10-K

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, 2016

or

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

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 xNo ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).  Yes xNo ¨

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, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. Large accelerated filer ¨   Accelerated filer ¨   Non-accelerated filer x   Smaller reporting company ¨

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.

PANHANDLE EASTERN PIPE LINE COMPANY, LP

TABLE OF CONTENTS

		Page
PART I
ITEM 1.	BUSINESS	1
ITEM 1A.	RISK FACTORS	3
ITEM 1B.	UNRESOLVED STAFF COMMENTS	14
ITEM 2.	PROPERTIES	14
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	19
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	20
PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	21
ITEM 11.	EXECUTIVE COMPENSATION	21
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS	21
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	21
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	21
PART IV
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	23
ITEM 16.	FORM 10-K SUMMARY	23
	SIGNATURES	24

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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, estimated or expressed, forecasted, projected or expected in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Part I – Item 1A. Risk Factors” included in this annual report.

Definitions

The abbreviations, acronyms and industry terminology used in 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
ETE	Energy Transfer Equity, L.P.
ETP	Energy Transfer Partners, L.P., a subsidiary of ETE
Exchange Act	Securities Exchange Act of 1934
FERC	Federal Energy Regulatory Commission
GAAP	Accounting principles generally accepted in the United States of America
Lake Charles LNG	Lake Charles LNG Company, LLC
LIBOR	London Interbank Offered Rate
LNG	Liquefied natural gas
NGL	Natural gas liquids
PCBs	Polychlorinated biphenyls
PEPL	Panhandle Eastern Pipe Line Company, LP
PEPL Holdings	PEPL Holdings, LLC
PRPs	Potentially responsible parties
Regency	Regency Energy Partners LP, a subsidiary of ETP
Sea Robin	Sea Robin Pipeline Company, LLC
SEC	United States Securities and Exchange Commission
Southern Union	Southern Union Company

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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 and its subsidiaries are primarily engaged in 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 Gas Company, LLC (“Trunkline”), Sea Robin Pipeline Company, LLC (“Sea Robin”) and Pan Gas Storage LLC (“Southwest Gas”).

Southern Union Panhandle LLC, an indirect wholly-owned subsidiary of ETP, owns a 1% general partnership interest in PEPL and ETP indirectly owns a 99% limited partnership 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 89% of total revenues in 2016.

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

	Years Ended December 31,
	2016	2015
PEPL transportation	609	607
Trunkline transportation	480	633
Sea Robin transportation	85	113

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The following table provides a summary of certain statistical information associated with the Company at December 31, 2016:

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)	68.1
Underground Storage Capacity-Leased (Bcf)	28.8
Weighted Average Remaining Life in Years of Firm Transportation Contracts (1)
PEPL	4.5
Trunkline	7.6
Sea Robin (2)	N/A
Weighted Average Remaining Life in Years of Firm Storage Contracts (1)
PEPL	6.9
Trunkline	3.4

⁽¹⁾  Weighted by firm capacity volumes.

⁽²⁾  Sea Robin’s contracts are primarily interruptible, with only four firm contracts in place.

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.    

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

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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 11 to our consolidated financial statements.

Employees

At December 31, 2016, the Company had 542 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. You may read and copy any materials we file or furnish with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information regarding the Public Reference Room by calling the SEC at 1-800-732-0330. In addition, the SEC maintains an internet website at http://www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

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

ITEM 1A. RISK FACTORS

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

Risks That Relate to the Company

The Company has substantial debt and may not be able to obtain funding or obtain funding on acceptable terms because of deterioration in the credit and capital markets.  This may hinder or prevent the Company from meeting its future capital needs.

The Company has a significant amount of debt outstanding.  As of December 31, 2016, debt on the consolidated balance sheets totaled $1.14 billion.

Covenants exist in certain of the Company’s debt agreements that 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. A failure by the Company to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if the Company did not cure such default within any permitted cure period or if the Company did not obtain amendments, consents or waivers from its lenders with respect to such covenants. Any such acceleration or inability to borrow could cause a material adverse change in the Company’s financial condition.

The Company relies on access to both short- and long-term credit as a significant source of liquidity for capital requirements not satisfied by the cash flow from its operations.  Deterioration in the Company’s financial condition could hamper its ability to access the capital markets.

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Global financial markets and economic conditions have been, and may continue to be, disrupted and volatile.  The current weak economic conditions have made, and may continue to make, obtaining funding more difficult.

Due to these factors, the Company cannot be certain that funding will be available if needed and, to the extent required, on acceptable terms.  If funding is not available when needed, or is available only on unfavorable terms, the Company may be unable to grow its existing business, complete acquisitions, refinance its debt or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on the Company’s revenues and results of operations.

Credit ratings downgrades could increase the Company’s financing costs and limit its ability to access the capital markets.

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

The 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 ETP.

The Company is an indirect wholly-owned subsidiary of ETP.  ETP executives serve as the board of managers and as executive officers of the Company.  Accordingly, ETP 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 ETP, on the one hand, and the Company’s creditors, on the other hand, the Company can give no assurance that ETP would not exercise its power to control the Company in a manner that would benefit ETP 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 ETE and/or ETP. 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 ETE and/or ETP. These officers and directors face potential conflicts regarding the allocation of their time, which may adversely affect our business, results of operations and financial condition.

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Our affiliates may compete with us.

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

The Company’s growth strategy entails risk.

The Company may actively pursue acquisitions in the energy industry to complement and diversify its existing businesses. As part of its growth strategy, PEPL may:

• examine and potentially acquire regulated or unregulated businesses, including transportation and storage assets and gathering and processing businesses within the natural gas industry;

• enter into joint venture agreements and/or other transactions with other industry participants or financial investors;

• selectively divest parts of its business, including parts of its core operations; and

• continue expanding its existing operations.

The Company’s ability to acquire new businesses will depend upon the extent to which opportunities become available, as well as, among other things:

• its success in valuing and bidding for the opportunities;

• its ability to assess the risks of the opportunities;

• its ability to obtain regulatory approvals on favorable terms; and

• its access to financing on acceptable terms.

Once acquired, the Company’s ability to integrate a new business into its existing operations successfully will largely depend on the adequacy of implementation plans, including the ability to identify and retain employees to manage the acquired business, and the ability to achieve desired operating efficiencies. The successful integration of any businesses acquired in the future may entail numerous risks, including:

• the risk of diverting management’s attention from day-to-day operations;

• the risk that the acquired businesses will require substantial capital and financial investments;

• the risk that the investments will fail to perform in accordance with expectations; and

• the risk of substantial difficulties in the transition and integration process.

These factors could have a material adverse effect on the Company’s business, financial condition, results of operations and cash flows, particularly in the case of a larger acquisition or multiple acquisitions in a short period of time.

The consideration paid in connection with an investment or acquisition also affects the Company’s financial results. In addition, acquisitions or expansions may result in the incurrence of additional debt.

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,

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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.

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 personally identifiable 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 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.

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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.  Even though the Company generally has the right of eminent domain, 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.

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

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shippers who elect not to pay the recourse rates. The FERC must approve or accept all rate filings for us to be allowed to charge such rates.

The FERC may review existing tariffs 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. It is currently the FERC’s policy to permit pipelines to include in cost-of-service a tax allowance to reflect actual or potential income tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. Under the FERC’s policy, we thus remain eligible to include an income tax allowance in the tariff rates we charge for interstate natural gas transportation. The effectiveness of the FERC’s policy and the application of that policy remain subject to future challenges, refinement or change by the FERC or the courts.

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.

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The absence of a quorum at FERC, if it persists, could limit our ability to construct new facilities and/or expand certain existing facilities, which could have a material and adverse impact on our business and result of operations.

The Federal Energy Regulatory Commission (“FERC” or the “Commission”) oversees, among other matters, the interstate sale at wholesale and transportation of natural gas, crude oil and refined petroleum products, as well as the construction and siting of liquefied natural gas, or LNG, facilities.  FERC’s authority includes reviewing proposals to site, construct, expand and/or retire interstate natural gas pipeline facilities.  As set forth in the Department of Energy Authorization Act (“DOE Act”), the Commission is composed of up to five Commissioners, who are to be appointed by the President and confirmed by the Senate.  The DOE Act requires that at least three Commissioners be present “for the transaction of business.”  Without such a quorum of three or more Commissioners, FERC is unable to act on matters that require a vote of its Commissioners.  Norman Bay, a FERC Commissioner and former Chairman of the Commission, resigned effective February 3, 2017.  With Commissioner Bay’s departure, only two FERC Commissioners remained in office, as there were already two vacancies prior to Commissioner Bay’s resignation.  FERC has therefore lacked the quorum required for its Commissioners to issues orders and take other actions since February 3.  While FERC staff may still issue certain routine or uncontested orders under authority delegated by the Commission while it had a quorum, and such delegated authority was broadened immediately prior to Commissioner Bay’s departure, FERC is currently unable to resolve contested cases or issue major new orders, such as certificates of public convenience and necessity for new interstate natural gas pipelines or the expansion of existing FERC-certificated pipelines.  The current limitations on FERC’s ability to act have not had a material effect on our operations, but if the absence of a quorum continues for a long enough period of time, our ability to construct new facilities and/or expand the capacity of our pipelines could be materially affected.  The absence of a quorum will continue until a new FERC Commissioner is nominated by the President and confirmed by the Senate, provided the two remaining FERC Commissioners remain in office.  The President has not yet nominated any new FERC Commissioners to fill the vacancies.

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

Pursuant to authority under the Natural Gas Pipeline Safety Act (“NGPSA”) and Hazardous Liquid Pipeline Safety Act (“HLPSA”), as amended by the Pipeline Safety Improvement Act, the PIPES Act and the 2011 Pipeline Safety Act, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a series of rules requiring pipeline operators to develop and implement integrity management programs for gas transmission and hazardous liquid pipelines that, in the event of a pipeline leak or rupture could affect “high consequence areas,” which are areas where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources, and unusually sensitive ecological areas. These regulations require operators of covered pipelines to:

• perform ongoing assessments of pipeline integrity;

• identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

• improve data collection, integration and analysis;

• repair and remediate the pipeline as necessary; and

• implement preventive and mitigating actions.

In addition, states have adopted regulations similar to existing PHMSA regulations for intrastate gathering and transmission lines. At this time, we cannot predict the ultimate cost of compliance with applicable pipeline integrity management regulations, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of the pipeline integrity testing. We will continue our pipeline integrity testing programs to assess and maintain the integrity of our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines. Any changes to pipeline safety laws by Congress and regulations by PHMSA that result in more stringent or costly safety standards could have a significant adverse effect on us and similarly situated midstream operators. For instance, changes to regulations governing the safety of gas transmission pipelines and gathering lines are being considered by PHMSA, including, for example, revising the definitions of “high consequence areas” and “gathering lines” and strengthening integrity management requirements as they apply to existing regulated operators and to currently exempt operators should certain exemptions be removed.

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

The positions taken by the Company in its tax return filings 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 Company’s tax return positions are fully supportable, certain positions may be challenged successfully by federal, state and local jurisdictions.

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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 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.

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

As of December 31, 2016, our consolidated balance sheet reflected $285 million of goodwill. 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.

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

As of December 31, 2016, 208 of the Company’s 542 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 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 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. More recently, on October 22, 2015, the EPA published a final rule that expands the petroleum and natural gas system sources for which annual 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

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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.

In response to the Deepwater Horizon incident and resulting oil spill in the United States Gulf of Mexico in 2010, the federal Bureau of Ocean Energy Management (“BOEM”) and the federal Bureau of Safety and Environmental Enforcement (“BSEE”), each agencies of the U.S. 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 restrictions together with any uncertainties or inconsistencies in current 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 adversely affect or delay new drilling and ongoing development efforts. In addition, new regulatory initiatives may be adopted or enforced by the BOEM and/or the BSEE in the future that could result in additional 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 September 2015, the BOEM issued draft guidance that would bolster supplemental bonding procedures for the decommissioning of offshore wells, platforms, pipelines, and other facilities. The BOEM is expected to issue the draft guidance in the form of a final Notice to Lessees and Operators by no later than mid-2016. These recent or 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 similar to the Deepwater Horizon incident were to occur in the future, the United States or other countries could elect to again 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.

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 could significantly increase 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 U.S. 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

11

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, as it had in 2007 with respect to Southwest Gas.  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.

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 higher than 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.

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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.

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 reportcontains 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;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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.

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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 11 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 ETP, owns a 1% general partnership interest in PEPL and ETP 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.”

Recent Developments

Investment in ETP

The Company’s investment in ETP, including common units from the Regency merger, consisted of 17.8 million ETP common units and was accounted for using the equity method. Effective September 1, 2015, the Company exchanged these ETP common units for a note receivable from a subsidiary of ETP in the amount of $1.37 billion. The note receivable accrued interest annually at 4.75% and was due on September 1, 2035. On August 31, 2016, the remaining balance of $541 million on the note receivable and related accrued interest from a subsidiary of ETP was settled through a non-cash distribution.

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Results of Operations

	Years Ended December 31,
	2016			2015
OPERATING REVENUES:
Transportation and storage of natural gas	$	496		$	528
Other	18			20
Total operating revenues (1)	514			548
OPERATING EXPENSES:
Cost of natural gas and other energy	2			4
Operating and maintenance	209			216
General and administrative	39			42
Depreciation and amortization	130			133
Impairment losses	771			—
Total operating expenses	1,151			395
OPERATING INCOME (LOSS)	(637		)	153
OTHER INCOME (EXPENSE):
Interest expense, net	(49		)	(50		)
Equity in earnings of unconsolidated affiliates	1			26
Interest income - affiliates	26			23
Other, net	—			5
Total other income (expense), net	(22		)	4
INCOME (LOSS) BEFORE INCOME TAX EXPENSE	(659		)	157
Income tax expense (benefit)	(13		)	52
NET INCOME (LOSS)	(646		)	105
Natural gas volumes transported (TBtu): (2)
PEPL	609			607
Trunkline	480			633
Sea Robin	85			113

⁽¹⁾  Reservation revenues comprised 89% and 90% of total operating revenues for the years ended December 31, 2016 and 2015, 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 decreased for the year ended December 31, 2016 compared to the prior year due to the transfer of one of Trunkline’s pipelines that was taken out of service during the third quarter of 2015 in advance of being repurposed from natural gas service to crude oil service, lower reservation revenues on the Panhandle and Trunkline pipelines due to capacity sold at lower rates and declines in production and third party maintenance on the Sea Robin Pipeline. These decreases were partially offset by higher parking revenues on the Panhandle and Trunkline pipelines.

• Impairment Losses. For the year ended December 31, 2016, the Company recorded a $133 million impairment related to Sea Robin property, plant and equipment and goodwill impairments of $590 million and $48 million related to the PEPL reporting unit and the Sea Robin reporting unit, respectively. These impairments were 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.

• Equity in Earnings of Unconsolidated Affiliates. Equity in earnings of unconsolidated affiliates decreased for the year ended December 31, 2016 compared to the prior year due to the exchange of the Company’s investment in ETP for a note receivable from a subsidiary of ETP effective September 1, 2015.

17

• Income Taxes. The change in the effective rate for the year ended December 31, 2016 was primarily due to goodwill impairments, 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 11 to our consolidated financial statements.

Contingencies and Regulatory Matters

See Note 11 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, 2016:

	Total		2017		2018		2019		2020		2021		2022 and thereafter
Operating leases (1)	$	14	$	3	$	2	$	2	$	2	$	2	$	3
Total long-term debt (2) (3)	1,090		300		400		150		—		—		240
Interest payments on debt (4)	338		75		42		22		16		16		167
Natural gas purchases (5)	38		3		3		3		3		2		24
Firm capacity payments (6)	44		24		16		4		—		—		—
OPEB funding (7)	48		8		8		8		8		8		8
Total (8)	$	1,572	$	413	$	471	$	189	$	29	$	28	$	442

⁽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, 2016, the Company was in compliance with all of its covenants.  See Note 6 to our consolidated financial statements.

