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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)



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

For the fiscal year ended December 31, 2018



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

For the transition period from to

Commission File No. 1-2921

PANHANDLE EASTERN PIPE LINE COMPANY, LP

(Exact name of registrant as specified in its charter)



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

8111 Westchester Drive, Suite 600, Dallas, Texas 75225

(Address of principle executive offices) (zip code)

(214) 981-0700

(Registrant’s telephone number, including area code)

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer x Smaller reporting company ¨ Emerging growth company ¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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

Panhandle Eastern Pipe Line Company, LP meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format. Items 1, 2 and 7 have been reduced and Items 6, 10, 11, 12 and 13 have been omitted in accordance with Instruction I.

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PANHANDLE EASTERN PIPE LINE COMPANY, LP

TABLE OF CONTENTS



		Page
PART I
ITEM 1.	BUSINESS	1
ITEM 1A.	RISK FACTORS	4
ITEM 1B.	UNRESOLVED STAFF COMMENTS	15
ITEM 2.	PROPERTIES	15
ITEM 3.	LEGAL PROCEEDINGS	15
ITEM 4.	MINE SAFETY DISCLOSURES	15
PART II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	16
ITEM 6.	SELECTED FINANCIAL DATA	16
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	16
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	20
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	20
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	20
ITEM 9A.	CONTROLS AND PROCEDURES	20
ITEM 9B.	OTHER INFORMATION	21
PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	22
ITEM 11.	EXECUTIVE COMPENSATION	22
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS	22
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	22
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	22
PART IV
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	24
ITEM 16.	FORM 10-K SUMMARY	24
	SIGNATURES	27

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Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by Panhandle Eastern Pipe Line Company, LP, and its subsidiaries (“PEPL” or the “Company”) in periodic press releases and some oral statements of Panhandle officials during presentations about the Company, include forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “continue,” “believe,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Company believes such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such assumptions, expectations or projections will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Company’s actual results may vary materially from those anticipated, projected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Part I – Item 1A. Risk Factors” included in this annual report.

Definitions

The following is a list of certain acronyms and terms generally used in the energy industry and throughout this annual report on Form 10-K are defined as follows:



/d		per day

ARO		Asset retirement obligation

Bcf		Billion cubic feet

EPA		United States Environmental Protection Agency

Exchange Act		Securities Exchange Act of 1934

FERC		Federal Energy Regulatory Commission

GAAP		Accounting principles generally accepted in the United States of America

LIBOR		London Interbank Offered Rate

NGL		Natural gas liquids

PCBs		Polychlorinated biphenyls

PEI		PEI Power Corporation

PRPs		Potentially responsible parties

Sea Robin		Sea Robin Pipeline Company, LLC

SEC		United States Securities and Exchange Commission

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

TBtu		Trillion British thermal units

Trunkline		Trunkline Gas Company, LLC

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PART I

ITEM 1. BUSINESS

Overview

Panhandle Eastern Pipe Line Company, LP (“PEPL”) and its subsidiaries (collectively, the “Company”) primarily operate 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 and storage of natural gas and are subject to the rules and regulations of the FERC. The Company’s subsidiaries are Trunkline, Sea Robin and Southwest Gas.

In October 2018, Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. completed the merger of ETO with a wholly-owned subsidiary of ET in a unit-for-unit exchange (the “Energy Transfer Merger”). Following the closing of the Energy Transfer Merger, Energy Transfer Equity, L.P. changed its name to “Energy Transfer LP” and its common units began trading on the New York Stock Exchange under the “ET” ticker symbol on Friday, October 19, 2018. In addition, Energy Transfer Partners, L.P. changed its name to “Energy Transfer Operating, L.P.” For purposes of maintaining clarity, the following references are used herein:


•	References to “ETO” refer to the entity named Energy Transfer Partners, L.P. prior to the close of the Energy Transfer Merger and Energy Transfer Operating, L.P. subsequent to the close of the Energy Transfer Merger; and


•	References to “ET” refer to the entity named Energy Transfer Equity, L.P. prior to the close of the Energy Transfer Merger and Energy Transfer LP subsequent to the close of the Energy Transfer Merger.

Southern Union Panhandle LLC, an indirect wholly-owned subsidiary of ETO, owns a 1% general partner interest in PEPL and ETO indirectly owns a 99% limited partner interest in PEPL.

Asset Overview

The Company owns and operates a large natural gas open-access interstate pipeline network. The pipeline network, consisting of the PEPL, 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 90% of total revenues in 2018.

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



	Years Ended December 31,
	2018	2017
PEPL transportation	845	636
Trunkline transportation	685	525
Sea Robin transportation	89	73

The following table provides a summary of certain statistical information associated with the Company at December 31, 2018:



Approximate Miles of Pipelines
PEPL		6,000
Trunkline		2,000
Sea Robin		1,000
Peak Day Delivery Capacity (Bcf/d)
PEPL		2.8
Trunkline		0.9
Sea Robin		2.0
Underground Storage Capacity-Owned (Bcf)		71.1
Underground Storage Capacity-Leased (Bcf)		18.0
Weighted Average Remaining Life in Years of Firm Transportation Contracts ⁽¹⁾
PEPL		5.7
Trunkline		7.8
Sea Robin ⁽²⁾		N/A
Weighted Average Remaining Life in Years of Firm Storage Contracts ⁽¹⁾
PEPL		5.8
Trunkline		3.6


⁽¹⁾	Weighted by firm capacity volumes.


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

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 PEPL, 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. PEPL, 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 and the Pipeline Safety Improvement Act of 2002, which regulate the safety of natural gas pipelines.

Effective January 2018, the 2017 Tax 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

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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 because it is non-binding policy and parties will have the opportunity to address the policy as applied in future cases. 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. In light of the rehearing order, the impacts of the FERC’s policy on the treatment of income taxes may have on the rates the Company can charge for the FERC regulated transportation services are unknown at this time.

The FERC also issued a Notice of Inquiry (“2017 Tax Law NOI”) requesting comments on the effect of the Tax Act on FERC jurisdictional rates. The 2017 Tax Law NOI states that of particular interest to the FERC is whether, and if so how, the FERC should address changes relating to accumulated deferred income taxes and bonus depreciation. Comments in response to the 2017 Tax Law NOI were due on or before May 21, 2018. It is unknown at this time what actions that the FERC will take, if any, following receipt of responses to the 2017 Tax Law NOI and any potential impacts from final rules or policy statements issued following the 2017 Tax Law NOI on the rates the Company can charge for FERC regulated transportation services.

Included in the March 15, 2018 proposals is a Notice of Proposed Rulemaking (“NOPR”) proposing rules for implementation of the Revised Policy Statement and the corporate income tax rate reduction with respect to natural gas pipeline rates. On July 18, 2018, the FERC issued a Final Rule adopting procedures that are generally the same as proposed in the NOPR with a few clarifications and modifications. With limited exceptions, the Final Rule requires all FERC regulated natural gas pipelines that have cost-based rates for service to make a one-time Form No. 501-G filing providing certain financial information and to make an election on how to treat its existing rates. The Final Rule suggests that this information will allow the FERC and other stakeholders to evaluate the impacts of the Tax Act and the Revised Policy Statement on each individual pipeline’s rates. The Final Rule also requires that each FERC regulated natural gas pipeline select one of four options: file a limited Natural Gas Act (“NGA”) Section 4 filing reducing its rates only as required related to the Tax Act and the Revised Policy Statement, commit to filing a general NGA Section 4 rate case in the near future, file a statement explaining why an adjustment to rates is not needed, or take no other action. For the limited NGA Section 4 option, the FERC clarified that, notwithstanding the Revised Policy Statement, a pipeline organized as a master limited partnership does not need to eliminate its income tax allowance but, instead, can reduce its rates to reflect the reduction in the maximum corporate tax rate. Trunkline and PEPL filed their respective FERC Form No. 501-Gs on October 11, 2018. Southwest Gas filed its FERC Form No. 501-G on November 8, 2018. Pursuant to an option in the Final Rule, Sea Robin filed a general section 4 rate case on November 30, 2018 in lieu of filing a FERC Form 501-G which was due on December 6, 2018. By order issued January 16, 2019, the FERC initiated a review of PEPL’s existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged by PEPL are just and reasonable and set the matter for hearing. PEPL must file a cost and revenue study on or before April 1, 2019. An initial decision is expected to be issued in the first quarter of 2020. By order issued February 19, 2019, the FERC initiated a review of Southwest Gas’s existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged by Southwest Gas are just and reasonable and set the matter for hearing. Southwest Gas must file a cost and revenue study on or before May 6, 2019. The FERC is directing that an initial decision be issued within 47 weeks of the date the cost and revenue study is due.

Even without action on the 2017 Tax Law NOI or as contemplated in the Final Rule, 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, and tax-related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income taxes, while other pipeline costs also will continue to affect the FERC’s determination of just and reasonable cost of service rates. Although changes in these two tax related components may decrease, other components in the cost of service rate calculation may increase and result in a newly calculated cost of service rate that is the same as or greater than the prior cost of service rate. Moreover, we receive revenues from our pipelines based on a variety of rate structures, including cost of service rates, negotiated rates, discounted rates and market-based rates. Many of our interstate pipelines have negotiated market rates that were agreed to by customers in connection with long-term contracts entered into to support the construction of the pipelines. Other systems have a mix of tariff rate, discount rate, and negotiated rate agreements. We do not expect market-based rates, negotiated rates or discounted rates that are not tied to the cost of service rates to be affected by the Revised Policy Statement or any final regulations that may result from the March 15, 2018 proposals. 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 the ultimate outcome of the NOI, the Final Rule, and the Revised Policy Statement, 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 the Company’s cost of service components and the outcomes of any challenges to our rates by the FERC or our shippers.

