for funding its debt repayment obligations. Alternatives include, but are not limited to, refinancing of amounts due with new senior notes, a term loan facility or a loan provided by Energy Transfer or other affiliates.

5. RETIREMENT BENEFITS:

Postretirement Benefit Plans

Affiliates of the Company previously offered postretirement health care and life insurance benefit plans (other postretirement plans) that covered substantially all employees. Participation in the plan was previously frozen and medical benefits were no longer offered, except for coverage that has been extended to a closed group of former employees based on certain criteria.

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Obligations and Funded Status

Other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services. The following tables contain information at the dates indicated about the obligations and funded status of the Company’s other postretirement plans.


	December 31,
	2021		2020
Change in benefit obligation:
Benefit obligation at beginning of period	$	98	$	91
Service cost	1		1
Interest cost	2		3

Actuarial loss	1		7
Benefits paid, net	(4)		(4)


Benefit obligation at end of period	$	98	$	98
Change in plan assets:
Fair value of plan assets at beginning of period	$	191	$	169
Return on plan assets and other	23		18
Employer contributions	8		8
Benefits paid, net	(4)		(4)

Fair value of plan assets at end of period	$	218	$	191

Amount overfunded at end of period (1)	$	120	$	93

Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial gain	$	(21)	$	(8)
Prior service cost	18		19
	$	(3)	$	11

(1)Recorded as a non-current asset in the consolidated balance sheets with a non-current pension liability for overfunded amounts owed to the Company’s shippers.

Components of Net Periodic Benefit Cost

The following tables set forth the components of net periodic benefit cost of the Company’s postretirement benefit plan for the periods presented:


	Years Ended December 31,
	2021		2020		2019
Service cost	$	1	$	1	$	1
Interest cost	2		3		3
Expected return on plan assets	(10)		(9)		(7)
Prior service credit amortization	1		18		24


Net periodic benefit cost	$	(6)	$	13	$	21

Services cost is recorded within general and administrative expense while non-service cost components are recorded within other, net in our consolidated statements of operations.

The estimated prior service cost for other postretirement plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost during 2022 is $1 million.

Assumptions. The weighted-average discount rate used in determining benefit obligations was 2.50% and 2.16% at December 31, 2021 and 2020, respectively.

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The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below:


	Years Ended December 31,
	2021		2020		2019
Discount rate	2.18	%	3.00	%	4.05	%
Expected return on assets:
Tax exempt accounts	7.00	%	7.00	%	7.00	%
Taxable accounts	4.75	%	4.75	%	4.75	%

The Company employs a building block approach in determining the expected long-term rate of return on the plans’ assets with proper consideration for diversification and rebalancing. Historical markets are studied and long-term historical relationships between equities and fixed-income are preserved consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. 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 check for reasonableness and appropriateness.

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 table below:


	December 31,
	2021		2020
Health care cost trend rate	8.10	%	8.05	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.90	%	4.65	%
Year that the rate reaches the ultimate trend rate	2029		2028

Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one-percentage-point change in assumed health care cost trend rates would have no material effect on accumulated postretirement benefit obligation or on total of annual service and interest cost components.

Plan Assets. The Company’s overall investment strategy is to maintain an appropriate balance of actively managed investments while maintaining a high standard of portfolio quality and achieving proper diversification. To achieve diversity within its other postretirement plan asset portfolio, the Company has targeted the following asset allocations: equity of 25% to 30% and fixed income of 65% to 70%. These target allocations are monitored by the Investment Committee of Energy Transfer’s Board of Directors in conjunction with an external investment advisor. On occasion, the asset allocations may fluctuate as compared to these guidelines as a result of Investment Committee actions.

The fair value of the Company’s other postretirement plan assets at the dates indicated by asset category is as follows:


	December 31,
	2021		2020
Cash and cash equivalents	$	14	$	11
Total Market Index Fund (1)	111		87
Total International Index Fund(2)	19		18
U.S. Bond Index Fund (3)	74		75
Total	$	218	$	191

(1)The fund invests primarily in common stocks included in the Dow Jones U.S. Total Stock Market Index. As of December 31, 2021, this fund was invested 100% in domestic equities.

(2)The fund invests primarily in both the securities and in depository receipts representing securities included in the MSCI All Country World Index. As of December 31, 2021, this fund was invested 97% in foreign equities and 3% in domestic equities.

(3)The fund invests primarily in bonds included in the Bloomberg Barclays U.S. Aggregate Bond Index. As of December 31, 2021, this fund was invested 40% in U.S. Treasury, 27% in mortgage-backed securities, 25% in corporations and 8% in other.