⁽³⁾  The long-term debt cash obligations exclude $51 million of unamortized fair value adjustments as of December 31, 2016.

⁽⁴⁾  Interest payments on debt are based upon the applicable stated or variable interest rates as of December 31, 2016.

⁽⁵⁾  The Company has tariffs in effect for its utility service areas that provide for recovery of its purchased natural gas costs under defined methodologies.

⁽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 $711 million due to uncertainty of the timing of future cash flows for such liabilities.

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.

18

New Accounting Standards

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. In August 2015, the FASB deferred the effective date of ASU 2014-09, which is now effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The guidance permits two methods of adoption: retrospectively to each prior reporting period presented (full retrospective method), or retrospectively with the cumulative effect of initially applying the guidance recognized at the date of initial application (the cumulative catchup transition method). The Company expects to adopt ASU 2014-09 in the first quarter of 2018 and will apply the cumulative catchup transition method. The Company is in the process of evaluating revenue contracts by fee type to determine the potential impact of adopting the new standards. At this point the Company has determined that the timing and/or amount of revenues recognized on certain contracts may be impacted by the adoption of the new standard; however, the Company is still in the process of quantifying these impacts and cannot say whether or not they would be material to the financial statements. In addition, the Company is in the process of implementing appropriate changes to business processes, systems and controls to support recognition and disclosure under the new standard. The Company continues to monitor additional authoritative or interpretive guidance related to the new standard as it becomes available, as well as comparing to conclusions on specific interpretative issues to other industry peers, to the extent that such information is available.

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 useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The Company is currently evaluating the impact, if any, that adopting this new standard will have on the consolidated financial statements and related disclosures.

In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment”. The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit's carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance does not amend the optional qualitative assessment of goodwill impairment. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. We expect that our adoption of this standard will change our approach for testing goodwill for impairment; however, this standard requires prospective application and therefore will only impact periods subsequent to adoption.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

At December 31, 2016, the interest rate on 95% 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, 2016, there were no hedges in place with respect to natural gas price risk associated with the Company’s interstate pipeline operations.

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

19

the shippers. Furthermore, the Company may, at times, require collateral 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, 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, 2016.

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, 2016.

ITEM 9B. OTHER INFORMATION

None.

20

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,
	2016		2015
Audit fees (1)	$	680	$	565
Audit related fees (2)	37		28
Tax fees	—		—
All other fees	—		—
Total Fees	$	717	$	593

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

The ETP 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 ETP Audit Committee.

21

The ETP 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.

22

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 E-1.

ITEM 16. FORM 10-K SUMMARY

None.

23

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
Date:  February 24, 2017	By: /s/   A. Troy Sturrock A. Troy Sturrock Senior 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 the Panhandle 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 24, 2017
	Kelcy L. Warren
(ii)	Principal financial officer:
	/s/ Thomas E. Long	Chief Financial Officer	February 24, 2017
	Thomas E. Long
(iii)	The Board of Directors of SUG Holding Company, Sole Member of Southern Union Panhandle, LLC, General Partner of Panhandle Eastern Pipe Line Company, L.P
	Signature	Title	Date
	/s/ Kelcy L. Warren	Chief Executive Officer and Director,	February 24, 2017
	Kelcy L. Warren	SUG Holding Company
	/s/ John W. McReynolds	Director, SUG Holding Company	February 24, 2017
	John W. McReynolds

24

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 dated as of March 27, 2000, between PEPL and Bank One Trust Company, National Association (succeeded to by The Bank of New York Mellon Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A.), as Trustee. (Filed as Exhibit 4(e) to PEPL’s Form S-4 (File No. 333-39850) filed on June 22, 2000.)
4(d)	Third Supplemental Indenture dated as of August 18, 2003, between PEPL and Bank One Trust Company, National Association (succeeded to by The Bank of New York Mellon Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A.), as Trustee. (Filed as Exhibit 4(d) to PEPL’s Form 10-Q for the quarter ended September 30, 2003.)
4(e)	Fourth Supplemental Indenture dated as of March 12, 2004, between PEPL and J.P. Morgan Trust Company, National Association (succeeded to by The Bank of New York Mellon Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A.), as Trustee.  (Filed as Exhibit 4.E to PEPL’s Form 10-K for the year ended December 31, 2004.)
4(f)	Fifth Supplemental Indenture dated as of October 26, 2007, 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 October 29, 2007.)
4(g)	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.)
10(a)	Credit Agreement between Trunkline LNG Holdings, LLC, as borrower, Panhandle Eastern Pipeline Company, LP and Trunkline LNG Company, LLC, as guarantors, the financial institutions listed therein and the Bank of Tokyo-Mitsubishi UFJ, Ltd., as administrative agent, dated as of February 23, 2012 (Filed as Exhibit 10(a) to PEPL’s Form 10-K for the year ended December 31, 2011.)
10(b)	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.)
10(c)	Amended and Restated Credit Agreement between Trunkline LNG Holdings, LLC, as borrower, Panhandle Eastern Pipe Line Company, LP and CrossCountry Citrus, LLC, as guarantors, the financial institutions listed therein and Bayerische Hypo-Und Vereinsbank AG, New York Branch, as administrative agent, dated as of June 29, 2007 (Filed as Exhibit 10.1 to PEPL’s Form 8-K filed on July 6, 2007.)

E - 1

	Exhibit Number	Description
	10(d)	Amendment Number 1 to the Amended and Restated Credit Agreement between Trunkline LNG Holdings, LLC as borrower, Panhandle Eastern Pipe Line Company, LP and CrossCountry Citrus, LLC, as guarantors, the financial institutions listed therein and Bayerische Hypo-Und Vereinsbank AG, New York Branch, as administrative agent, dated as of June 13, 2008 (Filed as Exhibit 10(b) to PEPL’s Form 10-Q for the quarter ended June 30, 2008.)
	10(e)	Amended and Restated Promissory Note made by CrossCountry Citrus, LLC, as borrower, in favor of Trunkline LNG Holdings LLC, as holder, dated as of June 13, 2008 (Filed as Exhibit 10(d) to PEPL’s Form 10-Q for the quarter ended June 30, 2008.)
	10(f)	Transfer Agreement, dated February 19, 2014, by and between Energy Transfer Partners, L.P. and Panhandle Eastern Pipe Line Company, LP (Filed as Exhibit 10.1 to PEPL’s Form 8-K filed on February 19, 2014.)
*	12.1	Computation of Ratio of Earnings to Fixed Charges.
*	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.
	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.

E - 2

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

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Managers

Panhandle Eastern Pipe Line Company, LP

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, 2016 and 2015, and the related consolidated statements of operations, comprehensive income (loss), partners’ capital, and cash flows for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, 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. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Panhandle Eastern Pipe Line Company, LP and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Houston, Texas

February 24, 2017

F - 2

PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

	December 31,
	2016			2015
ASSETS
Current assets:
Cash and cash equivalents	$	4		$	3
Accounts receivable, net	46			48
Accounts receivable from related companies	17			172
Exchanges receivable	7			5
Inventories	179			113
Other current assets	4			9
Total current assets	257			350
Property, plant and equipment	3,242			3,338
Accumulated depreciation	(355		)	(286		)
	2,887			3,052
Other non-current assets, net	153			137
Advances to affiliates	—			258
Note receivable from related party	251			574
Goodwill	285			923
Total assets	$	3,833		$	5,294

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

F - 3

PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

	December 31,
	2016		2015
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Current maturities of long-term debt	$	307	$	1
Accounts payable and accrued liabilities	11		3
Accounts payable to related companies	66		125
Exchanges payable	165		94
Accrued interest	12		12
Customer advances and deposits	9		9
Other current liabilities	40		55
Total current liabilities	610		299
Long-term debt, less current maturities	834		1,165
Deferred income taxes	711		725
Other non-current liabilities	217		222
Commitments and contingencies
Partners’ capital:
Partners’ capital	1,456		2,881
Accumulated other comprehensive income	5		2
Total partners’ capital	1,461		2,883
Total liabilities and partners’ capital	$	3,833	$	5,294

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

F - 4

PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(Dollars in millions)

	Years Ended December 31,
	2016			2015			2014
OPERATING REVENUES:
Transportation and storage of natural gas	$	496		$	528		$	555
Other	18			20			26
Total operating revenues	514			548			581
OPERATING EXPENSES:
Cost of natural gas and other energy	2			4			3
Operating and maintenance	209			216			209
General and administrative	39			42			46
Depreciation and amortization	130			133			130
Impairment losses	771			—			—
Total operating expenses	1,151			395			388
OPERATING INCOME (LOSS)	(637		)	153			193
OTHER INCOME (EXPENSE):
Interest expense, net	(49		)	(50		)	(66		)
Equity in earnings (losses) of unconsolidated affiliates	1			26			(12		)
Interest income - affiliates	26			23			23
Other, net	—			5			5
Total other income (expense), net	(22		)	4			(50		)
INCOME (LOSS) BEFORE INCOME TAX EXPENSE	(659		)	157			143
Income tax expense (benefit)	(13		)	52			182
NET INCOME (LOSS)	(646		)	105			(39		)
less: Net income (loss) attributable to noncontrolling interest	—			—			6
NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS	$	(646	)	$	105		$	(45	)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Actuarial gain (loss) relating to postretirement benefits, net of tax amounts of $0, $0, and $1, respectively	3			2			(3		)
COMPREHENSIVE INCOME (LOSS)	$	(643	)	$	107		$	(48	)

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

F - 5

PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(Dollars in millions)

	Partners’ Capital			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total
Balance, December 31, 2013	$	3,551		$	3		$	(486	)	$	3,068
Distribution to partners	(102		)	—			—			(102		)
Unit-based compensation expense	1			—			—			1
Other comprehensive loss, net of tax	—			(2		)	—			(2		)
Lake Charles LNG Transaction	(20		)	—			(23		)	(43		)
Panhandle Merger	(502		)	(1		)	503			—
Other	6			—			—			6
Net income (loss)	(45		)	—			6			(39		)
Balance, December 31, 2014	2,889			—			—			2,889
Distribution to partners	(125		)	—			—			(125		)
Unit-based compensation expense	2			—			—			2
Other comprehensive income, net of tax	—			2			—			2
Contribution to SUG Holding	(28		)	—			—			(28		)
Other	38			—			—			38
Net income	105			—			—			105
Balance, December 31, 2015	2,881			2			—			2,883
Deemed distribution to partners	(781		)	—			—			(781		)
Unit-based compensation expense	2			—			—			2
Other comprehensive income, net of tax	—			3			—			3
Net income	(646		)	—			—			(646		)
Balance, December 31, 2016	$	1,456		$	5		$	—		$	1,461

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

F - 6

PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

	Years Ended December 31,
	2016			2015			2014
OPERATING ACTIVITIES:
Net income (loss)	$	(646	)	$	105		$	(39	)
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	130			133			130
Impairment losses	771			—			—
Deferred income taxes	(21		)	31			(108		)
Amortization of deferred financing fees	(24		)	(23		)	(22		)
Unrealized gain on derivatives	—			—			(25		)
(Income) loss from unconsolidated affiliates	(1		)	(26		)	12
Distributions of earnings received from unconsolidated affiliates	—			9			6
Other non-cash	11			13			6
Changes in operating assets and liabilities	103			(66		)	197
Net cash flows provided by operating activities	323			176			157
INVESTING ACTIVITIES:
Proceeds from affiliates	—			—			20
Capital expenditures	(106		)	(128		)	(109		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	—			46			65
Repayment of note receivable from related party	49			40			—
Note receivable issued to related party	(265		)	(40		)	—
Other	—			2			(16		)
Net cash flows used in investing activities	(322		)	(80		)	(40		)
FINANCING ACTIVITIES:
Distributions to partners	—			(125		)	(102		)
Net cash flows used in financing activities	—			(125		)	(102		)
NET CHANGE IN CASH AND CASH EQUIVALENTS	1			(29		)	15
CASH AND CASH EQUIVALENTS, beginning of period	3			32			17
CASH AND CASH EQUIVALENTS, end of period	$	4		$	3		$	32

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

F - 7

PANHANDLE EASTERN PIPE LINE COMPANY, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Tabular dollar amounts are in millions)

1. OPERATIONS AND ORGANIZATION:

Panhandle Eastern Pipe Line Company, LP (“PEPL”) and its subsidiaries (the “Company”) are primarily engaged in 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 Gas Company, LLC (“Trunkline”), Sea Robin Pipeline Company, LLC (“Sea Robin”) and Pan Gas Storage LLC (“Southwest Gas”).

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

Certain prior period amounts have been reclassified to conform to the 2016 presentation. These reclassifications had no impact on net income or total equity.

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.

New Accounting Pronouncements. 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. In August 2015, the FASB deferred the effective date of ASU 2014-09, which is now effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The guidance permits two methods of adoption: retrospectively to each prior reporting period presented (full retrospective method), or retrospectively with the cumulative effect of initially applying the guidance recognized at the date of initial application (the cumulative catchup transition method). The Company expects to adopt ASU 2014-09 in the first quarter of 2018 and will apply the cumulative catchup transition method. The Company is in the process of evaluating revenue contracts by fee type to determine the potential impact of adopting the new standards. At this point the Company has determined that the timing and/or amount of revenues recognized on certain contracts may be impacted by the adoption of the new standard; however, the Company is still in the process of quantifying these impacts and cannot say whether or not they would be material to the financial statements. In addition, the Company is in the process of implementing appropriate changes to business processes, systems and controls to support recognition and disclosure under the new standard. The Company continues to monitor additional authoritative or interpretive guidance related to the new standard as it becomes available, as well as comparing to conclusions on specific interpretative issues to other industry peers, to the extent that such information is available.

F - 8

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 useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The Company is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.

In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment”. The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit's carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance does not amend the optional qualitative assessment of goodwill impairment. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. We expect that our adoption of this standard will change our approach for testing goodwill for impairment; however, this standard requires prospective application and therefore will only impact periods subsequent to adoption.

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.

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

	Years Ended December 31,
	2016		2015			2014
Non-cash investing activities:
Contribution from affiliate	$	—	$	—		$	376
Note receivable issued in exchange for investment in ETP	—		(1,369		)	—
Settlement of affiliate liability - note liability	541		793			—
Settlement of affiliate liability - tax liability	240		—			—
Supplemental cash flow information:
Accrued capital expenditures	$	15	$	21		$	15
Cash paid for interest, net of interest capitalized	75		76			75
Cash received for interest on note receivable from affiliate	40		16			—

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,
	2016		2015
Natural gas (1)	$	163	$	98
Materials and supplies	16		15
	$	179	$	113

⁽¹⁾  Natural gas volumes held for operations at December 31, 2016 and 2015 were 45.6 TBtu and 43.2 TBtu, respectively.

Natural Gas Imbalances.  Natural gas imbalances occur as a result of differences in volumes of natural gas received and delivered.  The Company records natural gas imbalance in-kind receivables and payables at cost or market, based on whether net imbalances have reduced or increased system natural gas balances, respectively.  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.

F - 9

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 Gas, 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.

Property, Plant and Equipment.

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

		December 31,
	Lives in Years	2016			2015
Land and improvements		$	8		$	8
Buildings and improvements	6 – 22	341			340
Pipelines and equipment	5 – 46	2,223			2,444
Natural gas storage facilities	5 – 46	340			329
Vehicles	5	24			24
Right of way	36 – 40	25			23
Furniture and fixtures	5 – 12	34			34
Other	2 – 19	193			99
Construction work in progress		54			37
Total property, plant and equipment		3,242			3,338
Accumulated depreciation and amortization		(355		)	(286		)
Net property, plant and equipment		$	2,887		$	3,052

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. 

Asset Impairment.  An impairment loss is recognized when the carrying amount of a long-lived asset used in operations is not recoverable and exceeds its fair value.  The carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset.  A long-lived asset is tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. In 2016, the Company recorded a $133 million impairment related to the Sea Robin reporting unit primarily due to a decrease in projected future cash flows driven by declines in commodity prices. No other fixed asset impairments were identified or recorded for our reporting units.

