10-K/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

(Amendment No. 1)

(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, 2015

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.

EXPLANATORY NOTE

As noted in the Form 8-K filed August 4, 2016, we are filing this Amendment No. 1 to our Form 10-K (“Form 10-K/A”) for the year ended December 31, 2015, which was originally filed on February 26, 2016 (“Original Filing”), to restate our consolidated financial statements as of and for the years ended December 31, 2015 and 2014, as well as the quarterly periods within those years, and to amend related disclosures, including our controls and procedures. Accordingly, pursuant to Rule 12b-15 under the Securities Exchange Act of 1934, as amended, this Form 10-K/A contains the complete text of Item 1A of Part I, Items 7, 8 and 9A of Part II and Item 15 of Part IV. Unaffected items have not been repeated in this Form 10-K/A.

In connection with the preparation of the Form 10-Q for the three and six months ended June 30, 2016, the Company determined that, due to certain clerical errors, the state tax rate utilized to calculate the tax provision for the Company was incorrect, resulting in income tax expense being understated by $20 million and $36 million for the years ended December 31, 2015 and 2014, respectively. As a result, we have restated our consolidated financial statements, consolidated financial information and notes to the consolidated financial statements as of and for the years ended December 31, 2015 and 2014. The errors did not impact any periods prior to January 1, 2014.

Management has concluded that the error in the tax rate noted above resulted from a material weakness in the Company's internal controls, and as a result, management has concluded that the Company's internal controls over financial reporting were not effective as of December 31, 2015 and 2014. Management is evaluating the changes to the design of the internal controls related to income tax and anticipates remediation as of September 30, 2016. A description of the material weakness in internal controls and the related remediation is disclosed in Item 9A of this Form 10-K/A.

This amendment does not reflect events occurring after the filing of the Original Filing, and does not modify or update the disclosures therein in any way other than as required to reflect the adjustments described above. Such events include the events described in our quarterly report on Form 10-Q for the quarter ended March 31, 2016.

We are also filing currently dated signatures from our Directors and currently dated certifications from our Chief Executive Officer and Chief Financial Officer as Exhibits 31.1, 31.2, 32.1, 32.2, as well as various exhibits related to XBRL.

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PANHANDLE EASTERN PIPE LINE COMPANY, LP

TABLE OF CONTENTS

		Page
PART I
ITEM 1A.	RISK FACTORS	1
PART II
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	12
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	15
ITEM 9A.	CONTROLS AND PROCEDURES	15
PART IV
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	17
	SIGNATURES	18

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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 Form 10-K/A.

Definitions

The abbreviations, acronyms and industry terminology used in this annual report on Form 10-K/A are defined as follows:

/d	per day
ARO	Asset retirement obligation
Bcf	Billion cubic feet
Btu	British thermal units
Citrus	Citrus, LLC
EPA	United States Environmental Protection Agency
La Grange	La Grange Acquisition, L.P., a wholly-owned subsidiary of ETP, which conducts business under the assumed named of Energy Transfer Company
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
MGE	Missouri Gas Energy
NEG	New England Gas Company
NGL	Natural gas liquids
OPEB plans	Other postretirement employee benefit plans
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 ETE

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Sea Robin	Sea Robin Pipeline Company, LLC
SEC	United States Securities and Exchange Commission
Southern Union	Southern Union Company
Southwest Gas	Pan Gas Storage, LLC (d.b.a. Southwest Gas)
SUGS	Southern Union Gas Services
TBtu	Trillion British thermal units
Trunkline	Trunkline Gas Company, LLC

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PART I

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

We have identified a material weakness in our internal control over financial reporting which could, if not remediated, result in material misstatements in our financial statements.

We have identified a material weakness in internal control over financial reporting related to the controls around the Company's income tax accrual. Under standards established by the Public Company Accounting Oversight Board, a material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected and corrected on a timely basis. See Part II, Item 9A, "Controls and Procedures."  We have taken remedial measures, but if those measures are insufficient to address the material weakness, or if additional material weaknesses or significant deficiencies in our internal control over financial reporting are discovered or occur in the future, our consolidated financial statements may contain material misstatements, and we could be required to restate our financial results.

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, 2015, debt on the consolidated balance sheets totaled $1.17 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.