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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 due on or before July 25, 2018. 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.

Employees

At December 31, 2018, the Company had 505 employees. Of these employees, 208 were represented by the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial, and Service Workers International AFL-CIO, CLC. The current union contract expires on May 28, 2019.

SEC Reporting

We file or furnish annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any related amendments and supplements thereto with the SEC. The SEC maintains an internet website at http://www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

We provide electronic access, free of charge, to our periodic and current reports on our internet website located at http://www.energytransfer.com. These reports are available on our website as soon as reasonably practicable after we electronically file such materials with the SEC. Information contained on our website is not part of this report.

ITEM 1A. RISK FACTORS

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

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Risks That Relate to the Company

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 ETO 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.

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 s 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 Company depends on distributions from its subsidiaries to meet its needs.

The Company is dependent on the earnings and cash flows of, and dividends, loans, advances or other distributions from, its subsidiaries to generate the funds necessary to meet its obligations. The availability of distributions from such entities is subject to their earnings and capital requirements, the satisfaction of various covenants and conditions contained in financing documents by which they are bound or in their organizational documents, and in the case of the regulated subsidiaries, regulatory restrictions that limit their ability to distribute profits to the Company.

The Company is controlled by ETO.

The Company is an indirect wholly-owned subsidiary of ETO. ETO executives serve as the board of managers and as executive officers of the Company. Accordingly, ETO 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 ETO, on the one hand, and the Company’s creditors, on the other hand, the Company can give no assurance that ETO would not exercise its power to control the Company in a manner that would benefit ETO to the detriment of the Company’s creditors.

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 ET and/or ETO. 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 ET and/or ETO. 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.

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The Company is subject to operating risks.

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

Terrorist attacks aimed at our facilities could adversely affect our business, results of operations, cash flows and financial condition.

The United States government has issued warnings that energy assets, including the nation’s pipeline infrastructure, may be the future target of terrorist organizations. Some of our facilities are subject to standards and procedures required by the Chemical Facility Anti-Terrorism Standards. We believe we are in compliance with all material requirements; however, such compliance may not prevent a terrorist attack from causing material damage to our facilities or pipelines. Any such terrorist attack on our facilities or pipelines, those of our customers, or in some cases, those of other pipelines could have a material adverse effect on our business, financial condition and results of operations.

The impact that terrorist attacks, such as the attacks of September 11, 2001, may have on the energy industry in general, and on the Company in particular, is not known at this time. Uncertainty surrounding military activity may affect the Company’s operations in unpredictable ways, including disruptions of fuel supplies and markets and the possibility that infrastructure facilities, including pipelines, gathering facilities and processing plants, could be direct targets of, or indirect casualties of, an act of terror or a retaliatory strike. The Company may have to incur significant additional costs in the future to safeguard its physical assets.

Cybersecurity breaches and other disruptions could compromise our information and expose us to liability, which would cause our business and reputation to suffer.

In the ordinary course of our business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers, suppliers and business partners, and personal identification information of our employees, in our data centers and on our networks. The secure processing, maintenance and transmission of this information is critical to our operations and business strategy. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties, disruption of our operations, damage to our reputation, and cause a loss of confidence in our products and services, which could adversely affect our business.

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.

Security breaches and other disruptions could compromise our information and operations, and expose us to liability, which would cause our business and reputation to suffer.

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to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties for divulging shipper information, disruption of our operations, damage to our reputation, and loss of confidence in our products and services, which could adversely affect our business.

Our information technology infrastructure is critical to the efficient operation of our business and essential to our ability to perform day-to-day operations. Breaches in our information technology infrastructure or physical facilities, 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.

The success of the pipeline business depends, in part, on factors beyond the Company’s control.

Third parties own most of the natural gas transported and stored through the pipeline systems operated by the Company. As a result, the volume of natural gas transported and stored depends on the actions of those third parties and is beyond the Company’s control. Further, other factors beyond the Company’s and those third parties’ control may unfavorably impact the Company’s ability to maintain or increase current transmission and storage rates, to renegotiate existing contracts as they expire or to remarket unsubscribed capacity. High utilization of contracted capacity by firm customers reduces capacity available for interruptible transportation and parking services.

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 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. Securing additional rights-of-way is also critical to the Company’s ability to pursue expansion projects. 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.

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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 tariff rates (also known as recourse rates) with the FERC 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 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 because it is non-binding policy and parties will have the opportunity to address the policy as applied in future cases. In the rehearing order, the FERC clarified that a pipeline organized as a master limited partnership will not be 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.

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Gs on October 11, 2018. Southwest Gas filed its FERC Form No. 501-G on November 8, 2018. Pursuant to an option in the Final Rule, Sea Robin filed a general section 4 rate case on November 30, 2018 in lieu of filing a FERC Form 501-G which was due on December 6, 2018. Because our existing jurisdictional rates were established based on a higher corporate tax rate, FERC or our shippers may challenge these rates in the future, and the resulting new rate may be lower than the rates we currently charge. For example, the FERC has recently initiated reviews of Panhandle’s and Southwest Gas’s existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged are just and reasonable. These reviews will require the filing of a cost and revenue study prior to the FERC issuing a decision.

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 current FERC Chairman announced in December 2017 that FERC will review 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 that will affect our natural gas pipeline business 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 and HLPSA, PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for natural gas transmission and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect high consequence areas, or HCAs, which are areas where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources, and unusually sensitive ecological areas. These regulations require operators of covered pipelines to:


•	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

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on us and similarly situated midstream operators. For example, in January 2017, PHMSA issued a final rule for hazardous liquid pipelines that significantly expands the reach of certain PHMSA integrity management requirements, such as, for example, periodic assessments, leak detection and repairs, regardless of the pipeline’s proximity to a HCA. The final rule also imposes new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. However, the date of implementation of this final rule by publication in the Federal Register is uncertain given the recent change in Presidential Administrations. In a second example, in April 2016, PHMSA published a proposed rulemaking that would impose new or more stringent requirements for certain natural gas lines and gathering lines including, among other things, expanding certain of PHMSA’s current regulatory safety programs for natural gas pipelines in newly defined “moderate consequence areas” that contain as few as 5 dwellings within a potential impact area; requiring gas pipelines installed before 1970 and thus excluded from certain pressure testing obligations to be tested to determine their maximum allowable operating pressure (“MAOP”); and requiring certain onshore and offshore gathering lines in Class I areas to comply with damage prevention, corrosion control, public education, MAOP limits, line markers and emergency planning standards. Additional requirements proposed by this proposed rulemaking would increase PHMSA’s integrity management requirements and also require consideration of seismicity in evaluating threats to pipelines. The changes adopted or proposed by these rulemakings or made in future legal requirements could have a material adverse effect on our results of operations and costs of transportation services.

Federal, state and local jurisdictions may challenge the Company’s tax return positions.

The positions taken by the tax return filings of the Company’s parent company require significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is also required in assessing the timing and amounts of deductible and taxable items. Despite management’s belief that the tax return positions are fully supportable, certain positions may be challenged successfully by federal, state and local jurisdictions.

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, or PRPs.

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.

The adoption of climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the services we provide.

The EPA has determined that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted rules under the Clean Air Act that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and Title V operating permit reviews for greenhouse gas emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions, which reviews could require securing PSD permits at covered facilities emitting greenhouse gases and meeting “best available control technology” standards for those greenhouse gas emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of greenhouse gas emissions from specified onshore and offshore production facilities and onshore processing, transmission and storage facilities in the United States, which includes certain of our operations. In October 2015, the EPA published a final rule that expands the petroleum and natural gas system sources for which annual

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greenhouse gas emissions reporting is currently required to include greenhouse gas emissions reporting beginning in the 2016 reporting year for certain onshore gathering and boosting systems consisting primarily of gathering pipelines, compressors and process equipment used to perform natural gas compression, dehydration and acid gas removal. While Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, there has not been significant activity in the form of adopted legislation. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing greenhouse gas emissions by means of cap and trade programs. The adoption of any legislation or regulations that requires reporting of greenhouse gases or otherwise restricts emissions of greenhouse gases from our equipment and operations could require us to incur significant added costs to reduce emissions of greenhouse gases or could adversely affect demand for the natural gas and NGLs we gather and process or fractionate.

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.