F - 10

Goodwill.  Goodwill resulting from a purchase business combination is tested for impairment at the Company’s reporting unit level at least annually during the fourth quarter by applying a fair-value based test.  The annual impairment test is updated if events or circumstances occur that would more likely than not reduce the fair value of the reporting unit below its book carrying value.

During the fourth quarter of 2016, the Company performed goodwill impairment tests and recognized goodwill impairments of $590 million and $48 million related to the PEPL reporting unit and the Sea Robin reporting unit, 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 determined the fair value of our 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 and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the 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 earnings 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.

The Company did not record a goodwill impairment for the years ended December 31, 2015 and 2014.

Changes in the carrying amount of goodwill were as follows:

	Total
Balance, December 31, 2014	$	1,152
ETP common units exchange transaction	(229		)
Balance, December 31, 2015	923
Impairment losses	(638		)
Balance, December 31, 2016	$	285

Related Party Transactions. Related party expenses primarily include payments for services provided by ETE, ETP 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 parent, SUG Holding Company.  The Company has entered into a tax sharing agreement with SUG Holding Company pursuant to which the Company will be required to make payments to SUG Holding Company in order to reimburse SUG Holding Company for federal and state taxes that it pays on the Company’s income, or to receive payments from SUG Holding Company to the extent that tax losses generated by the Company are utilized by SUG Holding Company.  In addition, the Company’s subsidiaries that are corporations are included in consolidated and combined federal and state income tax returns filed by SUG Holding Company.  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 SUG Holding Company, 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.  The tax sharing agreement may be amended from time to time.

Investments in Unconsolidated Affiliates. Investments in unconsolidated affiliates over which the Company may exercise significant influence are accounted for using the equity method. Any excess of the Company’s investment in affiliates, as compared to its share of the underlying equity, that is not recognized as goodwill is amortized over the estimated economic service lives of the underlying assets. Other investments over which the Company may not exercise significant influence are accounted for under the cost method. A loss in value of an investment, other than a temporary decline, is recognized in earnings.

F - 11

Evidence of a loss in value might include, but would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment or inability of the investee to sustain an earnings capacity that would justify the carrying amount of the investment. A current fair value of an investment that is less than its carrying amount may indicate a loss in value of the investment. All of the above factors are considered in the Company’s review of its equity method investments.

Other Current Liabilities. Accrued and other current liabilities consisted of the following:

	December 31,
	2016		2015
Accrued capital expenditures	$	15	$	21
Accrued property taxes	7		5
Other	18		29
Total other current liabilities	$	40	$	55

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.

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.

Amounts related to the allowance for doubtful accounts were not material as of and during the years ended December 31, 2016 and 2015.

F - 12

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,
	2016		2015		2014
Customer A	12	%	11	%	11	%
Customer B	—		10		—
Other top 10 customers	38		28		40
Remaining customers	50		51		49
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 at December 31, 2016.

Retirement Benefits.  Employers are required to recognize in their balance sheets 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.   Employers must recognize the change in the funded status of the plan in other comprehensive income in partners’ capital in the year in which the change occurs.

Derivatives and Hedging Activities.  All derivatives are recognized on the consolidated balance sheet at their fair value.  On the date the derivative contract is entered into, the Company designates the derivative as (i) a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (a fair value hedge);  (ii) a hedge of a forecasted transaction or the variability of cash flows to be received or paid in conjunction with a recognized asset or liability (a cash flow hedge); or (iii) an instrument that is held for trading or non-hedging purposes (a trading or economic hedging instrument).  For derivatives treated as a fair value hedge, the effective portion of changes in fair value is recorded as an adjustment to the hedged item.  The ineffective portion of a fair value hedge is recognized in earnings.  Upon termination of a fair value hedge of a debt instrument, the resulting gain or loss is amortized to earnings through the maturity date of the debt instrument.  For derivatives treated as a cash flow hedge, the effective portion of changes in fair value is recorded in accumulated other comprehensive income until the related hedged items impact earnings.  Any ineffective portion of a cash flow hedge is reported in current-period earnings.  For derivatives treated as trading or economic hedging instruments, changes in fair value are reported in current-period earnings.  Fair value is determined based upon quoted market prices and pricing models using assumptions that market participants would use.  

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.

F - 13

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

The Company did not have any material assets or liabilities that are measured at fair value on a recurring basis at December 31, 2016 and 2015. 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 parent. Under the Company’s tax sharing arrangement with its 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. MERGERS, DECONSOLIDATIONS AND RELATED TRANSACTIONS:

2014 Transactions

Panhandle Merger

On January 10, 2014, the Company consummated a merger with Southern Union, the indirect parent of the Company, and PEPL Holdings, the sole limited partner of the Company, pursuant to which each of Southern Union and PEPL Holdings, a wholly-owned subsidiary of Southern Union, were merged with and into the Company (the “Panhandle Merger”), with the Company surviving the Panhandle Merger. In connection with the Panhandle Merger, the Company assumed Southern Union’s obligations under its 7.6% Senior Notes due 2024, 8.25% Senior Notes due 2029 and Floating Rate Junior Subordinated Notes due 2066. At the time of the Panhandle Merger, Southern Union did not have material operations of its own, other than its ownership of the Company and noncontrolling interest in PEI Power II, LLC, Regency (31.4 million common units and 6.3 million Class F Units) and ETP (2.2 million common units). In connection with the Panhandle Merger, the Company also assumed PEPL Holdings’ guarantee of $600 million of Regency senior notes. The Company’s obligations under this guarantee were released in 2015.

F - 14

Lake Charles LNG Transaction

On February 19, 2014, PEPL transferred to ETP all of the interests in Lake Charles LNG, the entity that owns a LNG regasification facility in Lake Charles, Louisiana, in exchange for the cancellation of a $1.09 billion note payable to ETP that was assumed by the Company in the merger with Southern Union on January 10, 2014. Also on February 19, 2014, ETE and ETP completed the transfer to ETE of Lake Charles LNG from ETP in exchange for the redemption by ETP of 18.7 million ETP common units held by ETE. The transaction was effective as of January 1, 2014, at which time PEPL deconsolidated Lake Charles LNG, including goodwill of $184 million and intangible assets of $50 million related to Lake Charles LNG. The results of Lake Charles LNG’s operations have not been presented as discontinued operations and Lake Charles LNG’s assets and liabilities have not been presented as held for sale in the Company’s consolidated financial statements due to the expected continuing involvement among the entities.

4. RELATED PARTY TRANSACTIONS:

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

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

	Years Ended December 31,
	2016		2015		2014
Operating revenues	$	17	$	18	$	33
Operating and maintenance	14		16		16
General and administrative	27		31		33
Interest income — affiliates	26		23		23
Income (loss) from unconsolidated affiliates	1		26		(12		)

The following table provides a summary of distributions received from related parties:

	Years Ended December 31,
	2016		2015		2014
Distributions related to investment in:
ETP	$	—	$	39	$	9
Regency	—		16		61

As discussed in Note 5, the Company settled a note receivable from a subsidiary of ETP through a non-cash distribution during the year ended September 30, 2016.

5. INVESTMENTS IN UNCONSOLIDATED AFFILIATES:

The Company previously held an investment in Regency common units, which had been received in connection with a contribution transaction in 2013. In April 2015, ETP completed its acquisition of Regency. Under the terms of the definitive merger agreement, holders of Regency common units received 0.4066 ETP Common Units for each Regency common unit. Regency unitholders also received at closing an additional $0.32 per common unit in the form of ETP Common Units (based on the price for ETP Common Units prior to the merger closing). The Regency common units and Regency Class F units converted to 15.5 million ETP common units.

Subsequent to the Regency merger, the Company’s investment in ETP consisted of 17.8 million ETP common units, which included ETP common units already held by the Company prior to the Regency merger. This investment was accounted for using the equity method. Effective September 1, 2015, the Company exchanged these ETP common units for a note receivable from a subsidiary of ETP in the amount of $1.37 billion. The note receivable accrued interest annually at 4.75% and was due on September 1, 2035. On August 31, 2016, the remaining balance of $541 million on the note receivable and related accrued interest from a subsidiary of ETP was settled through a non-cash distribution.

F - 15

The following tables present aggregated selected balance sheet and income statement data for ETP (on a 100% basis for all periods presented).

	December 31,
	2015
Current assets	$	4,698
Property, plant and equipment, net	45,087
Other assets	15,388
Total assets	$	65,173
Current liabilities	$	4,121
Non-current liabilities	34,021
Equity	27,031
Total liabilities and equity	$	65,173

	Years Ended December 31,
	2015		2014
Revenue	$	34,292	$	55,475
Operating income	2,259		2,443
Net income	1,521		1,299

The Company has other equity method investments which are not, individually or in the aggregate, significant to our consolidated financial statements.

6. DEBT OBLIGATIONS:

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

	December 31,
	2016		2015
6.20% Senior Notes due 2017	$	300	$	300
7.00% Senior Notes due 2018	400		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		5
Unamortized fair value adjustments	51		76
Total debt outstanding	1,141		1,166
Less: Current maturities of long-term debt	307		1
Total long-term debt, less current maturities	$	834	$	1,165

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, 2016 and 2015 was $1.14 billion and $1.20 billion, 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.

F - 16

As of December 31, 2016, the Company has scheduled long-term debt principal payments as follows:

Years Ended December 31,
2017	$	300
2018	400
2019	150
2020	—
2021	—
Thereafter	240
Total	$	1,090

Assumption of Southern Union Debt

In connection with the consummation of the Panhandle Merger, PEPL assumed Southern Union’s long-term debt obligations. As of December 31, 2016, the long-term debt assumed in the Panhandle Merger consisted of $82 million in aggregate principal amount of 7.60% Senior Notes due 2024, $33 million in aggregate principal amount of 8.25% Senior Notes due 2029 and $54 million in aggregate principal amount of Floating Rate Junior Subordinated Notes due 2066 outstanding. The amounts recorded in the consolidated balance sheet also reflected unamortized fair value adjustments, which were $11 million in the aggregate at December 31, 2016.

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 3.903% at December 31, 2016.

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, 2016, the Company is in compliance with these covenants.

The Company will continue to opportunistically evaluate alternatives with regards to 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 ETP or other affiliates.

7. RETIREMENT BENEFITS:

Postretirement Benefit Plans

Postretirement benefits expense for the years ended December 31, 2016 and 2015 reflect the impact of changes the Company or its affiliates adopted as of September 30, 2013, to modify its retiree medical benefits program, effective January 1, 2014. The modification placed all eligible retirees on a common medical benefit platform, subject to limits on the Company’s annual contribution toward eligible retirees’ medical premiums. 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.

F - 17

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,
	2016			2015
Change in benefit obligation:
Benefit obligation at beginning of period	$	21		$	24
Interest cost	1			1
Actuarial (gain) loss	(1		)	(2		)
Benefits paid, net	(2		)	(2		)
Dispositions	—			—
Benefit obligation at end of period	$	19		$	21
Change in plan assets:
Fair value of plan assets at beginning of period	$	118		$	114
Return on plan assets and other	2			(1		)
Employer contributions	8			7
Benefits paid, net	(2		)	(2		)
Dispositions	—			—
Fair value of plan assets at end of period	$	126		$	118
Amount overfunded at end of period (1)	$	(107	)	$	(97	)
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial loss	$	(7	)	$	(10	)
Prior service cost	14			14
	$	7		$	4

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

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,
	2016			2015			2014
Interest cost	$	1		$	1		$	1
Expected return on plan assets	(6		)	(6		)	(5		)
Prior service credit amortization	1			1			1
Actuarial loss amortization	(1		)	(1		)	(1		)
Net periodic benefit cost	$	(5	)	$	(5	)	$	(4	)

The estimated prior service cost for other postretirement plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost during 2017 is $1 million.

Assumptions.  The weighted-average discount rate used in determining benefit obligations was 3.71% and 3.84% at December 31, 2016 and 2015, respectively.

F - 18

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,
	2016		2015		2014
Discount rate	3.88	%	3.60	%	4.29	%
Expected return on assets:
Tax exempt accounts	7.00	%	7.00	%	7.00	%
Taxable accounts	4.50	%	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,
	2016		2015
Health care cost trend rate	8.10	%	8.10	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.70	%	4.71	%
Year that the rate reaches the ultimate trend rate	2024		2021

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 the following effects:

	One Percentage Point Increase		One Percentage Point Decrease
Effect on accumulated postretirement benefit obligation	$	1	$	(1	)

Plan Assets.  The Company’s overall investment strategy is to maintain an appropriate balance of actively managed investments while maintaining a high standard of portfolio quality and achieving proper diversification.  To achieve diversity within its other postretirement plan asset portfolio, the Company has targeted the following asset allocations: equity of 25% to 35% and fixed income of 65% to 75%.  These target allocations are monitored by the Investment Committee of ETP’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.

F - 19

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

	December 31,
	2016		2015
Cash and cash equivalents	$	8	$	3
Mutual fund (1)	—		115
Target 2020 Fund  (2)	112		—
Target 2050 Fund  (3)	6		—
Total	$	126	$	118

⁽¹⁾  This fund of funds invests primarily in a diversified portfolio of equity, fixed income and short-term mutual funds. As of December 31, 2015, the fund was primarily comprised of 36% equities, 54% fixed income securities, and 10% cash.

⁽²⁾  This fund of funds invests primarily in a diversified portfolio of equity, fixed income and cash.  As of December 31, 2016, the fund was primarily comprised of 30% equities, 68% fixed income securities and 2% cash.

⁽³⁾  This fund of funds invests primarily in a diversified portfolio of equity, fixed income and cash.  As of December 31, 2016, the fund was primarily comprised of 87% equities, 10% fixed income securities and 3% cash.

The other postretirement plan assets are classified as Level 1 assets within the fair-value hierarchy as their fair values are based on active market quotes.  

Contributions.  The Company expects to make $8 million contributions to its other postretirement plans in 2017 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
2017	$	2
2018	1
2019	1
2020	1
2021	1
2022 – 2026	6

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 was eligible for such subsidies through December 31, 2013. As a result of changes the Company made to the retiree medical plan effective January 1, 2014, the Company no longer receives such subsidy payments for coverage provided after December 31, 2013.

Defined Contribution Plan

The Company participates in ETP’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.  Company contributions to the Savings Plan during the years ended December 31, 2016, 2015, and 2014 were $2 million, $2 million, and $3 million, respectively.

In addition, the Company provides a 3% discretionary profit sharing contribution to eligible employees with annual base compensation below a specific threshold.  Company contributions are 100% vested after five years of continuous service.  The Company’s discretionary profit sharing contributions during the years ended December 31, 2016, 2015, and 2014 were $1 million, $1 million, and $2 million, respectively.

F - 20

8.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,
	2016			2015		2014
Current expense (benefit):
Federal	$	8		$	21	$	258
State	—			—		32
Total	8			21		290
Deferred expense (benefit):
Federal	$	(11	)	$	17	$	(130	)
State	(10		)	14		22
Total	(21		)	31		(108		)
Total income tax expense	$	(13	)	$	52	$	182

The differences between the Company’s effective income tax rate and the U.S. federal income tax statutory rate were as follows:

	Years Ended December 31,
	2016			2015			2014
Computed statutory income tax expense (benefit) at 35%	$	(231	)	$	55		$	50
Changes in income taxes resulting from:
Premium on debt retirement	—			—			(10		)
State income taxes, net of federal income tax benefit	(6		)	9			36
Non-deductible goodwill impairment	223			—			—
Non-deductible goodwill included in the Lake Charles LNG Transaction	—			—			105
Audit settlements	—			(7		)	—
Other	1			(5		)	1
Income tax expense	$	(13	)	$	52		$	182

F - 21

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,
	2016			2015
Deferred income tax assets:
Other postretirement benefits	$	4		$	5
Debt amortization	30			57
Other	37			32
Total deferred income tax assets	71			94
Valuation allowance	(2		)	(2		)
Net deferred income tax assets (included within other non-current assets, net)	$	69		$	92
Deferred income tax liabilities:
Property, plant and equipment	$	(770	)	$	(796	)
Investment in unconsolidated affiliates	(6		)	(20		)
Other	(4		)	(1		)
Total deferred income tax liabilities	(780		)	(817		)
Net deferred income tax liability	$	(711	)	$	(725	)

As of December 31, 2016, the Company has $11 million ($6 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 and Southern Union are no longer subject to U.S. federal, state or local examinations for taxable periods prior to 2013. However, the Company and Southern Union are subject to Louisiana audits for taxable years 2013 and 2014. The issue under audit is whether to allocate or apportion the taxable gain from sale of two local distribution companies in 2013

9. DERIVATIVE ASSETS AND LIABILITIES:

The Company recognizes all derivative assets and liabilities at fair value on the consolidated balance sheets. The Company had no outstanding interest rate swap agreements as of December 31, 2016 and 2015.