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.

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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.

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:

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• 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, 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.

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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.

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;

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• 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 their 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 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.

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The ability of interstate pipelines held in tax-pass-through entities, like us, to include an allowance for income taxes as a cost-of-service element in their regulated rates has been subject to extensive litigation before the FERC and the courts for a number of years. 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.

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

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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.

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, 2015, our consolidated balance sheet reflected $923 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 January 29, 2016, 210 of the Company’s 552 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

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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 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

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commerce.  FERC also has authority over the construction, acquisition, operation and disposition of these pipeline and storage assets.

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

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

FERC may also exercise its Section 5 authority to initiate proceedings to review rates that it believes may not be just and reasonable.  FERC has recently exercised this authority with respect to several other pipeline companies, 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.

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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.

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;

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• unanticipated environmental liabilities;

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

• the impact of potential impairment charges;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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PART II

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, as filed in the Form 10-K for the period ended December 31, 2015.

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

Regency Merger

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. The Company’s investment was accounted for in our consolidated financial statements using the equity method.

Investment in ETP

Effective September 1, 2015, the Company exchanged its investment in the ETP common units received during the Regency transaction, along with ETP common units that had been received in a previous transaction, for a note receivable from a subsidiary of ETP in the amount of $1.37 billion.

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Results of Operations

	Years Ended December 31,
	2015			2014
	(Restated)			(Restated)
OPERATING REVENUES:
Transportation and storage of natural gas	$	528		$	555
Other	20			26
Total operating revenues (1)	548			581
OPERATING EXPENSES:
Cost of natural gas and other energy	4			3
Operating and maintenance	216			209
General and administrative	42			46
Depreciation and amortization	133			130
Total operating expenses	395			388
OPERATING INCOME	153			193
OTHER INCOME (EXPENSE):
Interest expense, net	(50		)	(66		)
Equity in earnings (losses) of unconsolidated affiliates	26			(12		)
Interest income - affiliates	23			23
Other, net	5			5
Total other expenses, net	4			(50		)
INCOME BEFORE INCOME TAX EXPENSE	157			143
Income tax expense	52			182
NET INCOME (LOSS)	105			(39		)
less: Net income attributable to noncontrolling interest	—			6
NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS	$	105		$	(45	)
Natural gas volumes transported (TBtu): (2)
PEPL	607			611
Trunkline	633			694
Sea Robin	113			130

⁽¹⁾  Reservation revenues comprised 90% and 83% of total operating revenues for the years ended December 31, 2015 and 2014, 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, 2015 compared to the prior year primarily due to the impact of colder weather in the first quarter of 2014, which increased gas parking service related and firm reservation transportation revenue. Additionally, transportation revenues decreased $15 million due to a managed contract roll off to facilitate the transfer of one of the pipelines at Trunkline that was taken out of service in advance of being repurposed from natural gas service to crude oil service.

• Operating Expenses. Operating expenses increased for the year ended December 31, 2015 compared to the prior year primarily due to an increase of $4 million in employee costs as well as an increase in legal fees due to a reversal of a $3 million legal reserve during the first quarter of 2014.

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• Interest Expense, Net of Interest Capitalized. Interest expense decreased for the year ended December 31, 2015 compared to the prior year due to the repayment of long-term debt, as well as losses on interest rate swaps that were recorded in interest rate expense in 2014. The Company settled a total of $275 million of interest rate swaps in 2014, and no interest rate swaps remained outstanding at or subsequent to December 31, 2014.

• Equity in Earnings (Losses) of Unconsolidated Affiliates. Equity in earnings (losses) of unconsolidated affiliates primarily reflects the Company’s earnings related to its investments in ETP through September 1, 2015 (the date that the Company exchanged its investment in ETP common units) and Regency through May 1, 2015 (the date that ETP acquired Regency).  The loss for the year ended December 31,  2014 was primarily due to Regency’s recognition of a goodwill impairment, for which the Company recorded a non-cash loss based on its proportionate ownership in Regency

• Income Taxes. The increase in the effective tax rate for the year ended December 31, 2014 was primarily due to the Lake Charles LNG Transaction, which was treated as a sale for tax purposes, resulting in $70 million of incremental income tax expense. Accordingly, the decrease in the effective rate for the year ended December 31, 2015 was also primarily due to Lake Charles LNG Transaction which was completed in 2014.