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. For example, in April 2016, the BOEM published a proposed rule that would update existing air-emissions requirements relating to offshore oil and natural-gas activity on federal Outer Continental Shelf waters. However, in May 2017, Order 3350 was issued by the Department of the Interior Secretary Ryan Zinke, directing the BOEM to reconsider a number of regulatory initiatives governing oil and gas exploration in offshore waters, including, among other things, a cessation of all activities to promulgate the April 2016 proposed rulemaking (“Order 3350”). In an unrelated legal initiative, BOEM issued a Notice to Lessees and Operators (“NTL #2016-N01”) that became effective in September 2016 and imposes more stringent requirements relating to the provision of financial assurance to satisfy decommissioning obligations. Together with a recent re-assessment by BSEE in 2016 in how it determines the amount of financial assurance required, the revised BOEM-administered offshore financial assurance program that is currently being implemented is expected to result in increased amounts of financial assurance being required of operators on the OCS, which amounts may be significant. However, as directed under Order 3350, the BOEM has delayed implementation of NTL #2016-N01 so that it may reconsider this regulatory initiative and, currently, this NTL’s implementation timeline has been extended indefinitely beyond June 30, 2017, except in certain circumstances where there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities. The April 2016 proposed rule and NTL #2016-N01, should they be finalized and/or implemented, 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. 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.

An impairment of goodwill and intangible assets could reduce our earnings.

Goodwill is recorded when the purchase price of a business exceeds the fair value of the tangible and separately measurable intangible net assets. Accounting principles generally accepted in the United States require us to test goodwill for impairment on an annual basis or when events or circumstances occur, indicating that goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that any of our goodwill or intangible assets were impaired, we would be required to take an immediate charge to earnings with a correlative effect on partners’ capital and balance sheet leverage as measured by debt to total capitalization.

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The Company’s business could be affected adversely by union disputes and strikes or work stoppages by its unionized employees.

As of December 31, 2018, 208 of the Company’s 505 employees were represented by collective bargaining units under collective bargaining agreements. Any future work stoppage could, depending on the affected operations and the length of the work stoppage, have a material adverse effect on the Company’s business, financial position, results of operations or 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.

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 order issued January 16, 2019, the FERC initiated a review of PEPL’s existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged by PEPL are just and reasonable and set the

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matter for hearing. PEPL must file a cost and revenue study on or before April 1, 2019. An initial decision is expected to be issued in the first quarter of 2020. In addition, on November 30, 2018, Sea Robin filed a rate case pursuant to Section 4 of the Natural Gas Act. A hearing date is scheduled for October 23, 2019 and an initial decision is expected to be issued in the first quarter of 2020. By order issued February 19, 2019, the FERC initiated a review of Southwest Gas’s existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged by Southwest Gas are just and reasonable and set the matter for hearing. Southwest Gas must file a cost and revenue study on or before May 6, 2019. The FERC is directing that an initial decision be issued within 47 weeks of the date the cost and revenue study is due.

In March 2016, the FERC commenced an audit of Trunkline for the period from January 1, 2013 to present to evaluate Trunkline’s compliance with the requirements of its FERC gas tariff, the accounting regulations of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s annual reporting requirements. The FERC issued a final audit report in October 2018. In response to the findings in the audit report, the Company expects to make certain changes to its processes, policies and procedures; however, the Company does not expect the findings to result in any changes to its financial statements.

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.

Substantial risks are involved in operating a natural gas pipeline system.

Numerous operational risks are associated with the operation of a complex pipeline system. These include adverse weather conditions, accidents, the breakdown or failure of equipment or processes, the performance of pipeline facilities below expected levels of capacity and efficiency, the collision of equipment with pipeline facilities (such as may occur if a third party were to perform excavation or construction work near the facilities) and other catastrophic events beyond the Company’s control. In particular, the Company’s pipeline system, especially those portions that are located offshore, may be subject to adverse weather conditions, including hurricanes, earthquakes, tornadoes, extreme temperatures and other natural phenomena, making it more difficult for the Company to realize the historic rates of return associated with these assets and operations. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Insurance proceeds may not be adequate to cover all liabilities or expenses incurred or revenues lost.

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 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 success of the Company depends on the continued development of additional natural gas reserves in the vicinity of its facilities and its 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 its 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.

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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.

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;

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•	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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

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

ITEM 3. LEGAL PROCEEDINGS

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

ITEM 4. MINE SAFETY DISCLOSURE

Not applicable.

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PART II

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

Southern Union Panhandle LLC, an indirect wholly-owned subsidiary of ETO, owns a 1% general partnership interest in PEPL and ETO indirectly owns a 99% limited partnership interest in PEPL.

ITEM 6. SELECTED FINANCIAL DATA

Item 6, Selected Financial Data, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Tabular dollar amounts are in millions)

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

Overview

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

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

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Results of Operations



	Years Ended December 31,
	2018			2017
OPERATING REVENUES:
Transportation and storage of natural gas	$	544		$	460
Other	30			20
Total operating revenues ⁽¹⁾	574			480
OPERATING EXPENSES:
Cost of natural gas and other energy	4			3
Operating and maintenance	215			199
General and administrative	30			28
Depreciation and amortization	122			127
Impairment losses	—			389
Total operating expenses	371			746
OPERATING INCOME (LOSS)	203			(266		)
OTHER INCOME (EXPENSE):
Interest expense, net	(28		)	(46		)
Interest expense - affiliates	(13		)	—
Interest income - affiliates	—			10
Other, net	(5		)	(6		)
Total other expense, net	(46		)	(42		)
INCOME (LOSS) BEFORE INCOME TAX EXPENSE (BENEFIT)	157			(308		)
Income tax expense (benefit)	49			(263		)
NET INCOME (LOSS)	$	108		$	(45	)
Natural gas volumes transported (TBtu): ⁽²⁾
PEPL	845			636
Trunkline	685			525
Sea Robin	89			73


⁽¹⁾	Reservation revenues comprised 90% and 91% of total operating revenues for the years ended December 31, 2018 and 2017, 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:


•	Operating Revenues. Operating revenues increased for the year ended December 31, 2018 compared to the prior year on the Panhandle and Trunkline pipelines due to higher customer demand driven by colder weather as well as capacity sold at higher rates.

•

Impairment Losses. The Company recorded a total of $389 million of impairment losses for the year ended December 31, 2017, which is comprised of a $262 million goodwill impairment related to Trunkline primarily due to decreases in projected future revenues and cash flows and a $127 million fixed asset impairment for Sea Robin due to lower utilization and expected further decrease in projected future cash flows.


•	Interest expense, net. Interest expense, net decreased for the year ended December 31, 2018 compared to the prior year due to repayment of Panhandle’s $300 million 6.20% Senior Notes in November 2017 and its $400 million 7.00% Senior Notes in June 2018.


•	Interest expense - affiliates. Interest expense - affiliates increased for the year ended December 31, 2018 compared to the prior year primarily due to the issuance of notes payable to a subsidiary of ETO.

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•	Interest income - affiliates. Interest income - affiliates decreased for the year ended December 31, 2018 compared to the prior year primarily due to the settlement of a note receivable from a subsidiary of ETO in November 2017.


•	Income Taxes. The change in the effective rate for the year ended December 31, 2018 was primarily due to an increase in income before income tax expense, a statutory state rate increase, a reduction in the federal corporate income rate per the Tax Act recorded in 2017, and goodwill impairments recorded in 2017, as discussed above, for which the Company does not recognize a tax benefit.

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

Contractual Obligations

The following table summarizes the Company’s expected contractual obligations by payment due date as of December 31, 2018:



	Total		2019		2020		2021		2022		2023		2024 and thereafter
Operating leases⁽¹⁾	$	10	$	2	$	2	$	2	$	1	$	1	$	2
Total long-term debt ^{(2) (3)}	385		150		—		—		—		—		235
Note payable to related party ⁽⁴⁾	356		—		—		—		—		—		356
Interest payments on debt ⁽⁵⁾	268		23		17		17		17		17		177
Interest payments on note payable to related party ⁽⁵⁾	163		19		19		19		19		19		68
Firm capacity payments ⁽⁶⁾	9		8		1		—		—		—		—
OPEB funding ⁽⁷⁾	48		8		8		8		8		8		8
Total ⁽⁸⁾	$	1,239	$	210	$	47	$	46	$	45	$	45	$	846


⁽¹⁾	Lease of various assets utilized for operations.

⁽²⁾

The Company is party to debt agreements containing certain covenants that, if not satisfied, would give rise to an event of default that would cause such debt to become immediately due and payable. Such covenants require the Company to maintain a fixed charge coverage ratio, a leverage ratio and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. At December 31, 2018, the Company was in compliance with all of its covenants. See Note 4 to our consolidated financial statements.


⁽³⁾	The long-term debt cash obligations exclude $16 million of unamortized fair value adjustments as of December 31, 2018.


⁽⁴⁾	The Company has a note payable with a subsidiary of ETO. The note matures on July 31, 2027.


⁽⁵⁾	Interest payments on debt and note payable to related party are based upon the applicable stated or variable interest rates as of December 31, 2018.


⁽⁶⁾	Charges for third party storage capacity.


⁽⁷⁾	PEPL is committed to the funding levels of $8 million per year until modified by future rate proceedings, the timing of which is uncertain.


⁽⁸⁾	Excludes non-current deferred tax liability of $437 million due to uncertainty of the timing of future cash flows for such liabilities.

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Inflation

The Company believes that inflation has caused, and may continue to cause, increases in certain operating expenses, and will continue to result in higher capital replacement and construction costs. The Company continually reviews the adequacy of its rates in relation to such increasing cost of providing services, the inherent regulatory lag in adjusting its tariff rates and the rates it is actually able to charge in its markets.