The following table summarizes the location and amount (excluding income tax effects) of derivative instrument (gains) and losses reported in the Company’s consolidated financial statements:

	Years Ended December 31,
	2016	2015	2014
Economic Hedges:
Interest rate contracts:
Change in fair value — increase (decrease) in interest expense	—	—	(7	)

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 collateral under certain circumstances in order to mitigate credit risk as necessary.

F - 22

The Company’s shippers consist of a diverse portfolio of customers across the energy industry, including oil and gas producers, midstream companies, municipalities, 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.

10. 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. An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated.  Although a number of other onshore assets in the Company’s system are subject to agreements or regulations that give rise to an ARO upon the Company’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement.

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

The Company had recorded AROs related to (i) retiring natural gas storage wells, (ii) retiring offshore platforms and lines and (iii) removing asbestos. Long-lived assets related to AROs aggregated $14 million and $18 million as of December 31, 2016 and 2015, respectively, and were reflected as plant, property and equipment on our balance sheet. In addition, the Company had $13 million and $6 million legally restricted for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2016 and 2015, respectively.

The following table is a reconciliation of the carrying amount of the ARO liability reflected as liabilities on our balance sheet 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, will result in a change in the amount of the liability recognized.

	Years Ended December 31,
	2016			2015			2014
Beginning balance	$	58		$	58		$	55
Revisions	—			—			3
Settled	(7		)	(3		)	(3		)
Disposals	—			—			—
Accretion expense	3			3			3
Ending balance	$	54		$	58		$	58

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

Contingent Residual Support Agreement with ETP

In connection with the Panhandle Merger, the Company assumed Southern Union’s obligations under a contingent residual support agreement with ETP and Citrus ETP Finance LLC, pursuant to which 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 ETP to support the payment of $2.0 billion in principal amount of senior notes issued by ETP on January 17, 2012.

FERC Audit

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 audit is ongoing.

F - 23

Environmental Matters

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

The Company is responsible for environmental remediation at certain sites on its natural gas transmission systems for contamination resulting from the past use of lubricants containing 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.

Our pipeline operations are subject to regulation by the U.S. Department of Transportation under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.

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 table below reflects the amount of accrued liabilities recorded in the consolidated balance sheets at the dates indicated 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.

	December 31,
	2016		2015
Current	$	—	$	—
Non-current	2		3
Total environmental liabilities	$	2	$	3

F - 24

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, 2016 and 2015, the Company recorded litigation and other claim-related accrued liabilities of $21 million and $22 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.

12. QUARTERLY FINANCIAL DATA (UNAUDITED):

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

	Quarters Ended
	March 31, 2016		June 30, 2016		September 30, 2016		December 31, 2016			Total
Operating revenues	$	141	$	124	$	120	$	129		$	514
Operating income (loss) (1)	48		30		23		(738		)	(637		)
Net income (loss)	31		15		13		(705		)	(646		)
Net income (loss) attributable to partners	31		15		13		(705		)	(646		)
	Quarters Ended
	March 31, 2015		June 30, 2015		September 30, 2015		December 31, 2015			Total
Operating revenues	$	155	$	128	$	126	$	139		$	548
Operating income	53		31		26		43			153
Net income	31		19		25		30			105
Net income attributable to partners	31		19		25		30			105

⁽¹⁾  Operating income (loss) includes $771 million of impairment losses recognized during the fourth quarter of 2016.

F - 25

EX-12.1

Exhibit 12.1

Panhandle Eastern Pipe Line Company, LP

Computation of Ratio of Earnings to Fixed Charges

(in millions, except for ratio amounts)

(Unaudited)

The following table sets forth the consolidated ratio of earnings to fixed charges on an historical basis for the years ended December 31, 2016, 2015, 2014, 2013 and 2012. For the purpose of calculating such ratios, “earnings” consist of pre-tax income from continuing operations before income or loss from equity investees, adjusted to reflect distributed income from equity investments, and fixed charges, less capitalized interest. “Fixed charges” consist of interest costs, amortization of debt discount, premiums and issuance costs and an estimate of interest implicit in rentals. No adjustment has been made to earnings for the amortization of capital interest for the periods presented as such amount is immaterial.

On January 10, 2014, the Company consummated a merger with Southern Union, the indirect parent of the Company, and PEPL Holdings, the sole limited partner of the Company, pursuant to which each of Southern Union and PEPL Holdings, a wholly-owned subsidiary of Southern Union, were merged with and into the Company (the “Panhandle Merger”), with the Company surviving the Panhandle Merger. We have accounted for this transaction as a reorganization of entities under common control; therefore, the consolidated financial statements of the Company were retrospectively adjusted to consolidate Southern Union for all periods.

	Successor															Predecessor
	Years Ended December 31,												Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012
	2016			2015			2014			2013
Fixed Charges:
Interest expense, net	$	49		$	50		$	66		$	111		$	131		$	50
Net amortization of debt discount, premium and issuance expense	(24		)	(23		)	(22		)	(28		)	(24		)	2
Capitalized interest	1			1			2			1			1			—
Interest charges included in rental expense	1			1			1			2			5			2
Total fixed charges	$	27		$	29		$	47		$	86		$	113		$	54
Earnings:
Income (loss) from continuing operations before income tax expense and noncontrolling interest	$	(659	)	$	157		$	143		$	(472	)	$	50		$	45
Less: equity in earnings (losses) of unconsolidated affiliates	1			26			(12		)	15			(7		)	16
Total earnings	(660		)	131			155			(487		)	57			29
Add:
Fixed Charges	27			29			47			86			113			54
Distributed income of equity investees	—			55			72			54			6			—
Less:
Interest capitalized	(1		)	(1		)	(2		)	(1		)	(1		)	—
Income Available for Fixed Charges	$	(634	)	$	214		$	272		$	(348	)	$	175		$	83
Ratio of earnings to fixed charges	(a)			7.38			5.79			(b)			1.55			1.54

^{a} For the year ended December 31, 2016, fixed charges exceeded earnings by $661 million.  In 2016, Panhandle Eastern Pipe Line Company, LP recognized a $771 million impairment charge associated with the PEPL and Sea Robin reporting units.

^{b} For the year ended December 31, 2013, fixed charges exceeded earnings by $434 million.  In 2013, Panhandle Eastern Pipe Line Company, LP recognized a $689 million goodwill impairment charge associated with the Lake Charles LNG reporting unit.

EX-31.1

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 24, 2017

/s/ Kelcy L. Warren

Kelcy L. Warren

Chief Executive Officer

EX-31.2

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 24, 2017

/s/ Thomas E. Long

Thomas E. Long

Chief Financial Officer

EX-32.1

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, 2016 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 24, 2017

/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.

EX-32.2

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, 2016 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 24, 2017

/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.

XML

Document And Entity Information $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($) shares
Document Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	FY
Entity Registrant Name	Panhandle Eastern Pipe Line Co LP
Entity Central Index Key	0000076063
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float | $	$ 0
Entity Common Stock, Shares Outstanding | shares	0

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 4	$ 3
Accounts receivable, net	46	48
Accounts receivable from related companies	17	172
Exchanges receivable	7	5
Inventories	179	113
Other current assets	4	9
Total current assets	257	350
Property, plant and equipment
Total property, plant and equipment	3,242	3,338
Accumulated depreciation	(355)	(286)
Net property, plant and equipment	2,887	3,052
Other Assets, Noncurrent	153	137
Goodwill	285	923
Due from Related Parties, Noncurrent	0	258
Notes Receivable, Related Parties, Noncurrent	251	574
Total assets	3,833	5,294
Current liabilities:
Current maturities of long-term debt	307	1
Accounts payable and accrued liabilities	11	3
Accounts payable to related companies	66	125
Exchanges payable	165	94
Accrued interest	12	12
Customer Advances and Deposits, Current	9	9
Other current liabilities	40	55
Total current liabilities	610	299
Long-term debt, less current maturities	834	1,165
Deferred income taxes	711	725
ADVANCES FROM AFFILIATES	0	0
Other non-current liabilities	217	222
Commitments and contingencies
Partners’ capital:
Partners’ capital	1,456	2,881
Accumulated other comprehensive income	5	2
Total partners’ capital	1,461	2,883
Total liabilities and partners’ capital	$ 3,833	$ 5,294

XML

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
OPERATING REVENUES:
Transportation and storage of natural gas	$ 496	$ 528	$ 555
Other	18	20	26
Total operating revenues	514	548	581
OPERATING EXPENSES:
Cost of Goods Sold	2	4	3
Operating, maintenance and general	209	216	209
General and Administrative Expense	39	42	46
Depreciation and amortization	130	133	130
Asset Impairment Charges	771	0	0
Total operating expenses	1,151	395	388
Operating Income (Loss)	(637)	153	193
OTHER INCOME (EXPENSE):
Interest expense, net	(49)	(50)	(66)
Income (loss) from unconsolidated affiliates	1	26	(12)
Interest income — affiliates	26	23	23
Other, net	0	5	5
Total other expenses, net	(22)	4	(50)
Income (Loss) from Continuing Operations Before Income Tax Expense	(659)	157	143
Income tax expense	(13)	52	182
Net Income (Loss)	(646)	105	(39)
Net Income (Loss) Attributable to Noncontrolling Interest	0	0	6
Net Income (Loss) Attributable to Partners	(646)	105	(45)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax	3	2	(3)
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ (643)	$ 107	$ (48)

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement of Income and Comprehensive Income [Line Items]
Net income (loss)	$ (705)	$ 13	$ 15	$ 31	$ 30	$ 25	$ 19	$ 31	$ (646)	$ 105	$ (39)
Other comprehensive income (loss), net of tax:
Actuarial gain (loss) relating to postretirement benefits, net of tax amounts of $__, $0, and $1, respectively									3	2	(3)
Comprehensive Income (Loss), Net of Tax, Attributable to Parent									$ (643)	$ 107	$ (48)

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Income Taxes - Actuarial Gain Loss - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Tax	$ 0	$ 0	$ 1

XML

CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL - USD ($) $ in Millions	Total	Trunkline LNG Transaction [Member]	Panhandle Merger [Member]	Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Income (Loss) Trunkline LNG Transaction [Member]	Accumulated Other Comprehensive Income (Loss) Panhandle Merger [Member]	Noncontrolling Interest [Member]	Noncontrolling Interest [Member] Trunkline LNG Transaction [Member]	Noncontrolling Interest [Member] Panhandle Merger [Member]	Limited Partner [Member]	Limited Partner [Member] Trunkline LNG Transaction [Member]	Limited Partner [Member] Panhandle Merger [Member]
Balance at Dec. 31, 2013	$ 3,068			$ 3			$ (486)			$ 3,551
Other comprehensive income, net of tax	(2)			(2)			0			0
Net income (loss)	(39)			0			6			(45)
Distribution to partners	(102)			0			0			(102)
Unit-based compensation expense	1			0			0			1
Panhandle Merger	(6)	$ 43	$ 0	0	$ 0	$ (1)	0	$ (23)	$ 503	6	$ (20)	$ (502)
Balance at Dec. 31, 2014	2,889			0			0			2,889
Other comprehensive income, net of tax	2			2			0			0
Net income (loss)	105			0			0			105
Distribution to partners	(125)			0			0			(125)
Unit-based compensation expense	2			0			0			2
Panhandle Merger	(38)			0			0			38
Contribution to SUG Holding	(28)			0			0			28
Balance at Dec. 31, 2015	2,883			2			0			2,881
Other comprehensive income, net of tax	3			3			0			0
Net income (loss)	(646)			0			0			(646)
Distribution to partners	(781)			0			0			(781)
Unit-based compensation expense	2			0			0			2
Balance at Dec. 31, 2016	$ 1,461			$ 5			$ 0			$ 1,456

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
OPERATING ACTIVITIES:
Net income (loss)	$ (646)	$ 105	$ (39)
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	130	133	130
Goodwill Impairment	771	0	0
Deferred income taxes	(21)	31	(108)
Amortization of deferred financing fees	(24)	(23)	(22)
Unrealized gain on derivatives	0	0	(25)
(Income) loss from unconsolidated affiliates	(1)	(26)	12
Distributions of earnings received from unconsolidated affiliates	0	9	6
Other non-cash	11	13	6
Changes in operating assets and liabilities	103	(66)	197
Net cash flows provided by operating activities	323	176	157
INVESTING ACTIVITIES:
Proceeds from SUGS Contribution	0	0	20
Proceeds from affiliates	49	40	0
Increase (Decrease) in Notes Receivable, Related Parties, Current	(265)	(40)	0
Capital expenditures	(106)	(128)	(109)
Distributions from unconsolidated affiliates in excess of cumulative earnings	0	46	65
Other	0	2	(16)
Net cash flows (used in) provided by investing activities	(322)	(80)	(40)
FINANCING ACTIVITIES:
Distribution Made to Limited Partner, Cash Distributions Paid	0	125	102
Net cash flows used in financing activities	0	(125)	(102)
NET CHANGE IN CASH AND CASH EQUIVALENTS	1	(29)	15
CASH AND CASH EQUIVALENTS, beginning of period	3	32	17
CASH AND CASH EQUIVALENTS, end of period	$ 4	$ 3	$ 32

XML

Description of the Business

12 Months Ended

Dec. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Description of the Business

OPERATIONS AND ORGANIZATION:

Panhandle Eastern Pipe Line Company, LP (“PEPL”) and its subsidiaries (the “Company”) are primarily engaged in 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 Gas Company, LLC (“Trunkline”), Sea Robin Pipeline Company, LLC (“Sea Robin”) and Pan Gas Storage LLC (“Southwest Gas”).

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

Certain prior period amounts have been reclassified to conform to the 2016 presentation. These reclassifications had no impact on net income or total equity.

XML

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

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.

New Accounting Pronouncements. 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. In August 2015, the FASB deferred the effective date of ASU 2014-09, which is now effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The guidance permits two methods of adoption: retrospectively to each prior reporting period presented (full retrospective method), or retrospectively with the cumulative effect of initially applying the guidance recognized at the date of initial application (the cumulative catchup transition method). The Company expects to adopt ASU 2014-09 in the first quarter of 2018 and will apply the cumulative catchup transition method. The Company is in the process of evaluating revenue contracts by fee type to determine the potential impact of adopting the new standards. At this point the Company has determined that the timing and/or amount of revenues recognized on certain contracts may be impacted by the adoption of the new standard; however, the Company is still in the process of quantifying these impacts and cannot say whether or not they would be material to the financial statements. In addition, the Company is in the process of implementing appropriate changes to business processes, systems and controls to support recognition and disclosure under the new standard. The Company continues to monitor additional authoritative or interpretive guidance related to the new standard as it becomes available, as well as comparing to conclusions on specific interpretative issues to other industry peers, to the extent that such information is available.

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 useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The Company is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.

In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment”. The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit's carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance does not amend the optional qualitative assessment of goodwill impairment. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. We expect that our adoption of this standard will change our approach for testing goodwill for impairment; however, this standard requires prospective application and therefore will only impact periods subsequent to adoption.

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.