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, 2015:

	Total		2016		2017		2018		2019		2020		2021 and thereafter
Operating leases (1)	$	17	$	3	$	3	$	3	$	2	$	3	$	3
Total long-term debt (2) (3)	1,090		—		300		400		150		—		240
Interest payments on debt (4)	383		75		71		41		21		16		159
Natural gas purchases (5)	53		3		4		4		3		3		36
Firm capacity payments (6)	68		26		23		16		3		—		—
OPEB funding (7)	48		8		8		8		8		8		8
Total (8)	$	1,659	$	115	$	409	$	472	$	187	$	30	$	446

⁽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, 2015, 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 $76 million of unamortized fair value adjustments as of December 31, 2015.

⁽⁴⁾  Interest payments on debt are based upon the applicable stated or variable interest rates as of December 31, 2015.

⁽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.

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⁽⁸⁾  Excludes non-current deferred tax liability of $725 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.

Rate Matters

On December 2, 2013, Sea Robin filed a general NGA Section 4 rate case at the FERC as required by a previous rate case settlement. In the filing, Sea Robin seeks to increase its authorized rates to recover costs related to asset retirement obligations, depreciation, and return and taxes. A settlement was reached with the shippers and a stipulation and agreement was filed with the FERC on July 23, 2014. The settlement was certified to the FERC by the administrative law judge on October 7, 2014 and was approved by the FERC on June 26, 2015. In September 2015, related to the final settlement, Sea Robin made refunds to customers totaling $11 million, including interest.

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 issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606) - Deferral of the Effective Date,” and 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. Early adoption is permitted as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within those annual periods. ASU 2014-09 can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Company is currently evaluating the impact, if any, that adopting this new accounting standard will have on our revenue recognition policies.

In November 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”), which is intended to improve how deferred taxes are classified on organizations’ balance sheets. The ASU eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations are now required to classify all deferred tax assets and liabilities as noncurrent. We adopted the provisions of ASU 2015-17 upon issuance.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

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 (“Principal Executive Officer”) and Chief Financial Officer (“Principal Financial Officer”), of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of the end of the period covered by this report. Based upon that evaluation, management, including the Chief Executive Officer and Chief Financial Officer, concluded that due to the material weakness described below, our disclosure controls and procedures were not effective as of December 31, 2015.

15

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, the Principal Executive Officer and Principal Financial Officer of our General Partner concluded that due to the material weakness described below, our internal controls over financial reporting were not effective as of December 31, 2015.

In connection with the preparation for the Form 10-Q for the three and six months ended June 30, 2016, the Company determined that, due to certain clerical errors, the state tax rate utilized to calculate the tax provision for the Company was incorrect, resulting in income tax expense being understated by $20 million and $36 million for the years ended December 31, 2015 and 2014, respectively. As a result, we have restated our consolidated financial statements, consolidated financial information and notes to the consolidated financial statements as of and for the years ended December 31, 2015 and 2014, included in this annual report on Form 10-K/A. The errors did not impact any periods prior to January 1, 2014.

These clerical errors resulted from a deficiency in the procedures to review the tax models used in recording the Company’s tax provision. We have concluded that such deficiency constituted a material weakness in the Company’s internal controls. Management is in the process of remediating the internal controls weakness related to income tax and anticipates remediation as of September 30, 2016. Nevertheless, the Company may continue to report the above material weakness while sufficient evaluation of newly established procedures and controls occurs. Notwithstanding the material weakness, management has concluded that the consolidated financial statements included in this Form 10-K/A present fairly, in all material respects, our financial position, results of operations and cash flows for the periods presented.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting that occurred during the three month period ended December 31, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting

16

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.