Recent Accounting Pronouncements

ASU 2016-02

In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report information about the amount, timing, and uncertainty of cash flows arising from a lease. The update requires lessees to record virtually all leases on their balance sheets. For lessors, this amended guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. In January 2018, the FASB issued Accounting Standards Update No. 2018-01 (“ASU 2018-01”), which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the existing lease guidance in Topic 840. The Company plans to elect the package of transition practical expedients and will adopt this standard beginning with its first quarter of fiscal 2019 and apply it retrospectively at the beginning of the period of adoption through a cumulative-effect adjustment to retained earnings. The Company has performed several procedures to evaluate the impact of the adoption of this standard on the financial statements and disclosures and address the implications of Topic 842 on future lease arrangements. The procedures include reviewing all forms of leases, performing a completeness assessment over the lease population, establishing processes and controls to timely identify new and modified lease agreements, educating its employees on these new processes and controls and implementing a third-party supported lease accounting information system to account for our leases in accordance with the new standard. The Company is finalizing its evaluation of the impacts that the adoption of this accounting guidance will have on the consolidated financial statements, and estimates approximately $5 million of right-to-use assets and lease liabilities will be recognized in the consolidated balance sheet upon adoption, with no material impact to its consolidated statements of operations.

Recently Adopted Pronouncements

ASU 2014-09

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“Topic 606”) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Company adopted ASU 2014-09 on January 1, 2018. The Company has made appropriate design and implementation updates to our business processes, systems and internal controls to support recognition and disclosure under the new standard.

Utilizing the practical expedients allowed under the modified retrospective adoption method, Accounting Standards Codification (“ASC”) Topic 606 was only applied to existing contracts for which the Company has remaining performance obligations as of January 1, 2018, and new contracts entered into after January 1, 2018. ASC Topic 606 was not applied to contracts that were completed prior to January 1, 2018.

The Company elected to apply the modified retrospective method to adopt the new standard. For contracts in scope of the new revenue standard as of January 1, 2018, the cumulative effect of adjustment to partners’ capital was not material. The comparative information has not been restated under the modified retrospective method and continues to be reported under the accounting standards in effect for those periods.

The adoption of the new revenue standard by the Company resulted in no reclassifications between revenue, cost of sales and operating expenses. There were no changes in the timing of recognition of revenue and therefore no impact to the balance sheet upon adoption.

ASU 2018-02

In February 2018, the FASB issued Accounting Standards Update No. 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allows a reclassification from accumulated other comprehensive income to partners’ capital for stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017. The Company elected to early adopt this ASU in the first quarter of 2018. The effect of the adoption was not material.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

At December 31, 2018, the interest rate on 88% of the Company’s long-term debt was fixed with no outstanding interest rate swaps.

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, there is 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, 2018, the Company had no hedges outstanding.

Credit Risk

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

The Company’s shippers consist of a diverse portfolio of customers across the energy industry, including oil and gas producers, midstream companies, municipalities, electric and gas utilities, and commercial and industrial end users. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that could impact our shippers to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of shipper non-performance.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

An evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer 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 Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures were adequate and effective as of December 31, 2018.

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 Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the 2013 Internal Control – Integrated Framework 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, 2018.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

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

ITEM 11. EXECUTIVE COMPENSATION

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

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

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

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

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

ITEM 14. PRINCIPAL ACCOUNTING 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,
	2018		2017
Audit fees ⁽¹⁾	$	649	$	620
Audit related fees ⁽²⁾	31		30
Total Fees	$	680	$	650


⁽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 ETO Audit Committee is responsible for the oversight of our accounting, reporting and financial practices, pursuant to the charter of the ETO Audit Committee. 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 ETO Audit Committee also oversees and directs our internal auditing program and reviews our internal controls.

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 ETO Audit Committee. All fees paid or expected to be paid to Grant Thornton LLP for fiscal years 2018 and 2017 were pre-approved by the ETO Audit Committee in accordance with this policy.

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The ETO Audit Committee reviews the external auditors’ proposed scope and approach as well as the performance of the external auditors. It also has direct responsibility for and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, regularly reviews with the external auditors any problems or difficulties the auditors encountered in the course of their audit work, and, at least annually, uses its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items):


•	the auditors’ internal quality-control procedures;


•	any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors;


•	the independence of the external auditors;


•	the aggregate fees billed by our external auditors for each of the previous two years; and


•	the rotation of the lead partner.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES


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


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


(2)	Financial Statement Schedules - None.


(3)	Exhibits - see Index to Exhibits set forth on page 25.

ITEM 16. FORM 10-K SUMMARY

None.

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INDEX TO EXHIBITS

The exhibits listed on the following Exhibit Index are filed as part of this report. Exhibits required by Item 601 of Regulation S-K, but which are not listed below, are not applicable.



	Exhibit Number	Description

	3(a)	Certificate of Formation of Panhandle Eastern Pipe Line Company, LP. (Filed as Exhibit 3.A to PEPL’s Form 10-K for the year ended December 31, 2004)

	3(b)	Limited Partnership Agreement of Panhandle Eastern Pipe Line Company, LP, dated as of June 29, 2004, between Southern Union Company and Southern Union Panhandle LLC. (Filed as Exhibit 3.B to PEPL’s Form 10-K for the year ended December 31, 2004)

	3(c)	Amendment No. 1, dated January 10, 2014 to Agreement of Limited Partnership of Panhandle Eastern Pipe Line Company, LP (Filed as Exhibit 3.1 to PEPL’s Form 8-K filed on January 10, 2014)

	4(a)	Indenture dated as of March 29, 1999, among CMS Panhandle Holding Company, Panhandle Eastern Pipe Line Company and NBD Bank (the predecessor to Bank One Trust Company, National Association, J.P. Morgan Trust Company, National Association, The Bank of New York Trust Company, N.A. and The Bank of New York Mellon Trust Company, N.A.), as Trustee. (Filed as Exhibit 4(a) to PEPL’s Form 10-Q for the quarter ended March 31, 1999)

	4(b)	First Supplemental Indenture dated as of March 29, 1999, among CMS Panhandle Holding Company, Panhandle Eastern Pipe Line Company and NBD Bank (the predecessor to Bank One Trust Company, National Association, J.P. Morgan Trust Company, National Association, The Bank of New York Trust Company, N.A. and The Bank of New York Mellon Trust Company, N.A.), as Trustee, including a form of Guarantee by Panhandle Eastern Pipe Line Company of the obligations of CMS Panhandle Holding Company. (Filed as Exhibit 4(b) to PEPL’s Form 10-Q for the quarter ended March 31, 1999)

	4(c)	Second Supplemental Indenture between Southern Union Company and The Bank of New York, N.A., as Trustee, dated as of October 23, 2006 (incorporated by reference to the Form 8-K/A filed by Southern Union Company on October 26, 2006)

	4(d)	Third Supplemental Indenture, dated as of June 24, 2013, between Southern Union Company and The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed by Southern Union Company on June 26, 2013)

	4(e)	Form of Sixth Supplemental Indenture, dated as of June 12, 2008, between PEPL and The Bank of New York Trust Company, N.A. (now known as The Bank of New York Mellon Trust Company, N.A.), as Trustee (Filed as Exhibit 4.1 to PEPL’s Form 8-K filed on June 11, 2008)

	4(f)	Form of Seventh Supplemental Indenture, to be dated as of June 2, 2009, between PEPL and The Bank of New York Mellon Trust Company, N.A. (Filed as Exhibit 4.1 to PEPL’s Form 8-K filed on May 28, 2009)
	4(g)	Supplemental Indenture No. 3, dated as of June 24, 2013 between Southern Union Company and The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed by Southern Union Company on June 26, 2013)

	4(h)	Supplemental Indenture No. 4, dated as of June 24, 2013 between Southern Union Company and The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed by Southern Union Company on June 26, 2013)


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

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

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

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

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		Exhibit Number		Description
		101.INS		XBRL Instance Document

		101.SCH		XBRL Taxonomy Extension Schema Document

		101.CAL		XBRL Taxonomy Calculation Linkbase Document

		101.DEF		XBRL Taxonomy Extension Definitions Document

		101.LAB		XBRL Taxonomy Label Linkbase Document

		101.PRE		XBRL Taxonomy Presentation Linkbase Document



*	Filed herewith.
**	Furnished herewith.