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

	Years Ended December 31,
	2016		2015			2014
Non-cash investing activities:
Contribution from affiliate	$	—	$	—		$	376
Note receivable issued in exchange for investment in ETP	—		(1,369		)	—
Settlement of affiliate liability - note liability	541		793			—
Settlement of affiliate liability - tax liability	240		—			—
Supplemental cash flow information:
Accrued capital expenditures	$	15	$	21		$	15
Cash paid for interest, net of interest capitalized	75		76			75
Cash received for interest on note receivable from affiliate	40		16			—

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,
	2016		2015
Natural gas (1)	$	163	$	98
Materials and supplies	16		15
	$	179	$	113

⁽¹⁾  Natural gas volumes held for operations at December 31, 2016 and 2015 were 45.6 TBtu and 43.2 TBtu, respectively.

Natural Gas Imbalances.  Natural gas imbalances occur as a result of differences in volumes of natural gas received and delivered.  The Company records natural gas imbalance in-kind receivables and payables at cost or market, based on whether net imbalances have reduced or increased system natural gas balances, respectively.  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 Gas, 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.

Property, Plant and Equipment.

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

		December 31,
	Lives in Years	2016			2015
Land and improvements		$	8		$	8
Buildings and improvements	6 – 22	341			340
Pipelines and equipment	5 – 46	2,223			2,444
Natural gas storage facilities	5 – 46	340			329
Vehicles	5	24			24
Right of way	36 – 40	25			23
Furniture and fixtures	5 – 12	34			34
Other	2 – 19	193			99
Construction work in progress		54			37
Total property, plant and equipment		3,242			3,338
Accumulated depreciation and amortization		(355		)	(286		)
Net property, plant and equipment		$	2,887		$	3,052

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. 

Asset Impairment.  An impairment loss is recognized when the carrying amount of a long-lived asset used in operations is not recoverable and exceeds its fair value.  The carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset.  A long-lived asset is tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. In 2016, the Company recorded a $133 million impairment related to the Sea Robin reporting unit primarily due to a decrease in projected future cash flows driven by declines in commodity prices. No other fixed asset impairments were identified or recorded for our reporting units.

Goodwill.  Goodwill resulting from a purchase business combination is tested for impairment at the Company’s reporting unit level at least annually during the fourth quarter by applying a fair-value based test.  The annual impairment test is updated if events or circumstances occur that would more likely than not reduce the fair value of the reporting unit below its book carrying value.

During the fourth quarter of 2016, the Company performed goodwill impairment tests and recognized goodwill impairments of $590 million and $48 million related to the PEPL reporting unit and the Sea Robin reporting unit, 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 determined the fair value of our 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 and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the 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 earnings 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.

The Company did not record a goodwill impairment for the years ended December 31, 2015 and 2014.

Changes in the carrying amount of goodwill were as follows:

	Total
Balance, December 31, 2014	$	1,152
ETP common units exchange transaction	(229		)
Balance, December 31, 2015	923
Impairment losses	(638		)
Balance, December 31, 2016	$	285

Related Party Transactions. Related party expenses primarily include payments for services provided by ETE, ETP 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 parent, SUG Holding Company.  The Company has entered into a tax sharing agreement with SUG Holding Company pursuant to which the Company will be required to make payments to SUG Holding Company in order to reimburse SUG Holding Company for federal and state taxes that it pays on the Company’s income, or to receive payments from SUG Holding Company to the extent that tax losses generated by the Company are utilized by SUG Holding Company.  In addition, the Company’s subsidiaries that are corporations are included in consolidated and combined federal and state income tax returns filed by SUG Holding Company.  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 SUG Holding Company, 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.  The tax sharing agreement may be amended from time to time.

Investments in Unconsolidated Affiliates. Investments in unconsolidated affiliates over which the Company may exercise significant influence are accounted for using the equity method. Any excess of the Company’s investment in affiliates, as compared to its share of the underlying equity, that is not recognized as goodwill is amortized over the estimated economic service lives of the underlying assets. Other investments over which the Company may not exercise significant influence are accounted for under the cost method. A loss in value of an investment, other than a temporary decline, is recognized in earnings. Evidence of a loss in value might include, but would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment or inability of the investee to sustain an earnings capacity that would justify the carrying amount of the investment. A current fair value of an investment that is less than its carrying amount may indicate a loss in value of the investment. All of the above factors are considered in the Company’s review of its equity method investments.

Other Current Liabilities. Accrued and other current liabilities consisted of the following:

	December 31,
	2016		2015
Accrued capital expenditures	$	15	$	21
Accrued property taxes	7		5
Other	18		29
Total other current liabilities	$	40	$	55

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.

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.

Amounts related to the allowance for doubtful accounts were not material as of and during the years ended December 31, 2016 and 2015.

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,
	2016		2015		2014
Customer A	12	%	11	%	11	%
Customer B	—		10		—
Other top 10 customers	38		28		40
Remaining customers	50		51		49
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 at December 31, 2016.

Retirement Benefits.  Employers are required to recognize in their balance sheets 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.   Employers must recognize the change in the funded status of the plan in other comprehensive income in partners’ capital in the year in which the change occurs.

Derivatives and Hedging Activities.  All derivatives are recognized on the consolidated balance sheet at their fair value.  On the date the derivative contract is entered into, the Company designates the derivative as (i) a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (a fair value hedge);  (ii) a hedge of a forecasted transaction or the variability of cash flows to be received or paid in conjunction with a recognized asset or liability (a cash flow hedge); or (iii) an instrument that is held for trading or non-hedging purposes (a trading or economic hedging instrument).  For derivatives treated as a fair value hedge, the effective portion of changes in fair value is recorded as an adjustment to the hedged item.  The ineffective portion of a fair value hedge is recognized in earnings.  Upon termination of a fair value hedge of a debt instrument, the resulting gain or loss is amortized to earnings through the maturity date of the debt instrument.  For derivatives treated as a cash flow hedge, the effective portion of changes in fair value is recorded in accumulated other comprehensive income until the related hedged items impact earnings.  Any ineffective portion of a cash flow hedge is reported in current-period earnings.  For derivatives treated as trading or economic hedging instruments, changes in fair value are reported in current-period earnings.  Fair value is determined based upon quoted market prices and pricing models using assumptions that market participants would use.  

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

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

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

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

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

The Company did not have any material assets or liabilities that are measured at fair value on a recurring basis at December 31, 2016 and 2015. 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 parent. Under the Company’s tax sharing arrangement with its 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.

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Mergers and Other Transactions

12 Months Ended

Dec. 31, 2016

Business Combinations [Abstract]

Business Combinations Disclosure

MERGERS, DECONSOLIDATIONS AND RELATED TRANSACTIONS:

2014 Transactions

Panhandle Merger

On January 10, 2014, the Company consummated a merger with Southern Union, the indirect parent of the Company, and PEPL Holdings, the sole limited partner of the Company, pursuant to which each of Southern Union and PEPL Holdings, a wholly-owned subsidiary of Southern Union, were merged with and into the Company (the “Panhandle Merger”), with the Company surviving the Panhandle Merger. In connection with the Panhandle Merger, the Company assumed Southern Union’s obligations under its 7.6% Senior Notes due 2024, 8.25% Senior Notes due 2029 and Floating Rate Junior Subordinated Notes due 2066. At the time of the Panhandle Merger, Southern Union did not have material operations of its own, other than its ownership of the Company and noncontrolling interest in PEI Power II, LLC, Regency (31.4 million common units and 6.3 million Class F Units) and ETP (2.2 million common units). In connection with the Panhandle Merger, the Company also assumed PEPL Holdings’ guarantee of $600 million of Regency senior notes. The Company’s obligations under this guarantee were released in 2015.

Lake Charles LNG Transaction

On February 19, 2014, PEPL transferred to ETP all of the interests in Lake Charles LNG, the entity that owns a LNG regasification facility in Lake Charles, Louisiana, in exchange for the cancellation of a $1.09 billion note payable to ETP that was assumed by the Company in the merger with Southern Union on January 10, 2014. Also on February 19, 2014, ETE and ETP completed the transfer to ETE of Lake Charles LNG from ETP in exchange for the redemption by ETP of 18.7 million ETP common units held by ETE. The transaction was effective as of January 1, 2014, at which time PEPL deconsolidated Lake Charles LNG, including goodwill of $184 million and intangible assets of $50 million related to Lake Charles LNG. The results of Lake Charles LNG’s operations have not been presented as discontinued operations and Lake Charles LNG’s assets and liabilities have not been presented as held for sale in the Company’s consolidated financial statements due to the expected continuing involvement among the entities.

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Related Party Transactions

12 Months Ended

Dec. 31, 2016

Related Party Transactions [Abstract]

Related Party Transactions

RELATED PARTY TRANSACTIONS:

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

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

	Years Ended December 31,
	2016		2015		2014
Operating revenues	$	17	$	18	$	33
Operating and maintenance	14		16		16
General and administrative	27		31		33
Interest income — affiliates	26		23		23
Income (loss) from unconsolidated affiliates	1		26		(12		)

The following table provides a summary of distributions received from related parties:

	Years Ended December 31,
	2016		2015		2014
Distributions related to investment in:
ETP	$	—	$	39	$	9
Regency	—		16		61

As discussed in Note 5, the Company settled a note receivable from a subsidiary of ETP through a non-cash distribution during the year ended September 30, 2016.

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INVESTMENTS IN UNCONSOLIDATED AFFILIATES INVESTMENTS IN UNCONSOLIDATED AFFILIATES (Notes)

12 Months Ended

Dec. 31, 2016

Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]

Investments in and Advances to Affiliates, Schedule of Investments [Text Block]

e Company previously held an investment in Regency common units, which had been received in connection with a contribution transaction in 2013. In April 2015, ETP completed its acquisition of Regency. Under the terms of the definitive merger agreement, holders of Regency common units received 0.4066 ETP Common Units for each Regency common unit. Regency unitholders also received at closing an additional $0.32 per common unit in the form of ETP Common Units (based on the price for ETP Common Units prior to the merger closing). The Regency common units and Regency Class F units converted to 15.5 million ETP common units.

Subsequent to the Regency merger, the Company’s investment in ETP consisted of 17.8 million ETP common units, which included ETP common units already held by the Company prior to the Regency merger. This investment was accounted for using the equity method. Effective September 1, 2015, the Company exchanged these ETP common units for a note receivable from a subsidiary of ETP in the amount of $1.37 billion. The note receivable accrued interest annually at 4.75% and was due on September 1, 2035. On August 31, 2016, the remaining balance of $541 million on the note receivable and related accrued interest from a subsidiary of ETP was settled through a non-cash distribution.

The following tables present aggregated selected balance sheet and income statement data for ETP (on a 100% basis for all periods presented).

	December 31,
	2015
Current assets	$	4,698
Property, plant and equipment, net	45,087
Other assets	15,388
Total assets	$	65,173
Current liabilities	$	4,121
Non-current liabilities	34,021
Equity	27,031
Total liabilities and equity	$	65,173

	Years Ended December 31,
	2015		2014
Revenue	$	34,292	$	55,475
Operating income	2,259		2,443
Net income	1,521		1,299

The Company has other equity method investments which are not, individually or in the aggregate, significant to our consolidated financial statements.

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Debt Obligations

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

Debt Obligations

DEBT OBLIGATIONS:

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

	December 31,
	2016		2015
6.20% Senior Notes due 2017	$	300	$	300
7.00% Senior Notes due 2018	400		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		5
Unamortized fair value adjustments	51		76
Total debt outstanding	1,141		1,166
Less: Current maturities of long-term debt	307		1
Total long-term debt, less current maturities	$	834	$	1,165

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, 2016 and 2015 was $1.14 billion and $1.20 billion, 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, 2016, the Company has scheduled long-term debt principal payments as follows:

Years Ended December 31,
2017	$	300
2018	400
2019	150
2020	—
2021	—
Thereafter	240
Total	$	1,090

Assumption of Southern Union Debt

In connection with the consummation of the Panhandle Merger, PEPL assumed Southern Union’s long-term debt obligations. As of December 31, 2016, the long-term debt assumed in the Panhandle Merger consisted of $82 million in aggregate principal amount of 7.60% Senior Notes due 2024, $33 million in aggregate principal amount of 8.25% Senior Notes due 2029 and $54 million in aggregate principal amount of Floating Rate Junior Subordinated Notes due 2066 outstanding. The amounts recorded in the consolidated balance sheet also reflected unamortized fair value adjustments, which were $11 million in the aggregate at December 31, 2016.

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 3.903% at December 31, 2016.

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, 2016, the Company is in compliance with these covenants.

The Company will continue to opportunistically evaluate alternatives with regards to 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 ETP or other affiliates.

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Benefits

12 Months Ended

Dec. 31, 2016

Postemployment Benefits [Abstract]

Benefits

RETIREMENT BENEFITS:

Postretirement Benefit Plans

Postretirement benefits expense for the years ended December 31, 2016 and 2015 reflect the impact of changes the Company or its affiliates adopted as of September 30, 2013, to modify its retiree medical benefits program, effective January 1, 2014. The modification placed all eligible retirees on a common medical benefit platform, subject to limits on the Company’s annual contribution toward eligible retirees’ medical premiums. 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.

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,
	2016			2015
Change in benefit obligation:
Benefit obligation at beginning of period	$	21		$	24
Interest cost	1			1
Actuarial (gain) loss	(1		)	(2		)
Benefits paid, net	(2		)	(2		)
Dispositions	—			—
Benefit obligation at end of period	$	19		$	21
Change in plan assets:
Fair value of plan assets at beginning of period	$	118		$	114
Return on plan assets and other	2			(1		)
Employer contributions	8			7
Benefits paid, net	(2		)	(2		)
Dispositions	—			—
Fair value of plan assets at end of period	$	126		$	118
Amount overfunded at end of period (1)	$	(107	)	$	(97	)
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial loss	$	(7	)	$	(10	)
Prior service cost	14			14
	$	7		$	4

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

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,
	2016			2015			2014
Interest cost	$	1		$	1		$	1
Expected return on plan assets	(6		)	(6		)	(5		)
Prior service credit amortization	1			1			1
Actuarial loss amortization	(1		)	(1		)	(1		)
Net periodic benefit cost	$	(5	)	$	(5	)	$	(4	)

The estimated prior service cost for other postretirement plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost during 2017 is $1 million.

Assumptions.  The weighted-average discount rate used in determining benefit obligations was 3.71% and 3.84% at December 31, 2016 and 2015, 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,
	2016		2015		2014
Discount rate	3.88	%	3.60	%	4.29	%
Expected return on assets:
Tax exempt accounts	7.00	%	7.00	%	7.00	%
Taxable accounts	4.50	%	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,
	2016		2015
Health care cost trend rate	8.10	%	8.10	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.70	%	4.71	%
Year that the rate reaches the ultimate trend rate	2024		2021

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 the following effects:

	One Percentage Point Increase		One Percentage Point Decrease
Effect on accumulated postretirement benefit obligation	$	1	$	(1	)

Plan Assets.  The Company’s overall investment strategy is to maintain an appropriate balance of actively managed investments while maintaining a high standard of portfolio quality and achieving proper diversification.  To achieve diversity within its other postretirement plan asset portfolio, the Company has targeted the following asset allocations: equity of 25% to 35% and fixed income of 65% to 75%.  These target allocations are monitored by the Investment Committee of ETP’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,
	2016		2015
Cash and cash equivalents	$	8	$	3
Mutual fund (1)	—		115
Target 2020 Fund  (2)	112		—
Target 2050 Fund  (3)	6		—
Total	$	126	$	118

⁽¹⁾  This fund of funds invests primarily in a diversified portfolio of equity, fixed income and short-term mutual funds. As of December 31, 2015, the fund was primarily comprised of 36% equities, 54% fixed income securities, and 10% cash.

⁽²⁾  This fund of funds invests primarily in a diversified portfolio of equity, fixed income and cash.  As of December 31, 2016, the fund was primarily comprised of 30% equities, 68% fixed income securities and 2% cash.

⁽³⁾  This fund of funds invests primarily in a diversified portfolio of equity, fixed income and cash.  As of December 31, 2016, the fund was primarily comprised of 87% equities, 10% fixed income securities and 3% cash.

