EDGAR 10-K Filing

Company CIK: 76063
Filing Year: 2022
Filename: 76063_10-K_2022_0000076063-22-000010.json

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ITEM 1. BUSINESS
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
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.
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
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.

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ITEM 1A. RISK FACTORS
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
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.
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
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
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.
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
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.
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 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
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
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.
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
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.
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;
•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.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

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ITEM 2. PROPERTIES
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.

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ITEM 3. LEGAL PROCEEDINGS
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.”

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURE
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
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.

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. [RESERVED]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
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.”
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.
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.”

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements starting on page of this report are incorporated by reference.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

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ITEM 9A. CONTROLS AND PROCEDURES
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.

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
None.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
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.

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ITEM 11. EXECUTIVE COMPENSATION
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.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
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.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
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.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
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.
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

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
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.
(2)Financial Statement Schedules - None.
(3)Exhibits - see Index to Exhibits set forth on page 28.