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The Total Market Index Fund and Total International Index Fund assets are classified as Level 1 assets within the fair value hierarchy. The U.S. Bond Index Fund is classified as Level 2 assets within the fair value hierarchy.

Contributions. The Company expects to make contributions of $8 million to its other postretirement plans in 2022 and annually thereafter until modified by rate case proceedings.

Benefit Payments. The Company’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 table below.


Years	Expected Benefit Payments
2022	$	6
2023	6
2024	6
2025	6
2026	6
2027-2031	26

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 plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D. The Company does not expect to receive any Medicare Part D subsidies in any future periods.

Defined Contribution Plan

The Company participates in Energy Transfer’s defined contribution savings plan (“Savings Plan”) that is available to virtually all employees. The Company provided matching contributions of 100% of the first 5% of the participant’s compensation paid into the Savings Plan. The Company contributed $2 million, $1 million and $2 million to the Savings Plan during the years ended December 31, 2021, 2020, and 2019, respectively.

In addition, the Company provides a 3% discretionary profit sharing contribution to eligible employees with annual base compensation below a specific threshold. Company contributions are 100% vested after five years of continuous service. The Company made discretionary profit sharing contributions of $1 million, $0.5 million and $1 million for the years ended December 31, 2021, 2020, and 2019, respectively.

As a result of the economic conditions in 2020, effective June 8, 2020, the Company ceased employer matching and profit sharing contributions through December 31, 2020. The Company resumed all such contributions in 2021.

6.INCOME TAXES:

The following table provides a summary of the current and deferred components of income tax benefit for the year ended December 31, 2019. The years ended December 31, 2021 and 2020 are excluded from the table below, because income tax expense is no longer significant to the Company subsequent to the PEPL Restructuring in 2019.


	Year Ended December 31,
	2019
Current expense:
Federal	$	31
State	8
Total	39
Deferred benefit:
Federal	$	(349)
State	(92)
Total	(441)
Total income tax benefit	$	(402)

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The differences between the Company’s effective income tax rate and the United States federal income tax statutory rate are primarily due to state income taxes and, subsequent to the PEPL Restructuring in 2019, due to partnership earnings not subject to tax. In addition, for the year ended December 31, 2019 income tax expense was also impacted by a benefit of $428 million due to the change in tax status associated with the PEPL Restructuring.

The Company is no longer subject to examination by the Internal Revenue Service and most state jurisdictions for 2013 and prior years. However, the Company is currently under state income tax examination for its 2013 and 2014 years.

7.ASSET RETIREMENT OBLIGATIONS:

The Company’s recorded asset retirement obligations are primarily related to owned natural gas storage wells and offshore lines and platforms. At the end of the useful life of these underlying assets, the Company is legally or contractually required to abandon in place or remove the asset. Although a number of other onshore assets in the Company’s system are subject to agreements or regulations that give rise to an ARO upon the Company’s 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.

Individual component assets have been and will continue to be replaced, but the pipeline system 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 foreseeable future. The Company has in place a rigorous repair and maintenance program that keeps the pipeline system in good working order. Therefore, although some of the individual assets may be replaced, the pipeline system itself will remain intact indefinitely.

The Company recorded AROs related to (i) retiring natural gas storage wells, (ii) retiring offshore platforms and lines and (iii) removing asbestos. In addition, the Company had $39 million and $34 million legally restricted for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2021 and 2020, respectively; these restricted funds did not include any material amounts of restricted cash.

The following table is a reconciliation of the carrying amount of the ARO liability for the periods presented. Changes in assumptions regarding the timing, amount, and probabilities associated with the expected cash flows, as well as the difference in actual versus estimated costs, may result in a change in the amount of the liability recognized.


	Years Ended December 31,
	2021		2020		2019
Beginning balance	$	37	$	35	$	26

Revisions	17		—		9
Settled	—		—		(2)

Accretion expense	2		2		2
Ending balance	$	56	$	37	$	35

8.REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:

Contingent Residual Support Agreement with Energy Transfer

Under a contingent residual support agreement with Energy Transfer (as successor by merger to ETO) and Citrus ETP Finance LLC, the Company provides contingent, residual support to Citrus ETP Finance LLC (on a non-recourse basis to the Company) with respect to Citrus ETP Finance LLC’s obligations to Energy Transfer to support the payment of certain Energy Transfer senior notes. As of December 31, 2021, $1 billion in principal amount of such supported Energy Transfer senior notes remains outstanding.