The other postretirement plan assets are classified as Level 1 assets within the fair-value hierarchy as their fair values are based on active market quotes.  

Contributions.  The Company expects to make $8 million contributions to its other postretirement plans in 2017 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
2017	$	2
2018	1
2019	1
2020	1
2021	1
2022 – 2026	6

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 was eligible for such subsidies through December 31, 2013. As a result of changes the Company made to the retiree medical plan effective January 1, 2014, the Company no longer receives such subsidy payments for coverage provided after December 31, 2013.

Defined Contribution Plan

The Company participates in ETP’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.  Company contributions to the Savings Plan during the years ended December 31, 2016, 2015, and 2014 were $2 million, $2 million, and $3 million, respectively.

In addition, the Company provides a 3% discretionary profit sharing contribution to eligible employees with annual base compensation below a specific threshold.  Company contributions are 100% vested after five years of continuous service.  The Company’s discretionary profit sharing contributions during the years ended December 31, 2016, 2015, and 2014 were $1 million, $1 million, and $2 million, respectively.

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Taxes on Income

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

Taxes on Income

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,
	2016			2015		2014
Current expense (benefit):
Federal	$	8		$	21	$	258
State	—			—		32
Total	8			21		290
Deferred expense (benefit):
Federal	$	(11	)	$	17	$	(130	)
State	(10		)	14		22
Total	(21		)	31		(108		)
Total income tax expense	$	(13	)	$	52	$	182

The differences between the Company’s effective income tax rate and the U.S. federal income tax statutory rate were as follows:

	Years Ended December 31,
	2016			2015			2014
Computed statutory income tax expense (benefit) at 35%	$	(231	)	$	55		$	50
Changes in income taxes resulting from:
Premium on debt retirement	—			—			(10		)
State income taxes, net of federal income tax benefit	(6		)	9			36
Non-deductible goodwill impairment	223			—			—
Non-deductible goodwill included in the Lake Charles LNG Transaction	—			—			105
Audit settlements	—			(7		)	—
Other	1			(5		)	1
Income tax expense	$	(13	)	$	52		$	182

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,
	2016			2015
Deferred income tax assets:
Other postretirement benefits	$	4		$	5
Debt amortization	30			57
Other	37			32
Total deferred income tax assets	71			94
Valuation allowance	(2		)	(2		)
Net deferred income tax assets (included within other non-current assets, net)	$	69		$	92
Deferred income tax liabilities:
Property, plant and equipment	$	(770	)	$	(796	)
Investment in unconsolidated affiliates	(6		)	(20		)
Other	(4		)	(1		)
Total deferred income tax liabilities	(780		)	(817		)
Net deferred income tax liability	$	(711	)	$	(725	)

As of December 31, 2016, the Company has $11 million ($6 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 and Southern Union are no longer subject to U.S. federal, state or local examinations for taxable periods prior to 2013. However, the Company and Southern Union are subject to Louisiana audits for taxable years 2013 and 2014. The issue under audit is whether to allocate or apportion the taxable gain from sale of two local distribution companies in 2013

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Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

ASSETS AND LIABILITIES:

The Company recognizes all derivative assets and liabilities at fair value on the consolidated balance sheets. The Company had no outstanding interest rate swap agreements as of December 31, 2016 and 2015.

The following table summarizes the location and amount (excluding income tax effects) of derivative instrument (gains) and losses reported in the Company’s consolidated financial statements:

	Years Ended December 31,
	2016	2015	2014
Economic Hedges:
Interest rate contracts:
Change in fair value — increase (decrease) in interest expense	—	—	(7	)

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 collateral 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, utilities, and commercial and industrial end users. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that could impact our shippers to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of shipper non-performance.

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ASSET RETIREMENT OBLIGATIONS

12 Months Ended

Dec. 31, 2016

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

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. An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated.  Although a number of other onshore assets in the Company’s system are subject to agreements or regulations that give rise to an ARO upon the Company’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement.

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

The Company had recorded AROs related to (i) retiring natural gas storage wells, (ii) retiring offshore platforms and lines and (iii) removing asbestos. Long-lived assets related to AROs aggregated $14 million and $18 million as of December 31, 2016 and 2015, respectively, and were reflected as plant, property and equipment on our balance sheet. In addition, the Company had $13 million and $6 million legally restricted for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2016 and 2015, respectively.

The following table is a reconciliation of the carrying amount of the ARO liability reflected as liabilities on our balance sheet 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, will result in a change in the amount of the liability recognized.

	Years Ended December 31,
	2016			2015			2014
Beginning balance	$	58		$	58		$	55
Revisions	—			—			3
Settled	(7		)	(3		)	(3		)
Disposals	—			—			—
Accretion expense	3			3			3
Ending balance	$	54		$	58		$	58

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies [Abstract]

Commitments and Contingencies Disclosure

REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:

Contingent Residual Support Agreement with ETP

In connection with the Panhandle Merger, the Company assumed Southern Union’s obligations under a contingent residual support agreement with ETP and Citrus ETP Finance LLC, pursuant to which 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 ETP to support the payment of $2.0 billion in principal amount of senior notes issued by ETP on January 17, 2012.

FERC Audit

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 audit is ongoing.

Environmental Matters

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

The Company is responsible for environmental remediation at certain sites on its natural gas transmission systems for contamination resulting from the past use of lubricants containing 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.

Our pipeline operations are subject to regulation by the U.S. Department of Transportation under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.

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 table below reflects the amount of accrued liabilities recorded in the consolidated balance sheets at the dates indicated 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.

	December 31,
	2016		2015
Current	$	—	$	—
Non-current	2		3
Total environmental liabilities	$	2	$	3

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, 2016 and 2015, the Company recorded litigation and other claim-related accrued liabilities of $21 million and $22 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.

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QUARTERLY OPERATIONS

12 Months Ended

Dec. 31, 2016

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information [Text Block]

QUARTERLY FINANCIAL DATA (UNAUDITED):

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

	Quarters Ended
	March 31, 2016		June 30, 2016		September 30, 2016		December 31, 2016			Total
Operating revenues	$	141	$	124	$	120	$	129		$	514
Operating income (loss) (1)	48		30		23		(738		)	(637		)
Net income (loss)	31		15		13		(705		)	(646		)
Net income (loss) attributable to partners	31		15		13		(705		)	(646		)
	Quarters Ended
	March 31, 2015		June 30, 2015		September 30, 2015		December 31, 2015			Total
Operating revenues	$	155	$	128	$	126	$	139		$	548
Operating income	53		31		26		43			153
Net income	31		19		25		30			105
Net income attributable to partners	31		19		25		30			105

⁽¹⁾  Operating income (loss) includes $771 million of impairment losses recognized during the fourth quarter of 2016.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Basis of Presentation and Significant Accounting Policies [Policy Text Block]

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.

Consolidation, Policy [Policy Text Block]

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

Use of Estimates, Policy [Policy Text Block]

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.

New Accounting Pronouncements, Policy [Policy Text Block]

New Accounting Pronouncements. 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. In August 2015, the FASB deferred the effective date of ASU 2014-09, which is now effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The guidance permits two methods of adoption: retrospectively to each prior reporting period presented (full retrospective method), or retrospectively with the cumulative effect of initially applying the guidance recognized at the date of initial application (the cumulative catchup transition method). The Company expects to adopt ASU 2014-09 in the first quarter of 2018 and will apply the cumulative catchup transition method. The Company is in the process of evaluating revenue contracts by fee type to determine the potential impact of adopting the new standards. At this point the Company has determined that the timing and/or amount of revenues recognized on certain contracts may be impacted by the adoption of the new standard; however, the Company is still in the process of quantifying these impacts and cannot say whether or not they would be material to the financial statements. In addition, the Company is in the process of implementing appropriate changes to business processes, systems and controls to support recognition and disclosure under the new standard. The Company continues to monitor additional authoritative or interpretive guidance related to the new standard as it becomes available, as well as comparing to conclusions on specific interpretative issues to other industry peers, to the extent that such information is available.

Cash and Cash Equivalents, Policy [Policy Text Block]

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.

Inventory, Policy [Policy Text Block]

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.

Natural Gas Exchanges [Policy Text Block]

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, based on whether net imbalances have reduced or increased system natural gas balances, respectively.  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 [Policy Text Block]

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 Gas, 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.

Property, Plant and Equipment, Policy [Policy Text Block]

Property, Plant and Equipment.

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

		December 31,
	Lives in Years	2016			2015
Land and improvements		$	8		$	8
Buildings and improvements	6 – 22	341			340
Pipelines and equipment	5 – 46	2,223			2,444
Natural gas storage facilities	5 – 46	340			329
Vehicles	5	24			24
Right of way	36 – 40	25			23
Furniture and fixtures	5 – 12	34			34
Other	2 – 19	193			99
Construction work in progress		54			37
Total property, plant and equipment		3,242			3,338
Accumulated depreciation and amortization		(355		)	(286		)
Net property, plant and equipment		$	2,887		$	3,052

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. 

Impairment or Disposal of Long-Lived Assets, Policy [Policy Text Block]

Asset Impairment.  An impairment loss is recognized when the carrying amount of a long-lived asset used in operations is not recoverable and exceeds its fair value.  The carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset.  A long-lived asset is tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable.

Goodwill and Intangible Assets, Policy [Policy Text Block]

Goodwill.  Goodwill resulting from a purchase business combination is tested for impairment at the Company’s reporting unit level at least annually during the fourth quarter by applying a fair-value based test.  The annual impairment test is updated if events or circumstances occur that would more likely than not reduce the fair value of the reporting unit below its book carrying value.

During the fourth quarter of 2016, the Company performed goodwill impairment tests and recognized goodwill impairments of $590 million and $48 million related to the PEPL reporting unit and the Sea Robin reporting unit, 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 determined the fair value of our 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 and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the 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 earnings 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.

The Company did not record a goodwill impairment for the years ended December 31, 2015 and 2014.

Changes in the carrying amount of goodwill were as follows:

	Total
Balance, December 31, 2014	$	1,152
ETP common units exchange transaction	(229		)
Balance, December 31, 2015	923
Impairment losses	(638		)
Balance, December 31, 2016	$	285

Related Party Transactions Disclosure [Policy Text Block]

Related Party Transactions. Related party expenses primarily include payments for services provided by ETE, ETP 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 parent, SUG Holding Company.  The Company has entered into a tax sharing agreement with SUG Holding Company pursuant to which the Company will be required to make payments to SUG Holding Company in order to reimburse SUG Holding Company for federal and state taxes that it pays on the Company’s income, or to receive payments from SUG Holding Company to the extent that tax losses generated by the Company are utilized by SUG Holding Company.  In addition, the Company’s subsidiaries that are corporations are included in consolidated and combined federal and state income tax returns filed by SUG Holding Company.  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 SUG Holding Company, 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.  The tax sharing agreement may be amended from time to time.

Equity Method Investments, Policy [Policy Text Block]

Investments in Unconsolidated Affiliates. Investments in unconsolidated affiliates over which the Company may exercise significant influence are accounted for using the equity method. Any excess of the Company’s investment in affiliates, as compared to its share of the underlying equity, that is not recognized as goodwill is amortized over the estimated economic service lives of the underlying assets. Other investments over which the Company may not exercise significant influence are accounted for under the cost method. A loss in value of an investment, other than a temporary decline, is recognized in earnings. Evidence of a loss in value might include, but would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment or inability of the investee to sustain an earnings capacity that would justify the carrying amount of the investment. A current fair value of an investment that is less than its carrying amount may indicate a loss in value of the investment. All of the above factors are considered in the Company’s review of its equity method investments.

Environmental Cost, Expense Policy [Policy Text Block]

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.

Revenue Recognition, Policy [Policy Text Block]

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.

Receivables, Trade and Other Accounts Receivable, Allowance for Doubtful Accounts, Policy [Policy Text Block]

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.

Amounts related to the allowance for doubtful accounts were not material as of and during the years ended December 31, 2016 and 2015.

Accumulated Other Comprehensive Loss [Policy Text Block]

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

Pension and Other Postretirement Plans, Policy [Policy Text Block]

Retirement Benefits.  Employers are required to recognize in their balance sheets 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.   Employers must recognize the change in the funded status of the plan in other comprehensive income in partners’ capital in the year in which the change occurs.

Derivatives, Policy [Policy Text Block]

Derivatives and Hedging Activities.  All derivatives are recognized on the consolidated balance sheet at their fair value.  On the date the derivative contract is entered into, the Company designates the derivative as (i) a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (a fair value hedge);  (ii) a hedge of a forecasted transaction or the variability of cash flows to be received or paid in conjunction with a recognized asset or liability (a cash flow hedge); or (iii) an instrument that is held for trading or non-hedging purposes (a trading or economic hedging instrument).  For derivatives treated as a fair value hedge, the effective portion of changes in fair value is recorded as an adjustment to the hedged item.  The ineffective portion of a fair value hedge is recognized in earnings.  Upon termination of a fair value hedge of a debt instrument, the resulting gain or loss is amortized to earnings through the maturity date of the debt instrument.  For derivatives treated as a cash flow hedge, the effective portion of changes in fair value is recorded in accumulated other comprehensive income until the related hedged items impact earnings.  Any ineffective portion of a cash flow hedge is reported in current-period earnings.  For derivatives treated as trading or economic hedging instruments, changes in fair value are reported in current-period earnings.  Fair value is determined based upon quoted market prices and pricing models using assumptions that market participants would use.  

Fair Value of Financial Instruments, Policy [Policy Text Block]

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.

Asset Retirement Obligations, Policy [Policy Text Block]

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 Tax, Policy [Policy Text Block]

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 parent. Under the Company’s tax sharing arrangement with its 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, Policy [Policy Text Block]

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.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2016

Summary of Significant Accounting Policies [Abstract]

Other Current Liabilities [Table Text Block]

	December 31,
	2016		2015
Accrued capital expenditures	$	15	$	21
Accrued property taxes	7		5
Other	18		29
Total other current liabilities	$	40	$	55

Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]

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

	Years Ended December 31,
	2016		2015			2014
Non-cash investing activities:
Contribution from affiliate	$	—	$	—		$	376
Note receivable issued in exchange for investment in ETP	—		(1,369		)	—
Settlement of affiliate liability - note liability	541		793			—
Settlement of affiliate liability - tax liability	240		—			—
Supplemental cash flow information:
Accrued capital expenditures	$	15	$	21		$	15
Cash paid for interest, net of interest capitalized	75		76			75
Cash received for interest on note receivable from affiliate	40		16			—

Property, Plant and Equipment [Table Text Block]

		December 31,
	Lives in Years	2016			2015
Land and improvements		$	8		$	8
Buildings and improvements	6 – 22	341			340
Pipelines and equipment	5 – 46	2,223			2,444
Natural gas storage facilities	5 – 46	340			329
Vehicles	5	24			24
Right of way	36 – 40	25			23
Furniture and fixtures	5 – 12	34			34
Other	2 – 19	193			99
Construction work in progress		54			37
Total property, plant and equipment		3,242			3,338
Accumulated depreciation and amortization		(355		)	(286		)
Net property, plant and equipment		$	2,887		$	3,052

Schedule of Inventory, Current [Table Text Block]

The following table presents the components of inventory:

	December 31,
	2016		2015
Natural gas (1)	$	163	$	98
Materials and supplies	16		15
	$	179	$	113

⁽¹⁾  Natural gas volumes held for operations at December 31, 2016 and 2015 were 45.6 TBtu and 43.2 TBtu, respectively.

Revenue from External Customers by Products and Services [Table Text Block]

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,
	2016		2015		2014
Customer A	12	%	11	%	11	%
Customer B	—		10		—
Other top 10 customers	38		28		40
Remaining customers	50		51		49
Total percentage	100	%	100	%	100	%

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2016

Related Party Transactions [Abstract]

Related Party Transactions [table text block]

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

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

	Years Ended December 31,
	2016		2015		2014
Operating revenues	$	17	$	18	$	33
Operating and maintenance	14		16		16
General and administrative	27		31		33
Interest income — affiliates	26		23		23
Income (loss) from unconsolidated affiliates	1		26		(12		)

dividends received from unconsolidated affiliates [Table Text Block]

The following table provides a summary of distributions received from related parties:

	Years Ended December 31,
	2016		2015		2014
Distributions related to investment in:
ETP	$	—	$	39	$	9
Regency	—		16		61

As discussed in Note 5, the Company settled a note receivable from a subsidiary of ETP through a non-cash distribution during the year ended September 30, 2016.