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SIGNATURES

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



	PANHANDLE EASTERN PIPE LINE COMPANY, LP




February 22, 2019	By: /s/ A. Troy Sturrock A. Troy Sturrock Vice President and Controller (duly authorized to sign on behalf of the registrant)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of Panhandle Eastern Pipe Line Company, LP, in the capacities and on the dates indicated:



	Signature	Title	Date

(i)	Principal executive officer:
	/s/ Kelcy L. Warren	Chief Executive Officer	February 22, 2019
	Kelcy L. Warren

(ii)	Principal financial officer:
	/s/ Thomas E. Long	Chief Financial Officer	February 22, 2019
	Thomas E. Long

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

	Signature	Title	Date
	/s/ Kelcy L. Warren	Manager	February 22, 2019
	Kelcy L. Warren	Southern Union Panhandle LLC

	/s/ Thomas E. Long	Manager	February 22, 2019
	Thomas E. Long	Southern Union Panhandle LLC

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Panhandle Eastern Pipe Line Company, LP and Subsidiaries



Financial Statements and Supplementary Data:	Page:
Report of Independent Registered Public Accounting Firm	F - 2
Consolidated Balance Sheets	F - 3
Consolidated Statements of Operations and Comprehensive Income (Loss)	F - 5
Consolidated Statements of Partners’ Capital	F - 6
Consolidated Statements of Cash Flows	F - 7
Notes to Consolidated Financial Statements	F - 8

F - 1

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Managers of Southern Union Panhandle LLC and

Unitholders of Panhandle Eastern Pipe Line Company, LP

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Panhandle Eastern Pipe Line Company, LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2018 and 2017, the related consolidated statements of operations and comprehensive income (loss), partners’ capital, and cash flows for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

Basis for opinion

These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ GRANT THORNTON LLP

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

Houston, Texas

February 22, 2019

F - 2

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PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)



	December 31,
	2018			2017
ASSETS
Current assets:
Cash and cash equivalents	$	20		$	2
Accounts receivable, net	43			45
Accounts receivable from related companies	11			12
Exchanges receivable	8			5
Inventories	98			150
Other current assets	6			3
Total current assets	186			217

Property, plant and equipment	3,196			3,199
Accumulated depreciation	(507		)	(419		)
	2,689			2,780

Other non-current assets, net	108			167
Goodwill	12			23
Total assets	$	2,995		$	3,187

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

F - 3

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PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)



	December 31,
	2018			2017
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Current maturities of long-term debt	$	152		$	407
Accounts payable and accrued liabilities	6			3
Accounts payable to related companies	46			32
Exchanges payable	85			131
Other current liabilities	69			53
Total current liabilities	358			626

Long-term debt, less current maturities	249			411
Note payable to related party	356			113
Deferred income taxes	437			451
Other non-current liabilities	233			241
Commitments and contingencies
Partners’ capital:
Partners’ capital	1,409			1,348
Accumulated other comprehensive loss	(47		)	(3		)
Total partners’ capital	1,362			1,345
Total liabilities and partners’ capital	$	2,995		$	3,187

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

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PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(Dollars in millions)



	Years Ended December 31,
	2018			2017			2016
OPERATING REVENUES:
Transportation and storage of natural gas	$	544		$	460		$	494
Other	30			20			20
Total operating revenues	574			480			514
OPERATING EXPENSES:
Cost of natural gas and other energy	4			3			2
Operating and maintenance	215			199			209
General and administrative	30			28			31
Depreciation and amortization	122			127			130
Impairment losses	—			389			771
Total operating expenses	371			746			1,143
OPERATING INCOME (LOSS)	203			(266		)	(629		)
OTHER INCOME (EXPENSE):
Interest expense, net	(28		)	(46		)	(49		)
Interest expense - affiliates	(13		)	—			—
Interest income - affiliates	—			10			26
Other, net	(5		)	(6		)	(7		)
Total other expense, net	(46		)	(42		)	(30		)
INCOME (LOSS) BEFORE INCOME TAX EXPENSE (BENEFIT)	157			(308		)	(659		)
Income tax expense (benefit)	49			(263		)	(13		)
NET INCOME (LOSS)	108			(45		)	(646		)

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Actuarial gain (loss) relating to postretirement benefits, net of tax amounts of $11, $3, and $0, respectively	(42		)	(10		)	3
Change in value of available-for-sale securities	—			2			—
COMPREHENSIVE INCOME (LOSS)	$	66		$	(53	)	$	(643	)

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

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PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(Dollars in millions)



	Partners’ Capital			Accumulated Other Comprehensive Income (Loss)			Total
Balance, December 31, 2015	$	2,881		$	2		$	2,883
Deemed distribution to partners	(781		)	—			(781		)
Non-cash compensation expense	2			—			2
Other comprehensive income, net of tax	—			3			3
Net loss	(646		)	—			(646		)
Balance, December 31, 2016	1,456			5			1,461
Distributions to partners	(74		)	—			(74		)
Deemed contribution from partners	8			—			8
Non-cash compensation expense	3			—			3
Other comprehensive loss, net of tax	—			(8		)	(8		)
Net loss	(45		)	—			(45		)
Balance, December 31, 2017	1,348			(3		)	1,345
Distributions to partners	(95		)	—			(95		)
Deemed contribution from partners	31			—			31
Non-cash compensation expense	3			—			3
Other	14			(2		)	12
Other comprehensive loss, net of tax	—			(42		)	(42		)
Net income	108			—			108
Balance, December 31, 2018	$	1,409		$	(47	)	$	1,362

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

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PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)



	Years Ended December 31,
	2018			2017			2016
OPERATING ACTIVITIES:
Net income (loss)	$	108		$	(45	)	$	(646	)
Reconciliation of net loss to net cash provided by operating activities:
Depreciation and amortization	122			127			130
Impairment losses	—			389			771
Deferred income taxes	12			(252		)	(21		)
Amortization of deferred financing fees	(13		)	(24		)	(24		)
Distributions of earnings received from unconsolidated affiliates	—			6			—
Other non-cash	8			8			10
Changes in operating assets and liabilities	31			(49		)	103
Net cash flows provided by operating activities	268			160			323
INVESTING ACTIVITIES:
Capital expenditures	(70		)	(154		)	(106		)
Repayment of note receivable from related party	—			291			49
Note receivable issued to related party	—			(40		)	(265		)
Other	—			2			—
Net cash flows (used in) provided by investing activities	(70		)	99			(322		)
FINANCING ACTIVITIES:
Distributions to partners	(24		)	(74		)	—
Note payable issued from related party	497			113			—
Repayments of loans from affiliates	(252		)	—			—
Repayment of long-term debt	(400		)	(300		)	—
Other	(1		)	—			—
Net cash flows used in financing activities	(180		)	(261		)	—
NET CHANGE IN CASH AND CASH EQUIVALENTS	18			(2		)	1
CASH AND CASH EQUIVALENTS, beginning of period	2			4			3
CASH AND CASH EQUIVALENTS, end of period	$	20		$	2		$	4

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

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PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Tabular dollar amounts are in millions)


1.	OPERATIONS AND ORGANIZATION:


•	References to “ETO” refer to the entity named Energy Transfer Partners, L.P. prior to the close of the Energy Transfer Merger and Energy Transfer Operating, L.P. subsequent to the close of the Energy Transfer Merger; and


•	References to “ET” refer to the entity named Energy Transfer Equity, L.P. prior to the close of the Energy Transfer Merger and Energy Transfer LP subsequent to the close of the Energy Transfer Merger.

Effective December 31, 2018, PEPL distributed its ownership of PEI and certain other assets to its parent.

Southern Union Panhandle LLC, an indirect wholly-owned subsidiary of ETO, owns a 1% general partnership interest in PEPL and ETO indirectly owns a 99% limited partnership interest in PEPL.

Certain prior period amounts have been reclassified to conform to the 2018 presentation. These reclassifications had no impact on net income, total partners’ capital, or cash flows.


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

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

The Company is subject to regulation by certain state and federal authorities. The Company has accounting policies which are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The Company does not apply regulatory-based accounting policies, primarily due to the level of discounting from tariff rates and its inability to recover specific costs. If regulatory-based accounting policies were applied, certain transactions would be recorded differently, including, among others, recording of regulatory assets, the capitalization of an equity component of invested funds on regulated capital projects and depreciation differences. The Company periodically reviews its level of discounting and negotiated rate contracts, the length of rate moratoriums and other related factors to determine if the regulatory-based authoritative guidance should be applied.

Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Recent Accounting Pronouncements

ASU 2016-02

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accounted for as leases under the existing lease guidance in Topic 840. The Company plans to elect the package of transition practical expedients and will adopt this standard beginning with its first quarter of fiscal 2019 and apply it retrospectively at the beginning of the period of adoption through a cumulative-effect adjustment to retained earnings. The Company has performed several procedures to evaluate the impact of the adoption of this standard on the financial statements and disclosures and address the implications of Topic 842 on future lease arrangements. The procedures include reviewing all forms of leases, performing a completeness assessment over the lease population, establishing processes and controls to timely identify new and modified lease agreements, educating its employees on these new processes and controls and implementing a third-party supported lease accounting information system to account for our leases in accordance with the new standard. The Company is finalizing its evaluation of the impacts that the adoption of this accounting guidance will have on the consolidated financial statements, and estimates approximately $5 million of right-to-use assets and lease liabilities will be recognized in the consolidated balance sheet upon adoption, with no material impact to its consolidated statements of operations.

Recently Adopted Pronouncements

ASU 2014-09

ASU 2018-02

Significant Accounting Policies

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

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



	Years Ended December 31,
	2018			2017			2016
Non-cash investing activities:
Settlement of affiliate receivable - note receivable	$	—		$	—		$	541
Settlement of affiliate receivable - tax receivable	—			—			240
Settlement of affiliate liability - tax payable	(19		)	(8		)	—
Settlement of affiliate liability - related party payables	(12		)	—			—
Contribution of assets from affiliate	(7		)	—			—
Distribution of non-cash assets to parent	68			—			—
Supplemental cash flow information:
Accrued capital expenditures	$	13		$	11		$	15
Cash paid for interest, net of interest capitalized	43			75			75
Cash received for interest on note receivable from affiliate	—			18			40
Cash paid for interest on note payable to affiliate	13			—			—

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

The following table presents the components of inventory:



	December 31,
	2018		2017
Natural gas ⁽¹⁾	$	79	$	132
Materials and supplies	19		18
	$	98	$	150


⁽¹⁾	Natural gas volumes held for operations at December 31, 2018 and 2017 were 25.9 TBtu and 37.9 TBtu, respectively.