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FERC Proceedings

Environmental Matters

The Company’s operations are subject to federal, state and local laws, rules and regulations regarding water quality, hazardous and solid waste management, air quality control and other environmental matters. These laws, rules and regulations require the Company to conduct its operations in a specified manner and to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with environmental laws, rules and regulations may expose the Company to significant fines, penalties and/or interruptions in operations. The Company’s environmental policies and procedures are designed to achieve compliance with such applicable laws and regulations. These evolving laws and regulations and claims for damages to property, employees, other persons and the environment resulting from current or past operations may result in significant expenditures and liabilities in the future. The Company engages in a process of updating and revising its procedures for the ongoing evaluation of its operations to identify potential environmental exposures and enhance compliance with regulatory requirements.

The Company is responsible for environmental remediation at certain sites on its natural gas transmission systems for contamination resulting from the past use of lubricants containing polychlorinated biphenyls (“PCBs”) in compressed air systems; the past use of paints containing PCBs; and the prior use of wastewater collection facilities and other on-site disposal areas. The Company has implemented a program to remediate such contamination. The primary remaining remediation activity on the PEPL systems is associated with past use of paints containing PCBs or PCB impacts to equipment surfaces and to a building at one location. The PCB assessments are ongoing and the related estimated remediation costs are subject to further change. Other remediation typically involves the management of contaminated soils and may involve remediation of groundwater. Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements, complexity and sharing of responsibility. The ultimate liability and total costs associated with these sites will depend upon many factors. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, the Company could potentially be held responsible for contamination caused by other parties. In some instances, the Company may share liability associated with contamination with other potentially responsible parties. The Company may also benefit from contractual indemnities that cover some or all of the cleanup costs. These sites are generally managed in the normal course of business or operations.

The Company’s environmental remediation activities are undertaken in cooperation with and under the oversight of appropriate regulatory agencies, enabling the Company under certain circumstances to take advantage of various voluntary cleanup programs in order to perform the remediation in the most effective and efficient manner.

The Company had accrued $1 million in non-current liabilities as of December 31, 2021 and 2020 to cover environmental remediation actions where management believes a loss is probable and reasonably estimable. The Company is not able to estimate the possible loss or range of loss in excess of amounts accrued. The Company does not have any material environmental remediation matters assessed as reasonably possible.

Liabilities for Litigation and Other Claims

The Company records accrued liabilities for litigation and other claim costs when management believes a loss is probable and reasonably estimable. When management believes there is at least a reasonable possibility that a material loss or an additional material loss may have been incurred, the Company discloses (i) an estimate of the possible loss or range of loss in excess of the amount accrued; or (ii) a statement that such an estimate cannot be made. As of December 31, 2021 and 2020, the Company’s consolidated balance sheet reflected litigation and other claim-related accrued liabilities of $73 million and $41 million, respectively. The Company does not have any material litigation or other claim contingency matters assessed as probable or reasonably possible that would require disclosure in the financial statements.

Other Commitments and Contingencies

The Company is subject to the laws and regulations of states and other jurisdictions concerning the identification, reporting and escheatment (the transfer of property to the state) of unclaimed or abandoned funds, and is subject to audit and

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examination for compliance with these requirements. The Company is currently being examined by a third-party auditor on behalf of nine states for compliance with unclaimed property laws.

9.LEASES:

The Company leases office space, land, and equipment under non-cancelable operating leases whose initial terms are typically 5 to 10 years, with some real estate leases having terms of 30 years or more, along with options that permit renewals for additional periods. At contract inception, 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 Accounting Standards Codification (“ASC”) Topic 842.

At present, the majority of the Company’s active leases are classified as operating in accordance with ASC Topic 842. Balances related to operating leases are included in operating lease ROU assets, other current liabilities and operating lease liabilities in our consolidated balance sheet. Finance leases represent a small portion of the active lease agreements and are included in property and equipment, other current liabilities, and other non-current liabilities in our consolidated balance sheet. The ROU assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the obligation of the Company 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 Company, and lease extensions 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 Company does not have leases that include options to purchase or automatic transfer of ownership of the leased property to the Company. 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, since many of our leases do not provide an implicit rate, the Company 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 Company 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.

For the years ended December 31, 2021 and 2020, the Company recognized $0.2 million of short-term lease cost, which is reflected in operating and maintenance in the accompanying consolidated statement of operations.