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INVESTMENTS IN UNCONSOLIDATED AFFILIATES INVESTMENTS IN UNCONSOLIDATED AFFILIATES (Tables)

12 Months Ended

Dec. 31, 2016

Equity Method Investment, Balance Sheet Summary [Line Items]

Equity Method Investment, Balance Sheet Summary [Table Text Block]

The following tables present aggregated selected balance sheet and income statement data for ETP (on a 100% basis for all periods presented).

	December 31,
	2015
Current assets	$	4,698
Property, plant and equipment, net	45,087
Other assets	15,388
Total assets	$	65,173
Current liabilities	$	4,121
Non-current liabilities	34,021
Equity	27,031
Total liabilities and equity	$	65,173

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INVESTMENTS IN UNCONSOLIDATED AFFILIATES Equity Method Investment, income Statement Summary (Tables)

12 Months Ended

Dec. 31, 2016

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investment, Income Statement Summary [Table Text Block]

	Years Ended December 31,
	2015		2014
Revenue	$	34,292	$	55,475
Operating income	2,259		2,443
Net income	1,521		1,299

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Debt Obligations (Tables)

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Debt Instrument

Debt Disclosure [Text Block]

DEBT OBLIGATIONS:

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

	December 31,
	2016		2015
6.20% Senior Notes due 2017	$	300	$	300
7.00% Senior Notes due 2018	400		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		5
Unamortized fair value adjustments	51		76
Total debt outstanding	1,141		1,166
Less: Current maturities of long-term debt	307		1
Total long-term debt, less current maturities	$	834	$	1,165

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, 2016 and 2015 was $1.14 billion and $1.20 billion, 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, 2016, the Company has scheduled long-term debt principal payments as follows:

Years Ended December 31,
2017	$	300
2018	400
2019	150
2020	—
2021	—
Thereafter	240
Total	$	1,090

Assumption of Southern Union Debt

In connection with the consummation of the Panhandle Merger, PEPL assumed Southern Union’s long-term debt obligations. As of December 31, 2016, the long-term debt assumed in the Panhandle Merger consisted of $82 million in aggregate principal amount of 7.60% Senior Notes due 2024, $33 million in aggregate principal amount of 8.25% Senior Notes due 2029 and $54 million in aggregate principal amount of Floating Rate Junior Subordinated Notes due 2066 outstanding. The amounts recorded in the consolidated balance sheet also reflected unamortized fair value adjustments, which were $11 million in the aggregate at December 31, 2016.

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 3.903% at December 31, 2016.

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, 2016, the Company is in compliance with these covenants.

The Company will continue to opportunistically evaluate alternatives with regards to 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 ETP or other affiliates.

Schedule Of Debt Instruments

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

	December 31,
	2016		2015
6.20% Senior Notes due 2017	$	300	$	300
7.00% Senior Notes due 2018	400		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		5
Unamortized fair value adjustments	51		76
Total debt outstanding	1,141		1,166
Less: Current maturities of long-term debt	307		1
Total long-term debt, less current maturities	$	834	$	1,165

Schedule of Maturities of Long-term Debt

As of December 31, 2016, the Company has scheduled long-term debt principal payments as follows:

Years Ended December 31,
2017	$	300
2018	400
2019	150
2020	—
2021	—
Thereafter	240
Total	$	1,090

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Benefits (Tables)

12 Months Ended

Dec. 31, 2016

Postemployment Benefits [Abstract]

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

The following tables contain information at the dates indicated about the obligations and funded status of the Company’s other postretirement plans.

	December 31,
	2016			2015
Change in benefit obligation:
Benefit obligation at beginning of period	$	21		$	24
Interest cost	1			1
Actuarial (gain) loss	(1		)	(2		)
Benefits paid, net	(2		)	(2		)
Dispositions	—			—
Benefit obligation at end of period	$	19		$	21
Change in plan assets:
Fair value of plan assets at beginning of period	$	118		$	114
Return on plan assets and other	2			(1		)
Employer contributions	8			7
Benefits paid, net	(2		)	(2		)
Dispositions	—			—
Fair value of plan assets at end of period	$	126		$	118
Amount overfunded at end of period (1)	$	(107	)	$	(97	)
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial loss	$	(7	)	$	(10	)
Prior service cost	14			14
	$	7		$	4

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

Schedule of Net Benefit Costs [Table Text Block]

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,
	2016			2015			2014
Interest cost	$	1		$	1		$	1
Expected return on plan assets	(6		)	(6		)	(5		)
Prior service credit amortization	1			1			1
Actuarial loss amortization	(1		)	(1		)	(1		)
Net periodic benefit cost	$	(5	)	$	(5	)	$	(4	)

Schedule of Assumptions Used [Table Text Block]

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,
	2016		2015		2014
Discount rate	3.88	%	3.60	%	4.29	%
Expected return on assets:
Tax exempt accounts	7.00	%	7.00	%	7.00	%
Taxable accounts	4.50	%	4.50	%	4.50	%

Schedule of Health Care Cost Trend Rates [Table Text Block]

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,
	2016		2015
Health care cost trend rate	8.10	%	8.10	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.70	%	4.71	%
Year that the rate reaches the ultimate trend rate	2024		2021

Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block]

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 the following effects:

	One Percentage Point Increase		One Percentage Point Decrease
Effect on accumulated postretirement benefit obligation	$	1	$	(1	)

Schedule of Allocation of Plan Assets [Table Text Block]

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

	December 31,
	2016		2015
Cash and cash equivalents	$	8	$	3
Mutual fund (1)	—		115
Target 2020 Fund  (2)	112		—
Target 2050 Fund  (3)	6		—
Total	$	126	$	118

⁽¹⁾  This fund of funds invests primarily in a diversified portfolio of equity, fixed income and short-term mutual funds. As of December 31, 2015, the fund was primarily comprised of 36% equities, 54% fixed income securities, and 10% cash.

Schedule of Expected Benefit Payments [Table Text Block]

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
2017	$	2
2018	1
2019	1
2020	1
2021	1
2022 – 2026	6

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Taxes on Income (Tables)

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

Schedule of Income Tax Expense (Benefit) and Effective Income Tax Rate

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

	Years Ended December 31,
	2016			2015		2014
Current expense (benefit):
Federal	$	8		$	21	$	258
State	—			—		32
Total	8			21		290
Deferred expense (benefit):
Federal	$	(11	)	$	17	$	(130	)
State	(10		)	14		22
Total	(21		)	31		(108		)
Total income tax expense	$	(13	)	$	52	$	182

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

The differences between the Company’s effective income tax rate and the U.S. federal income tax statutory rate were as follows:

	Years Ended December 31,
	2016			2015			2014
Computed statutory income tax expense (benefit) at 35%	$	(231	)	$	55		$	50
Changes in income taxes resulting from:
Premium on debt retirement	—			—			(10		)
State income taxes, net of federal income tax benefit	(6		)	9			36
Non-deductible goodwill impairment	223			—			—
Non-deductible goodwill included in the Lake Charles LNG Transaction	—			—			105
Audit settlements	—			(7		)	—
Other	1			(5		)	1
Income tax expense	$	(13	)	$	52		$	182

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

The table below summarizes the principal components of the Company’s deferred tax assets (liabilities) as follows:

	December 31,
	2016			2015
Deferred income tax assets:
Other postretirement benefits	$	4		$	5
Debt amortization	30			57
Other	37			32
Total deferred income tax assets	71			94
Valuation allowance	(2		)	(2		)
Net deferred income tax assets (included within other non-current assets, net)	$	69		$	92
Deferred income tax liabilities:
Property, plant and equipment	$	(770	)	$	(796	)
Investment in unconsolidated affiliates	(6		)	(20		)
Other	(4		)	(1		)
Total deferred income tax liabilities	(780		)	(817		)
Net deferred income tax liability	$	(711	)	$	(725	)

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Derivative Instrument and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives Effect On Income Table

The following table summarizes the location and amount (excluding income tax effects) of derivative instrument (gains) and losses reported in the Company’s consolidated financial statements:

	Years Ended December 31,
	2016	2015	2014
Economic Hedges:
Interest rate contracts:
Change in fair value — increase (decrease) in interest expense	—	—	(7	)

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PROPERTY, PLANT AND EQUIPMENT Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2016

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

		December 31,
	Lives in Years	2016			2015
Land and improvements		$	8		$	8
Buildings and improvements	6 – 22	341			340
Pipelines and equipment	5 – 46	2,223			2,444
Natural gas storage facilities	5 – 46	340			329
Vehicles	5	24			24
Right of way	36 – 40	25			23
Furniture and fixtures	5 – 12	34			34
Other	2 – 19	193			99
Construction work in progress		54			37
Total property, plant and equipment		3,242			3,338
Accumulated depreciation and amortization		(355		)	(286		)
Net property, plant and equipment		$	2,887		$	3,052

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ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2016

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation

The following table is a reconciliation of the carrying amount of the ARO liability reflected as liabilities on our balance sheet 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, will result in a change in the amount of the liability recognized.

	Years Ended December 31,
	2016			2015			2014
Beginning balance	$	58		$	58		$	55
Revisions	—			—			3
Settled	(7		)	(3		)	(3		)
Disposals	—			—			—
Accretion expense	3			3			3
Ending balance	$	54		$	58		$	58

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies [Abstract]

Environmental Liabilities Table

The table below reflects the amount of accrued liabilities recorded in the consolidated balance sheets at the dates indicated 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.

	December 31,
	2016		2015
Current	$	—	$	—
Non-current	2		3
Total environmental liabilities	$	2	$	3

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QUARTERLY OPERATIONS Quarterly Operations (Tables)

12 Months Ended

Dec. 31, 2016

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information [Table Text Block]

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

	Quarters Ended
	March 31, 2016		June 30, 2016		September 30, 2016		December 31, 2016			Total
Operating revenues	$	141	$	124	$	120	$	129		$	514
Operating income (loss) (1)	48		30		23		(738		)	(637		)
Net income (loss)	31		15		13		(705		)	(646		)
Net income (loss) attributable to partners	31		15		13		(705		)	(646		)
	Quarters Ended
	March 31, 2015		June 30, 2015		September 30, 2015		December 31, 2015			Total
Operating revenues	$	155	$	128	$	126	$	139		$	548
Operating income	53		31		26		43			153
Net income	31		19		25		30			105
Net income attributable to partners	31		19		25		30			105

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Description of the Business (Details)	12 Months Ended
	Dec. 31, 2016
General partnership
Description of the Business
Limited partnership interest	1.00%
Limited partnership
Description of the Business
Limited partnership interest	99.00%

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Policies - Cash and Cash Equivalents (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Restricted Cash and Cash Equivalents Items
Non-cash contribution from affiliate	$ 0	$ 0	$ 376
Notes Receivable, Related Parties, Noncurrent	0	(1,369)	0
non-cash payment from subsidiary of ETP	541	793	0
Non-Cash Settlement of Tax Liability	240	0	0
Accrued Capital Expenditures	15	21	15
Interest Paid, Net	75	76	75
Increase (Decrease) in Notes Receivables	$ 40	$ 16	$ 0

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Policies - Inventory (Details) MMbtu in Millions, $ in Millions		Dec. 31, 2016 USD ($) MMbtu	Dec. 31, 2015 USD ($) MMbtu
Natural Gas Volumes | MMbtu		45.6	43.2
Natural Gas Inventory	[1]	$ 163	$ 98
Inventory, Raw Materials and Supplies		16	15
Inventories		179	113
Energy Related Inventory		$ 179	$ 113

[1] Natural gas volumes held for operations at December 31, 2016 and 2015 were 45.6 TBtu and 43.2 TBtu, respectively.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of significant accounting policies - goodwill (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Feb. 19, 2014
Goodwill	$ 285	$ 923	$ 1,152
Goodwill, Other Changes		$ (229)
Goodwill, Impairment Loss	(638)
Panhandle [Member]
Goodwill, Impairment Loss	(590)
Sea Robin [Member]
Goodwill, Impairment Loss	$ (48)
Lake Charles LNG Transaction [Member]
Goodwill				$ 184

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Policies - Top Customers (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Entity-Wide Revenue, Major Customer, Percentage	100.00%	100.00%	100.00%
Ameren Corporation [Member]
Entity-Wide Revenue, Major Customer, Percentage	12.00%	11.00%	11.00%
Exelon Generation Company [Member] [Member]
Entity-Wide Revenue, Major Customer, Percentage	0.00%	10.00%	0.00%
Other Top 10 Customers
Entity-Wide Revenue, Major Customer, Percentage	38.00%	28.00%	40.00%
Remaining Customers
Entity-Wide Revenue, Major Customer, Percentage	50.00%	51.00%	49.00%

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Policies - PPE (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 3,242	$ 3,338
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	355	286
Net property, plant and equipment	2,887	3,052
Land and Land Improvements [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	8	8
Construction Work-In-Process [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	54	37
Building and Building Improvements [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	341	340
Pipelines [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	2,223	2,444
Natural Gas Storage [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	340	329
Vehicles [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	24	24
Right Of Way [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	25	23
Furniture and Fixtures [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	34	34
Property, Plant and Equipment, Other Types [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	193	$ 99
Sea Robin [Member]
Property, Plant and Equipment [Line Items]
Tangible Asset Impairment Charges	$ 133

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Policies - Other Current Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Other Liabilities, Current [Abstract]
Accrued Capital Expenditures	$ 15	$ 21	$ 15
Accrued Property Tax	7	5
Customer advances and deposits	18	29
Other current liabilities	$ 40	$ 55

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Mergers and Other Transactions (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended
	Feb. 28, 2014	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015	Jan. 31, 2015	Dec. 31, 2014	Feb. 19, 2014
Notes Receivable, Related Parties					$ 1,370
Goodwill		$ 285		$ 923			$ 1,152
Regency [Member]
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.							31,400,000
ETP [Member]
Notes Receivable, Related Parties			$ 541
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.					17,800,000
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.							2,200,000
NOTE PAYABLE TO RELATED PARTY								$ 1,090
7.60% Senior Notes, due February 1, 2024 [Member]
Debt Instrument, Interest Rate, Stated Percentage		7.60%
8.25% Senior Notes, due November 14, 2029 [Member]
Debt Instrument, Interest Rate, Stated Percentage		8.25%
Regency 4.50% Senior Notes Due 2023 [Member]
Debt Instrument, Interest Rate, Stated Percentage		4.50%
Guarantor Obligations, Current Carrying Value		$ 600
Class F Units [Member] | Regency [Member]
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.							6,300,000
Lake Charles LNG Transaction [Member]
Partners' Capital Account, Units, Redeemed	18,700,000
Goodwill								184
Intangible Assets, Net (Excluding Goodwill)								$ 50
Regency Merger [Member]
Business Acquisition, Number Of Share Received In Exchange Of Each Share						0.4066
Business Acquisition, Share Price						$ 0.32
Regency Merger [Member] | ETP [Member]
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.					15,500,000

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Related Party Balances (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction
Non-current notes receivable from related party — ETP	$ 251	$ 574
Advances from affiliates	$ 0	$ 0

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Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction
Interest income — affiliates	$ 26	$ 23	$ 23
Income (loss) from unconsolidated affiliates	1	26	(12)
Southern Union
Related Party Transaction
Revenue from Related Parties	17	18	33
Interest income — affiliates	26	23	23
Affiliated Entity
Related Party Transaction
Related Party Transaction, Expenses from Transactions with Related Party	14	16	16
Related Party Operating, Maintenance and General Expenses	27	31	33
Income (loss) from unconsolidated affiliates	$ 1	$ 26	$ (12)