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

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

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Property, Plant and Equipment.

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



		December 31,
	Lives in Years	2018			2017
Land and improvements		$	3		$	3
Buildings and improvements	6 – 46	158			162
Pipelines and equipment	5 – 46	2,556			2,571
Natural gas storage facilities	26 – 46	282			279
Other	3 – 21	160			157
Construction work in progress		37			27
Property, plant and equipment		3,196			3,199
Accumulated depreciation and amortization		(507		)	(419		)
Property, plant and equipment, net		$	2,689		$	2,780

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

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

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

Interest Cost Capitalized. The Company capitalizes interest on certain qualifying assets that are undergoing activities to prepare them for their intended use. Interest costs incurred during the construction period are capitalized and amortized over the life of the assets. The Company recognized capitalized interest of $1 million, $3 million and $2 million for the years ended December 31, 2018, 2017 and 2016, respectively.

Long-Lived Assets and Goodwill. Long-lived assets are required to be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Goodwill and intangibles with indefinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. An impairment loss should be recognized only if the carrying amount of the asset/goodwill is not recoverable and exceeds its fair value.

In order to test for recoverability when performing a quantitative impairment test, the Company makes estimates of projected cash flows related to the asset, which include, but are not limited to, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and future expenditures necessary to maintain the asset’s existing service potential. In order to determine fair value, the Company makes certain estimates and assumptions, including, among other things, changes in general economic conditions in the Company’s operating regions, the availability and prices of natural gas, the ability to negotiate favorable sales agreements, the risks that natural gas exploration and production activities will not occur or be successful, dependence on certain significant customers and producers of natural gas, and competition from other companies, including major energy producers. If future results are not consistent with the Company’s estimates, future impairment losses that could be material may be recorded to our results of operations.

The Company determines the fair value of its reporting units using a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Company believes the estimates and assumptions used in our impairment assessments are reasonable; however, variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow

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method, the Company determined fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Company determined the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Company estimated a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.

Key assumptions for the measurement of goodwill impairment is management’s estimate of future cash flows and EBITDA. These estimates are based on the annual budget for the upcoming year and forecasted amounts for multiple subsequent years. The annual budget process is typically completed near the annual goodwill impairment testing date, and management uses the most recent information for the annual impairment tests. The forecast is also subjected to a comprehensive update annually in conjunction with the annual budget process and is revised periodically to reflect new information and/or revised expectations. The estimates of future cash flows and EBITDA are subjective in nature and are subject to impacts from the business risks described in “Item 1A. Risk Factors.” Therefore, the actual results could differ significantly from the amounts used for goodwill impairment testing, and significant changes in fair value estimates could occur in a given period.

During the fourth quarter of 2018, the Company performed goodwill impairment tests and did not record a goodwill or fixed asset impairment.

During the fourth quarter of 2017, the Company performed goodwill impairment tests and recognized goodwill impairment of $262 million related to Trunkline, primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that the assets serve. The Company also recorded a $127 million fixed asset impairment related to Sea Robin, primarily due to lower utilization and expected decrease in projected future cash flows.

During the fourth quarter of 2016, the Company performed goodwill impairment tests and recognized goodwill impairment of $590 million and $48 million related to PEPL and Sea Robin, respectively, primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve. The Company also recorded a $133 million fixed asset impairment related to Sea Robin, primarily due to a decrease in projected future cash flows driven by declines in commodity prices.

Changes in the carrying amount of goodwill were as follows:



	Total
Balance, December 31, 2016	$	285
Impairment losses	(262		)
Balance, December 31, 2017	23
Goodwill associated with assets distributed to parent	(11		)
Balance, December 31, 2018	$	12

Related Party Transactions. Related party expenses primarily include payments for services provided by ET, ETO and other affiliates. Other income includes interest income on notes receivable from related parties.

PEPL and certain of its subsidiaries are not treated as separate taxpayers for federal and certain state income tax purposes. Instead, the Company’s income is taxable to its corporate parent, a subsidiary of ETO. The Company has entered into a tax sharing agreement with its corporate parent pursuant to which the Company will be required to make payments to its corporate parent in order to reimburse its corporate parent for federal and state taxes that it pays on the Company’s income, or to receive payments from its corporate parent to the extent that tax losses generated by the Company are utilized by its corporate parent. In addition, the Company’s subsidiaries that are corporations are included in consolidated and combined federal and state income tax returns filed by its corporate parent. The Company’s liability generally is equal to the liability that the Company and its subsidiaries would have incurred based upon the Company’s taxable income if the Company was a taxpayer filing separately from its corporate parent, except that the Company will receive credit under an intercompany note for any increased liability resulting from its tax basis in its assets having been reduced as a result of the like-kind exchange under Section 1031 of the Internal Revenue Code of 1986, as amended.

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

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



	December 31,
	2018		2017
Deposits from customers	$	25	$	10
Accrued expenses	24		22
Other	20		21
Total other current liabilities	$	69	$	53

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



	December 31,
	2018		2017
Pension liability	$	117	$	120
ARO Liability	26		57
Other	90		64
Total other non-current liabilities	$	233	$	241

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

Accounts Receivable and Allowance for Doubtful Accounts. The Company has a large number of customers in the electric and gas utility industries as well as oil and natural gas producers and municipalities. The large number of customers in these energy segments may impact our overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. The Company manages trade credit risk to mitigate credit losses and exposure to uncollectible trade receivables. Prospective and existing customers are reviewed regularly for creditworthiness based upon pre-established standards consistent with FERC filed tariffs to manage credit risk within approved tolerances. Customers that do not meet minimum credit standards are required to provide additional credit support in the form of a letter of credit, prepayment, or other forms of security.

The Company establishes an allowance for doubtful accounts on trade receivables based on the expected ultimate recovery of these receivables and considers many factors including historical customer collection experience, general and specific economic trends, and known specific issues related to individual customers, sectors, and transactions that might impact collectability. Increases in the allowance are recorded as a component of operating expenses; reductions in the allowance are recorded when receivables are subsequently collected or written-off. Past due receivable balances are written-off when the Company’s efforts have been unsuccessful in collecting the amount due.

The allowance for doubtful accounts was not material as of and during the years ended December 31, 2018 and 2017.

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



	Years Ended December 31,
	2018		2017		2016
Customer A	10	%	13	%	12	%
Customer B	16		—		—
Other top 10 customers	28		41		38
Remaining customers	46		46		50
Total percentage	100	%	100	%	100	%

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

Retirement Benefits. The Company recognizes the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans). Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Changes in the funded status of the plan are recorded in other comprehensive income in partners’ capital in the year in which the change occurs. In 2018, the Company adopted Accounting Standards Update No. 2017-07 Compensation - Retirement Benefits (Topic 715) retrospectively. It requires the service cost component to be presented with other current compensation costs for the related employees in the operating section of our consolidated statements of operations, with other components of net benefit cost presented outside of the operating income.

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


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

•

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

•

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

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

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The Company had $26 million and $21 million available for sale securities, included in other non-current assets, at December 31, 2018 and 2017. At December 31, 2018, $17 million in equity securities were valued at Level 1 and $9 million in fixed income securities were valued at Level 2. At December 31, 2017, $14 million in equity securities were valued at Level 1 and $7 million in fixed income securities were valued at Level 2. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value.

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

Income Taxes. Income taxes are accounted for under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.

The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes.

As a limited partnership, the Company is treated as a disregarded entity for federal income tax purposes. Accordingly, the Company and its subsidiaries are not treated as separate taxpayers; instead, their income is directly taxable to the Company’s corporate parent. Under the Company’s tax sharing arrangement with its corporate parent, the Company pays its share of taxes based on taxable income, which will generally equal the liability that the Company would have incurred as a separate taxpayer.

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


3.	RELATED PARTY TRANSACTIONS:

Accounts receivable from related companies reflected on the consolidated balance sheets primarily related to services provided to ET, ETO and other affiliates. Accounts payable to related companies and advance from affiliates reflected on the consolidated balance sheets related to various services provided by ETO and other affiliates.

The following tables provide a summary of related party activity included in our consolidated statements of operations:



	Years Ended December 31,
	2018		2017		2016
Operating revenues	$	97	$	43	$	17
Operating and maintenance	3		7		14
General and administrative	24		23		27
Interest income — affiliates	—		10		26
Interest expense — affiliates	13		—		—

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The Company settled related party payables with a subsidiary of ETO through non-cash contributions during the years ended December 31, 2018 and 2017 for $31 million and $8 million, respectively. During the year ended December 31, 2016, the Company settled related party receivables with a subsidiary of ETO through a non-cash distribution for $240 million.

As of December 31, 2018 and 2017, the Company had $356 million and $113 million, respectively, outstanding under a note payable with a subsidiary of ETO. The note payable accrues interest monthly with an annual interest rate of 5.318% as of December 31, 2018. The note matures on July 31, 2027.