The weighted-average remaining lease terms and weighted-average discount rate as of December 31, 2021 were as follows:



Weighted-average remaining lease term (years)
Operating leases			13
Weighted-average discount rate (%)
Operating leases			4%

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Maturities of operating lease liabilities as of December 31, 2021 are as follows:


	Operating leases

2022	$	—
2023	1
2024	1
2025	1
2026	1
Thereafter	1
Total lease payments	5
Less: present value discount	1
Present value of lease liabilities	$	4

10.REVENUE:

Contract Balances with Customers

The Company 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 Company 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 Company is contractually allowed to bill for such services. As of December 31, 2021 and 2020, no contract assets have been recognized.

The Company recognizes a contract liability if the customer's payment of consideration precedes the Company’s fulfillment of the performance obligations. As of December 31, 2021 and 2020, no contract liabilities have been recognized.

Performance Obligation

At contract inception, the Company 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 Company considers all the goods or services promised in the contract, whether explicitly stated or implied based on customary business practices. 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 table below.

As of December 31, 2021, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations is approximately $2.27 billion, and the Company expects to recognize this amount as revenue within the time bands illustrated below:


	Years Ending December 31,
	2022		2023		2024		Thereafter		Total
Revenue expected to be recognized on contracts with customers existing as of December 31, 2021	$	421	$	370	$	256	$	1,219	$	2,266

Practical Expedients Utilized by the Company

The Company elected the following practical expedients in accordance with Topic 606:

•Right to invoice - The Company elected to utilize an output method to recognize revenue that is based on the amount to which the Company has a right to invoice a customer for services performed to date, if that amount corresponds

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directly with the value provided to the customer for the related performance or its obligation completed to date. As such, the Company recognized revenue in the amount to which it had the right to invoice customers.

•Significant financing component - The Company elected not to adjust the promised amount of consideration for the effects of significant financing component if the Company 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 Company 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.

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Document

Exhibit 31.1

CERTIFICATION OF CO-CHIEF EXECUTIVE OFFICER

PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Marshall S. McCrea, III, certify that:

1.I have reviewed this annual report on Form 10-K of Panhandle Eastern Pipe Line Company, LP (the “registrant”);

2.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;

3.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;

4.The registrant’s other certifying officer and I are 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.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our 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;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our 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

d.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.The registrant’s other certifying officer and I have disclosed, based on our 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.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

b.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 18, 2022


/s/ Marshall S. McCrea, III
Marshall S. McCrea, III
Co-Chief Executive Officer

Document

Exhibit 31.2

CERTIFICATION OF CO-CHIEF EXECUTIVE OFFICER

PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Thomas E. Long, certify that:

1.I have reviewed this annual report on Form 10-K of Panhandle Eastern Pipe Line Company, LP (the “registrant”);

b.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 18, 2022


/s/ Thomas E. Long
Thomas E. Long
Co-Chief Executive Officer

Document

Exhibit 31.3

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Bradford D. Whitehurst, certify that:

1.I have reviewed this annual report on Form 10-K of Panhandle Eastern Pipe Line Company, LP (the “registrant”);

b.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 18, 2022


/s/ Bradford D. Whitehurst
Bradford D. Whitehurst
Chief Financial Officer

Document

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Panhandle Eastern Pipe Line Company, LP (the “Company”) on Form 10-K for the year ended December 31, 2021 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 Company.

Date: February 18, 2022


/s/ Marshall S. McCrea, III
Marshall S. McCrea, III
Co-Chief Executive Officer

*A signed original of this written statement required by 18 U.S.C. Section 1350 has been provided to and will be retained by Panhandle Eastern Pipe Line Company, LP.

Document

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Panhandle Eastern Pipe Line Company, LP (the “Company”) on Form 10-K for the year ended December 31, 2021 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 Company.

Date: February 18, 2022


/s/ Thomas E. Long
Thomas E. Long
Co-Chief Executive Officer

*A signed original of this written statement required by 18 U.S.C. Section 1350 has been provided to and will be retained by Panhandle Eastern Pipe Line Company, LP.

Document

Exhibit 32.3

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Panhandle Eastern Pipe Line Company, LP (the “Company”) on Form 10-K for the year ended December 31, 2021 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Bradford D. Whitehurst, 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 Company.

Date: February 18, 2022


/s/ Bradford D. Whitehurst
Bradford D. Whitehurst
Chief Financial Officer

*A signed original of this written statement required by 18 U.S.C. Section 1350 has been provided to and will be retained by Panhandle Eastern Pipe Line Company, LP.