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RELATED PARTY TRANSACTIONS Related Party Distributions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Distributions of earnings received from unconsolidated affiliates	$ 0	$ 9	$ 6
ETP [Member]
Distributions of earnings received from unconsolidated affiliates	0	39	9
Regency [Member]
Distributions of earnings received from unconsolidated affiliates	$ 0	$ 16	$ 61

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INVESTMENTS IN UNCONSOLIDATED AFFILIATES INVESTMENTS IN UNCONSOLIDATED AFF. - Schedule of Equity Methold Investments(Details) - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Summarized Financial Information, Current Assets	$ 4,698
Equity Method Investment Summarized Financial information, PPE	45,087
Equity Method Investment Summarized Financial information, Other Assets	15,388
Equity Method Investment, Summarized Financial Information, Assets	65,173
Equity Method Investment, Summarized Financial Information, Revenue	34,292	$ 55,475
Equity Method Investment, Summarized Financial Information, Income (Loss) from Continuing Operations before Extraordinary Items	2,259	2,443
Equity Method Investment, Summarized Financial Information, Net Income (Loss)	1,521	$ 1,299
Equity Method Investment, Summarized Financial Information, Current Liabilities	4,121
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities	34,021
Equity Method Investment Summarized Financial Information, Equity	27,031
equity method investment summarized financial information, total liabilities and equity	$ 65,173
Regency [Member]
Schedule of Equity Method Investments [Line Items]
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.		31.4
Class F Units [Member] | Regency [Member]
Schedule of Equity Method Investments [Line Items]
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.		6.3

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INVESTMENTS IN UNCONSOLIDATED AFFILIATES Investment in unconsolidated affiliates detail (Details) - USD ($) $ / shares in Units, $ in Millions	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015	Jan. 31, 2015	Dec. 31, 2014
Schedule of Equity Method Investments [Line Items]
Notes Receivable, Related Parties				$ 1,370
GOODWILL	$ 285		$ 923			$ 1,152
ETP [Member]
Schedule of Equity Method Investments [Line Items]
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.				17,800,000
Notes Receivable, Related Parties		$ 541
SUG Holding Note Receivable [Member]
Schedule of Equity Method Investments [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				4.75%
Regency Merger [Member]
Schedule of Equity Method Investments [Line Items]
Business Acquisition, Number Of Share Received In Exchange Of Each Share					0.4066
Business Acquisition, Share Price					$ 0.32
Regency Merger [Member] | ETP [Member]
Schedule of Equity Method Investments [Line Items]
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.				15,500,000

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Comprehensive Income (Loss) - Tax amounts in other comprehensive income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Income taxes included in other comprehensive income:
Actuarial loss relating to postretirement benefits	$ 0	$ 0	$ 1

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Debt Obligations - Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Feb. 19, 2014
Debt Instrument
Junior Subordinated Notes	$ 54	$ 54
Other Long-term Debt	5	5
Unamortized Net Premiums And Fair Value Adjustments	51	76
Total debt outstanding	1,141	1,166
Less: Current maturities of long-term debt	307	1
Long-term Debt, Excluding Current Maturities	834	1,165
6.20% Senior Notes due 2017
Debt Instrument
Senior Notes	300	$ 300
Debt Instrument, Interest Rate, Stated Percentage		6.20%
Senior Notes due 2018 [Member]
Debt Instrument
Senior Notes	400	$ 400
Debt Instrument, Interest Rate, Stated Percentage		7.00%
8.125% Senior Notes due 2019
Debt Instrument
Senior Notes	150	$ 150
Debt Instrument, Interest Rate, Stated Percentage		8.125%
7.60% Senior Notes, due February 1, 2024 [Member]
Debt Instrument
Senior Notes	82	$ 82
Senior Notes Due 2029 [Member]
Debt Instrument
Senior Notes	66	66
8.25% Senior Notes, due November 14, 2029 [Member]
Debt Instrument
Senior Notes	33	$ 33
Junior Subordinated Debt [Member]
Debt Instrument
Senior Notes	54
Panhandle [Member]
Debt Instrument
Junior Subordinated Notes	$ 600
ETP [Member]
Debt Instrument
NOTE PAYABLE TO RELATED PARTY			$ 1,090

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DEBT OBLIGATIONS Debt Obligations - Future Maturities (Details) $ in Millions	Dec. 31, 2016 USD ($)
Debt Instrument
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	$ 300
Long-term Debt, Maturities, Repayments of Principal in Year Two	400
Long-term Debt, Maturities, Repayments of Principal in Year Three	150
Long-term Debt, Maturities, Repayments of Principal in Year Four	0
Long-term Debt, Maturities, Repayments of Principal in Year Five	0
Long-term Debt, Maturities, Repayments of Principal after Year Five	240
Long Term Debt Maturities Repayments Of Principal Total	$ 1,090

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Debt Obligations - Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Feb. 19, 2014
Debt Instrument
Debt Instrument, Unamortized Discount (Premium), Net	$ 11
Debt Instrument, Fair Value Disclosure	1,140	$ 1,200
Long term debt, amount outstanding	1,141	1,166
Junior Subordinated Notes	54	54
Unamortized Net Premiums And Fair Value Adjustments	51	$ 76
7.60% Senior Notes, due February 1, 2024 [Member]
Debt Instrument
Senior Notes	$ 82
Debt Instrument, Interest Rate, Stated Percentage	7.60%
8.25% Senior Notes, due November 14, 2029 [Member]
Debt Instrument
Senior Notes	$ 33
Debt Instrument, Interest Rate, Stated Percentage	8.25%
Junior Subordinated Debt [Member]
Debt Instrument
Senior Notes	$ 54
3.26% Junior Subordinated Notes due November 1, 2066 [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	3.0175%
Long-term Debt, Weighted Average Interest Rate	3.903%
ETP [Member]
Debt Instrument
NOTE PAYABLE TO RELATED PARTY			$ 1,090
Panhandle [Member]
Debt Instrument
Junior Subordinated Notes	$ 600

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BENEFITS Benefits - Obligations and Funded Status (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Interest cost		$ 1	$ 1	$ 1
Fair value of plan assets at beginning of period		118
Fair value of plan assets at end of period		126	118
Other Postretirement Benefit Plan [Member]
Benefit obligation at beginning of period		21	24
Interest cost		1	1
Actuarial (gain) loss		(1)	(2)
Benefits paid, net		(2)	(2)
Change in Benefit Obligations, Dispositions		0	0
Benefit obligation at end of period		19	21	24
Fair value of plan assets at beginning of period		118	114
Return on plan assets and other		2	(1)
Employer contributions		8	7
Change in Plan Assets, Dispositions		0	0
Fair value of plan assets at end of period		126	118	$ 114
Amount overfunded at end of period (1)	[1]	(107)	(97)
Net actuarial loss		(7)	(10)
Prior service cost		14	14
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:		$ 7	$ 4

[1] Recorded as a non-current asset in the consolidated balance sheets.

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Benefits - Components of Net Periodic Benefit Cost (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure
Interest cost	$ 1	$ 1	$ 1
Expected return on plan assets	(6)	(6)	(5)
Prior service credit amortization	1	1	1
Actuarial loss amortization	(1)	(1)	(1)
Net periodic benefit cost	$ (5)	$ (5)	$ (4)

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BENEFITS Benefits - Weighted-average Assumptions (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Postemployment Benefits [Abstract]
Discount rate	3.88%	3.60%	4.29%
Tax exempt accounts	7.00%	7.00%	7.00%
Expected long term reurn on assets, taxable accounts	4.50%	4.50%	4.50%

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BENEFITS Benefits - Assumed Health Care Cost Trend Rates Used (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Postemployment Benefits [Abstract]
Health care cost trend rate	8.10%	8.10%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.70%	4.71%
Year that the rate reaches the ultimate trend rate	2024	2021

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BENEFITS Benefits - 1% Change in Assumed Health Care Cost Trend Rates Used (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)
Postemployment Benefits [Abstract]
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation	$ 1
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation	$ (1)

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BENEFITS Benefits - Fair Value of Assets by Category (Details) - USD ($) $ in Millions		Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan, Fair Value of Plan Assets		$ 126	$ 118
Cash and Cash Equivalents
Defined Benefit Plan, Fair Value of Plan Assets		8	3
Mutual Fund
Defined Benefit Plan, Fair Value of Plan Assets	[1]	0	115
Fixed Income Funds [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[1]	112	0
Balanced Funds [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[1]	$ 6	$ 0

[1] This fund of funds invests primarily in a diversified portfolio of equity, fixed income and short-term mutual funds. As of December 31, 2015, the fund was primarily comprised of 36% equities, 54% fixed income securities, and 10% cash.

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BENEFITS Benefits - Estimate of Expected Benefit Payments (Details) - Other Postretirement Benefit Plan [Member] $ in Millions	Dec. 31, 2016 USD ($)
Defined Benefit Plan, Expected Future Benefit Payments in Year One	$ 2
Defined Benefit Plan, Expected Future Benefit Payments in Year One, net	2
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	1
Defined Benefit Plan, Expected Future Benefit Payments in Year Two, net	1
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	1
Defined Benefit Plan, Expected Future Benefit Payments in Year Three, net	1
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	1
Defined Benefit Plan, Expected Future Benefit Payments in Year Four, net	1
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	1
Defined Benefit Plan, Expected Future Benefit Payments in Year Five, net	1
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	6
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter, net	$ 6

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BENEFITS Benefits - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure
Defined Contribution Plan Employers Matching Contribution Percentage to Participants Percentage Conribution	100.00%
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	$ 8
Defined Contribution Plan, Employer Matching Contribution, Percent	5.00%
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure
Large Cap US Equitiies	30.00%	36.00%
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Arising During Period, before Tax	$ 1
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	3.71%	3.84%
Fixed Income Securities	68.00%	54.00%
Cash Fund Investments	2.00%	10.00%
Other Postretirement Benefit Plan [Member] | Equity Securities
Defined Benefit Plan Disclosure
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	25.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	35.00%
Other Postretirement Benefit Plan [Member] | Fixed Income Securities
Defined Benefit Plan Disclosure
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	65.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	75.00%
Other Postretirement Benefit Plan [Member] | Balanced Funds [Member]
Defined Benefit Plan Disclosure
Large Cap US Equitiies	87.00%
Fixed Income Securities	10.00%
Cash Fund Investments	3.00%
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan Disclosure
Defined Contribution Plan, Employer Matching Contribution, Percent	3.00%
Company Contributions Vested	100.00%
Company Contributions Years	five
Defined Contribution Plan, Cost Recognized	$ 1	$ 1	$ 2
Savings Plan [Member]
Defined Benefit Plan Disclosure
Defined Contribution Plan, Cost Recognized	$ 2	$ 2	$ 3

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Taxes on Income - Current and Deferred (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure
Federal	$ 8	$ 21	$ 258
State	0	0	32
Current Income Tax Expense (Benefit)	8	21	290
Federal	(11)	17	(130)
State	(10)	14	22
Deferred income taxes	(21)	31	(108)
Total income tax expense	$ (13)	$ 52	$ 182

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TAXES ON INCOME Income Taxes - Effective Rate Reconciliation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Schedule of Effective Income Tax Rate Reconciliation [Line Items]
Computed statutory income tax expense at 35%	$ (231)	$ 55	$ 50
Premium on debt retirement	0	0	(10)
State income taxes, net of federal income tax benefit	(6)	9	36
Non-deductible goodwill impairment	223	0	0
Effective Income Tax Rate Reconciliation, Other Reconciling Items, Amount	0	0	105
Other	1	(5)	1
Effective Income Tax Rate Reconciliation, Audit Settlements	0	(7)	0
Total income tax expense	$ (13)	$ 52	$ 182

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TAXES ON INCOME Taxes on Income - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Other postretirement benefits	$ 4	$ 5
Debt amortization	30	57
Other	37	32
Total deferred income tax assets	71	94
Deferred Tax Assets, Valuation Allowance	(2)	(2)
Deferred Tax Assets, Net	69	92
Property, plant and equipment	(770)	(796)
Deferred Tax Liabilities, Investment in Noncontrolled Affiliates	(6)	(20)
Other	(4)	(1)
Deferred Tax Liabilities, Gross	(780)	(817)
Deferred Tax Liabilities, Net	(711)	(725)
Deferred Tax Liabilities, Net, Noncurrent	$ 711	$ 725

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TAXES ON INCOME Taxes on Income - Narrative (Details) $ in Millions	Dec. 31, 2016 USD ($)
Income Tax Disclosure [Abstract]
Unrecognized Tax Benefits	$ 11
Unrecognized tax benfits for state filing positions, net of federal tax	$ 6

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Derivative Instrument and Hedging Activities - Income Stmt (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Gain Loss Recognized In Other Comprehensive Income Interest Rate Hedges	$ 0	$ 0	$ 0
Gain Loss Recognized in Interest Expense	0	0	(7)
Gain Loss Recognized In Distribution Commodity Contracts	$ 0	$ 0	$ 0

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PROPERTY, PLANT AND EQUIPMENT Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2015
Building Improvements [Member] | Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P6Y0M
Building Improvements [Member] | Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P22Y0M
Pipelines And Equipment [Member] | Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P5Y0M
Pipelines And Equipment [Member] | Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P46Y0M
Natural Gas Storage [Member] | Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P5Y0M
Natural Gas Storage [Member] | Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P46Y0M
Vehicles [Member] | Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P5Y0M
Vehicles [Member] | Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P5Y0M
Right Of Way [Member] | Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P36Y0M
Right Of Way [Member] | Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P40Y0M
Furniture and Fixtures [Member] | Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P5Y0M
Furniture and Fixtures [Member] | Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P12Y0M
Property, Plant and Equipment, Other Types [Member] | Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P2Y0M
Property, Plant and Equipment, Other Types [Member] | Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P19Y0M

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ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations - Assets (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
ARO Underlying Asset	$ 13	$ 6
Other ARO Assets
ARO Underlying Asset	$ 14	$ 18

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ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations - Schedule of Changes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Beginning balance	$ 58	$ 58	$ 55
Revisions	0	0	3
Settled	$ (7)	$ (3)	$ (3)
Asset Retirement Obligations, Significant Changes	0	0	0
Accretion expense	$ 3	$ 3	$ 3
Ending balance	$ 54	$ 58	$ 58

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ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
ARO Underlying Asset	$ 13	$ 6
Asset Retirement Obligation, Revision of Estimate	0	0	$ 3
Asset Retirement Obligation, Liabilities Settled	$ 7	$ 3	$ 3
Asset Retirement Obligations, Significant Changes	0	0	0
Other ARO Assets
ARO Underlying Asset	$ 14	$ 18

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Commitments and Contingencies - Accrued Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Loss Contingencies [Line Items]
Current	$ 0	$ 0
Non-current	2	3
Total environmental liabilities	$ 2	$ 3

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Commitment and Contingenices (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2015
Loss Contingencies [Line Items]
Refundable Gas Costs			$ 11,000,000
Contingent Residual Support Agreement, Amount	$ 2,000,000,000
Estimated litigation liability	21,000,000	$ 22,000,000
Regency 4.50% Senior Notes Due 2023 [Member]
Loss Contingencies [Line Items]
Guarantor Obligations, Current Carrying Value	$ 600,000,000
Debt Instrument, Interest Rate, Stated Percentage	4.50%
Attorney General of Commonwealth [Member]
Loss Contingencies [Line Items]
Legal Fees	$ 19,000,000
Percentage Of Recovery	50.00%
Reimbursement expert and consultant cost, maximum	$ 150,000

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QUARTERLY OPERATIONS Quarterly Operations (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating revenues	$ 129	$ 120	$ 124	$ 141	$ 139	$ 126	$ 128	$ 155	$ 514	$ 548	$ 581
Operating income	(738)	23	30	48	43	26	31	53	(637)	153	193
Net income (loss)	(705)	13	15	31	30	25	19	31	(646)	105	(39)
Net income (loss) attributable to partners	$ (705)	$ 13	$ 15	$ 31	$ 30	$ 25	$ 19	$ 31	$ (646)	$ 105	$ (45)