4.	DEBT OBLIGATIONS:

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



	December 31,
	2018		2017
7.00% Senior Notes due 2018	$	—	$	400
8.125% Senior Notes due 2019	150		150
7.60% Senior Notes due 2024	82		82
7.00% Senior Notes due 2029	66		66
8.25% Senior Notes due 2029	33		33
Floating Rate Junior Subordinated Notes due 2066	54		54
Other long term debt	—		5
Unamortized fair value adjustments	16		28
Total debt outstanding	401		818
Less: Current maturities of long-term debt	152		407
Total long-term debt, less current maturities	$	249	$	411

Based on the estimated borrowing rates currently available to the Company and its subsidiaries for loans with similar terms and average maturities, the aggregate fair value of the Company’s consolidated debt obligations at December 31, 2018 and 2017 was $392 million and $830 million, respectively. The fair value of the Company’s consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

As of December 31, 2018, the Company has scheduled long-term debt principal payments as follows:



Years Ended December 31,
2019	150
2020	—
2021	—
2022	—
2023	—
Thereafter	235
Total	$	385

Senior Notes

Panhandle’s 7.00% Senior Notes in the amount of $400 million matured on June 15, 2018 and were repaid with borrowings under an affiliate loan agreement.

Floating Rate Junior Subordinated Notes

The interest rate on the remaining portion of PEPL’s $600 million junior subordinated notes due 2066 is a variable rate based upon the three-month LIBOR rate plus 3.0175%. The balance of the variable rate portion of the junior subordinated notes was $54 million at an effective interest rate of 5.559% and 4.394% at December 31, 2018, and 2017.

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Compliance With Our Covenants

The Company’s notes are subject to certain requirements, such as the maintenance of a fixed charge coverage ratio and a leverage ratio, which if not maintained, restrict the ability of the Company to make certain payments and impose limitations on the ability of the Company to subject its property to liens. Other covenants impose limitations on restricted payments, including dividends and loans to affiliates, and additional indebtedness. As of December 31, 2018, the Company is in compliance with these covenants.

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


5.	RETIREMENT BENEFITS:

Postretirement Benefit Plans

Prior to January 1, 2013, affiliates of the Company offered postretirement health care and life insurance benefit plans (other postretirement plans) that covered substantially all employees. Effective January 1, 2013, participation in the plan was frozen and medical benefits were no longer offered to non-union employees. Effective January 1, 2014, retiree medical benefits were no longer offered to union employees.

Effective January 1, 2018, the plan was amended to extend coverage to a new closed group of former employees based on certain criteria.

Obligations and Funded Status

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



	December 31,
	2018			2017
Change in benefit obligation:
Benefit obligation at beginning of period	$	25		$	19
Service cost	1			—
Interest cost	2			1
Amendments	56			8
Actuarial gain	(3		)	(1		)
Benefits paid, net	(3		)	(2		)
Benefit obligation at end of period	$	78		$	25
Change in plan assets:
Fair value of plan assets at beginning of period	$	143		$	126
Return on plan assets and other	(7		)	11
Employer contributions	8			8
Benefits paid, net	(3		)	(2		)
Fair value of plan assets at end of period	$	141		$	143

Amount overfunded at end of period ⁽¹⁾	$	63		$	118

Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial gain	$	(2	)	$	(13	)
Prior service cost	61			20
	$	59		$	7


⁽¹⁾	Recorded as a non-current asset in the consolidated balance sheets.

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Components of Net Periodic Benefit Cost

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



	Years Ended December 31,
	2018			2017			2016
Service cost	$	1		$	—		$	—
Interest cost	2			1			1
Expected return on plan assets	(7		)	(7		)	(6		)
Prior service credit amortization	14			1			1
Actuarial loss amortization	—			—			(1		)
Net periodic benefit cost	$	10		$	(5	)	$	(5	)

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

The estimated prior service cost for other postretirement plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost during 2019 is $24 million.

Assumptions. The weighted-average discount rate used in determining benefit obligations was 3.44% and 3.75% at December 31, 2018 and 2017, respectively.

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



	Years Ended December 31,
	2018		2017		2016
Discount rate	3.44	%	3.75	%	3.88	%
Expected return on assets:
Tax exempt accounts	7.00	%	7.00	%	7.00	%
Taxable accounts	4.75	%	4.50	%	4.50	%

The Company employs a building block approach in determining the expected long-term rate of return on the plans’ assets with proper consideration for diversification and rebalancing. Historical markets are studied and long-term historical relationships between equities and fixed-income are preserved consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to check for reasonableness and appropriateness.

The assumed health care cost trend rates used to measure the expected cost of benefits covered by the plans are shown in the table below:



	December 31,
	2018		2017
Health care cost trend rate	8.49	%	8.10	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.85	%	4.95	%
Year that the rate reaches the ultimate trend rate	2026		2025

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

Plan Assets. The Company’s overall investment strategy is to maintain an appropriate balance of actively managed investments while maintaining a high standard of portfolio quality and achieving proper diversification. To achieve diversity within its

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other postretirement plan asset portfolio, the Company has targeted the following asset allocations: equity of 25% to 35% and fixed income of 65% to 75%. These target allocations are monitored by the Investment Committee of ETO’s Board of Directors in conjunction with an external investment advisor. On occasion, the asset allocations may fluctuate as compared to these guidelines as a result of Investment Committee actions.

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



	December 31,
	2018		2017
Cash and cash equivalents	$	14	$	12
Target 2020 Fund ⁽¹⁾	—		123
Target 2050 Fund ⁽²⁾	—		8
Total Market Index Fund ⁽³⁾	53		—
Total International Index Fund ⁽⁴⁾	13		—
U.S. Bond Index Fund ⁽⁵⁾	61		—
Total	$	141	$	143


⁽¹⁾	This fund of funds invests primarily in a diversified portfolio of equity, fixed income and cash. As of December 31, 2017, the fund was primarily comprised of 32% equities, 52% fixed income securities and 16% international securities.


⁽²⁾	This fund of funds invests primarily in a diversified portfolio of equity, fixed income and cash. As of December 31, 2017, the fund was primarily comprised of 54% equities, 10% fixed income securities and 36% cash.


⁽³⁾	The fund invests primarily in common stocks included in the Dow Jones U.S. Total Stock Market Index. As of December 31, 2018, this fund was invested 100% in domestic equities.


⁽⁴⁾	The fund invests primarily in both the securities and in depository receipts representing securities included in the MSCI All Country World Index. As of December 31, 2018, this fund was invested 96% in foreign equities and 4% in domestic equities.


⁽⁵⁾	The fund invests primarily in bonds included in the Bloomberg Barclays U.S. Aggregate Bond Index. As of December 31, 2018, this fund was invested 41% in U.S. Treasury, 28% in mortgage-backed securities, 23% in corporations and 8% in other.

The Target 2020 Fund, Target 2025 Fund, Total Market Index Fund and Total International Index Fund assets are classified as Level 1 assets within the fair-value hierarchy. The U.S. Bond Index Fund is classified as Level 2 assets within the fair-value hierarchy.

Contributions. The Company expects to make $8 million contributions to its other postretirement plans in 2019 and annually thereafter until modified by rate case proceedings.

Benefit Payments. The Company’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below.



Years	Expected Benefit Payments
2019	$	4
2020	5
2021	5
2022	6
2023	5
2024 – 2028	24

The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D. The Company does not expect to receive any Medicare Part D subsidies in any future periods.

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Defined Contribution Plan

The Company participates in ETO’s defined contribution savings plan (“Savings Plan”) that is available to virtually all employees. The Company provided matching contributions of 100% of the first 5% of the participant’s compensation paid into the Savings Plan. The Company contributed $2 million to the Savings Plan during the years ended December 31, 2018, 2017, and 2016.

In addition, the Company provides a 3% discretionary profit sharing contribution to eligible employees with annual base compensation below a specific threshold. Company contributions are 100% vested after five years of continuous service. The Company made discretionary profit sharing contributions of $1 million during each of the years ended December 31, 2018, 2017, and 2016.

6.INCOME TAXES:

The following table provides a summary of the current and deferred components of income tax expense (benefit) from continuing operations:



	Years Ended December 31,
	2018		2017			2016
Current expense (benefit):
Federal	$	30	$	(10	)	$	8
State	7		(1		)	—
Total	37		(11		)	8
Deferred expense (benefit):
Federal	$	2	$	(253	)	$	(11	)
State	10		1			(10		)
Total	12		(252		)	(21		)
Total income tax expense (benefit)	$	49	$	(263	)	$	(13	)

The differences between the Company’s effective income tax rate and the United States federal income tax statutory rate were as follows:



	Years Ended December 31,
	2018		2017			2016
Income tax expense (benefit) at federal statutory rate	$	33	$	(108	)	$	(231	)
Changes in income taxes resulting from:
Federal tax rate change	—		(249		)	—
State income taxes, net of federal income tax benefit	14		1			(6		)
Non-deductible goodwill impairment	—		92			223
Other	2		1			1
Income tax expense (benefit)	$	49	$	(263	)	$	(13	)

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Deferred income taxes result from temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the Company’s deferred tax assets (liabilities) as follows:



	December 31,
	2018			2017
Deferred income tax assets:
Other postretirement benefits	$	18		$	3
Debt amortization	11			12
Other	74			65
Total deferred income tax assets	103			80
Valuation allowance	—			(2		)
Net deferred income tax assets (included within other non-current assets, net)	$	103		$	78

Deferred income tax liabilities:
Property, plant and equipment	$	(497	)	$	(484	)
Investment in unconsolidated affiliates	(2		)	(5		)
Other	(41		)	(40		)
Total deferred income tax liabilities	(540		)	(529		)
Net deferred income tax liability	$	(437	)	$	(451	)

As of December 31, 2018, the Company has $12 million ($9 million, net of federal tax) of unrecognized tax benefits, all of which would impact the Company’s effective income tax rate if recognized.

The Company’s policy is to classify and accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense in its consolidated statement of operations, which is consistent with the recognition of these items in prior reporting periods.

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

On December 22, 2017, the Tax Act was signed into law. Among other provisions, the highest corporate federal income tax rate was reduced from 35% to 21% for taxable years beginning after December 31, 2017. As a result, the Company recognized a deferred tax benefit of $249 million in December 2017.


7.	ASSET RETIREMENT OBLIGATIONS:

The Company’s recorded asset retirement obligations are primarily related to owned natural gas storage wells and offshore lines and platforms. At the end of the useful life of these underlying assets, the Company is legally or contractually required to abandon in place or remove the asset. Although a number of other onshore assets in the Company’s system are subject to agreements or regulations that give rise to an ARO upon the Company’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement.

Individual component assets have been and will continue to be replaced, but the pipeline system will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future. The Company has in place a rigorous repair and maintenance program that keeps the pipeline system in good working order. Therefore, although some of the individual assets may be replaced, the pipeline system itself will remain intact indefinitely.

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The Company recorded ARO related to (i) retiring natural gas storage wells, (ii) retiring offshore platforms and lines and (iii) removing asbestos. Long-lived assets related to ARO aggregated $2 million and $1 million as of December 31, 2018 and 2017, respectively, and were reflected as plant, property and equipment on our balance sheet. In addition, the Company had $26 million and $21 million legally restricted for the purpose of settling ARO that was reflected as other non-current assets as of December 31, 2018 and 2017, respectively.

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



	Years Ended December 31,
	2018			2017			2016
Beginning balance	$	57		$	54		$	58
Revisions	(33		)	1			—
Settled	(1		)	(1		)	(7		)
Accretion expense	3			3			3
Ending balance	$	26		$	57		$	54


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

Contingent Residual Support Agreement with ETO

Under a contingent residual support agreement with ETO and Citrus ETP Finance LLC, the Company provides contingent, residual support to Citrus ETP Finance LLC (on a non-recourse basis to the Company) with respect to Citrus ETP Finance LLC’s obligations to ETO to support the payment of $2 billion in principal amount of senior notes issued by ETO on January 17, 2012.

FERC Proceedings

By order issued January 16, 2019, the FERC initiated a review of PEPL’s existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged by PEPL are just and reasonable and set the matter for hearing. PEPL must file a cost and revenue study on or before April 1, 2019. An initial decision is expected to be issued in the first quarter of 2020. In addition, on November 30, 2018, Sea Robin filed a rate case pursuant to Section 4 of the Natural Gas Act. A hearing date is scheduled for October 23, 2019 and an initial decision is expected to be issued in the first quarter of 2020.

By order issued February 19, 2019, the FERC initiated a review of Southwest Gas’s existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged by Southwest Gas are just and reasonable and set the matter for hearing. Southwest Gas must file a cost and revenue study on or before May 6, 2019. The FERC is directing that an initial decision be issued within 47 weeks of the date the cost and revenue study is due.

Environmental Matters

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

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

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

The Company recorded $2 million in non-current liabilities as of December 31, 2018 and 2017 to cover environmental remediation actions where management believes a loss is probable and reasonably estimable. The Company is not able to estimate the possible loss or range of loss in excess of amounts accrued. The Company does not have any material environmental remediation matters assessed as reasonably possible.

Liabilities for Litigation and Other Claims

The Company records accrued liabilities for litigation and other claim costs when management believes a loss is probable and reasonably estimable. When management believes there is at least a reasonable possibility that a material loss or an additional material loss may have been incurred, the Company discloses (i) an estimate of the possible loss or range of loss in excess of the amount accrued; or (ii) a statement that such an estimate cannot be made. As of December 31, 2018 and 2017, the Company’s consolidated balance sheet reflected litigation and other claim-related accrued liabilities of $20 million and $21 million, respectively. The Company does not have any material litigation or other claim contingency matters assessed as probable or reasonably possible that would require disclosure in the financial statements.

Other Commitments and Contingencies

The Company is subject to the laws and regulations of states and other jurisdictions concerning the identification, reporting and escheatment (the transfer of property to the state) of unclaimed or abandoned funds, and is subject to audit and examination for compliance with these requirements. The Company is currently being examined by a third party auditor on behalf of nine states for compliance with unclaimed property laws.


9.	REVENUE

The following disclosures discuss the Company’s revised revenue recognition policies upon the adoption of ASU 2014-09 on January 1, 2018, as discussed in Note 2. These policies were applied to the current period only, and the amounts reflected in the Company’s consolidated financial statements for the years ended December 31, 2017 and 2016 were recorded under the Company’s previous accounting policies.

Our revenues are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through pipelines. Under transportation and storage contracts, customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly.

The performance obligation with respect to these contracts is a promise to provide a single type of service daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue should be recognized over time because the customer simultaneously receives and consumes the benefit of this service.

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Contract Balances with Customers

The Company satisfies its obligations by transferring goods or services in exchange for consideration from customers. The timing of performance may differ from the timing the associated consideration is paid to or received from the customer, thus resulting in the recognition of a contract asset or a contract liability.

The Company recognizes a contract asset when making upfront consideration payments to certain customers or when providing services to customers prior to the time at which the Company is contractually allowed to bill for such services. As of December 31, 2018, no contract assets have been recognized.

The Company recognizes a contract liability if the customer's payment of consideration precedes the Company’s fulfillment of the performance obligations. As of December 31, 2018, no contract liabilities have been recognized.

Performance Obligation

At contract inception, the Company assesses the goods and services promised in its contracts with customers and identifies a performance obligation for each promise to transfer a good or service (or bundle of goods or services) that is distinct. To identify the performance obligations, the Company considers all the goods or services promised in the contract, whether explicitly stated or implied based on customary business practices. For a contract that has more than one performance obligation, the Company allocates the total contract consideration it expects to be entitled to, to each distinct performance obligation based on a standalone-selling price basis. Revenue is recognized when (or as) the performance obligations are satisfied, that is, when the customer obtains control of the good or service. Certain of our contracts contain variable components, which, when combined with the fixed component are considered a single performance obligation. For these types of contracts, only the fixed component of the contracts are included in the table below.

As of December 31, 2018, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations is approximately $2.89 billion and the Company expects to recognize this amount as revenue within the time bands illustrated below:



	Years Ending December 31,
	2019		2020		2021		Thereafter		Total
Revenue expected to be recognized on contracts with customers existing as of December 31, 2018	$	445	$	357	$	293	$	1,795	$	2,890

Practical Expedients Utilized by the Company

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

•

Right to invoice - The Company elected to utilize an output method to recognize revenue that is based on the amount to which the Company has a right to invoice a customer for services performed to date, if that amount corresponds directly with the value provided to the customer for the related performance or its obligation completed to date. As such, the Company recognized revenue in the amount to which it had the right to invoice customers.


•	Significant financing component - The Company elected not to adjust the promised amount of consideration for the effects of significant financing component if the Company expects, at contract inception, that the period between the transfer of a promised good or service to a customer and when the customer pays for that good or service will be one year or less.


•	Unearned variable consideration - The Company elected to only disclose the unearned fixed consideration associated with unsatisfied performance obligations related to our various customer contracts which contain both fixed and variable components.

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10.	QUARTERLY FINANCIAL DATA (UNAUDITED):

The following table provides certain quarterly financial information for the periods presented:



	Quarters Ended
	March 31, 2018		June 30, 2018		September 30, 2018		December 31, 2018			Total
Operating revenues	$	149	$	134	$	137	$	154		$	574
Operating income	64		42		41		56			203
Net income	34		22		23		29			108


	Quarters Ended
	March 31, 2017		June 30, 2017		September 30, 2017		December 31, 2017			Total
Operating revenues	$	128	$	104	$	110	$	138		$	480
Operating income (loss) ⁽¹⁾	37		20		18		(341		)	(266		)
Net income (loss)	14		8		4		(71		)	(45		)


⁽¹⁾	Operating income (loss) includes $389 million of impairment losses recognized during the fourth quarter of 2017.

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Exhibit

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Kelcy L. Warren, certify that:


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


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


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


b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c.	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d.	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize, and report financial information; and


b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 22, 2019



/s/ Kelcy L. Warren
Kelcy L. Warren
Chief Executive Officer

Exhibit

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Thomas E. Long, certify that:


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


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


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


b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c.	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d.	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize, and report financial information; and


b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 22, 2019



/s/ Thomas E. Long
Thomas E. Long
Chief Financial Officer

Exhibit

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Panhandle Eastern Pipe Line Company, LP (the “Company”) on Form 10-K for the year ended December 31, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Kelcy L. Warren, Chief Executive Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:


(1)	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and


(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 22, 2019



/s/ Kelcy L. Warren
Kelcy L. Warren
Chief Executive Officer

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

Exhibit

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Panhandle Eastern Pipe Line Company, LP (the “Company”) on Form 10-K for the year ended December 31, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Thomas E. Long, Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:


(1)	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and


(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 22, 2019



/s/ Thomas E. Long
Thomas E. Long
Chief Financial Officer

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