17

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: August 8, 2016	By: /s/   A. Troy Sturrock A. Troy Sturrock Vice President and Controller (duly authorized to sign on behalf of the registrant)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of 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	August 8, 2016
	Kelcy L. Warren
(ii)	Principal financial officer:
	/s/ Thomas E. Long	Chief Financial Officer	August 8, 2016
	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,	August 8, 2016
	Kelcy L. Warren	SUG Holding Company
	/s/ John W. McReynolds	Director, SUG Holding Company	August 8, 2016
	John W. McReynolds

18

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	F - 5
Consolidated Statements of Comprehensive Income (Loss)	F - 6
Consolidated Statements of Partners’ Capital	F - 7
Consolidated Statements of Cash Flows	F - 8
Notes to Consolidated Financial Statements	F - 9

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, 2015 and 2014, 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, 2015. 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, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2, the 2015 and 2014 consolidated financial statements have been restated to correct an error.

/s/ GRANT THORNTON LLP

Houston, Texas

February 26, 2016 (except for the restatement described in Note 2

and the effects thereof, as to which the date is August 8, 2016)

F - 2

PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

	December 31,
	2015			2014
	(Restated)			(Restated)
ASSETS
Current assets:
Cash and cash equivalents	$	3		$	32
Accounts receivable, net	48			58
Accounts receivable from related companies	172			128
Exchanges receivable	5			11
Inventories	113			119
Other current assets	9			10
Total current assets	350			358
Property, plant and equipment	3,338			3,395
Accumulated depreciation	(286		)	(269		)
	3,052			3,126
Investments in unconsolidated affiliates	15			1,443
Other non-current assets, net	122			109
Advances to affiliates	258			—
Note receivable from related party	574			—
Goodwill	923			1,152
Total assets	$	5,294		$	6,188

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,
	2015		2014
	(Restated)		(Restated)
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Current maturities of long-term debt	$	1	$	1
Accounts payable and accrued liabilities	3		6
Accounts payable to related companies	125		43
Exchanges payable	94		114
Accrued interest	12		12
Customer advances and deposits	9		10
Other current liabilities	55		56
Total current liabilities	299		242
Long-term debt, less current maturities	1,165		1,189
Deferred income taxes	725		1,539
Advances from affiliates	—		51
Other non-current liabilities	222		278
Commitments and contingencies
Partners’ capital:
Partners’ capital	2,881		2,889
Accumulated other comprehensive income	2		—
Total partners’ capital	2,883		2,889
Total liabilities and partners’ capital	$	5,294	$	6,188

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

F - 4

PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in millions)

	Years Ended December 31,
	2015			2014			2013
	(Restated)			(Restated)
OPERATING REVENUES:
Transportation and storage of natural gas	$	528		$	555		$	576
LNG terminalling	—			—			216
Other	20			26			293
Total operating revenues	548			581			1,085
OPERATING EXPENSES:
Cost of natural gas and other energy	4			3			228
Operating and maintenance	216			209			248
General and administrative	42			46			113
Depreciation and amortization	133			130			189
Goodwill impairment	—			—			689
Total operating expenses	395			388			1,467
OPERATING INCOME (LOSS)	153			193			(382		)
OTHER INCOME (EXPENSE):
Interest expense, net	(50		)	(66		)	(111		)
Equity in earnings (losses) of unconsolidated affiliates	26			(12		)	15
Interest income - affiliates	23			23			9
Other, net	5			5			(3		)
Total other income (expense), net	4			(50		)	(90		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	157			143			(472		)
Income tax expense from continuing operations	52			182			98
INCOME (LOSS) FROM CONTINUING OPERATIONS	105			(39		)	(570		)
Income from discontinued operations	—			—			35
NET INCOME (LOSS)	105			(39		)	(535		)
less: Net income (loss) attributable to noncontrolling interest	—			6			(36		)
NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS	$	105		$	(45	)	$	(499	)

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

F - 5

PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in millions)

	Years Ended December 31,
	2015		2014			2013
	(Restated)		(Restated)
Net income (loss)	$	105	$	(39	)	$	(535	)
Other comprehensive income (loss), net of tax:
Change in fair value of commodity hedges	—		—			(3		)
Reclassification of unrealized loss on commodity hedges into earnings	—		—			6
Actuarial gain (loss) relating to postretirement benefits, net of tax amounts of $0, $1, and ($15), respectively	2		(3		)	25
	2		(3		)	28
Comprehensive income (loss)	$	107	$	(42	)	$	(507	)

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

F - 6

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, 2012	$	4,050		$	(9	)	$	(13	)	$	4,028
Dividends paid to Southern Union stockholders	—			—			(313		)	(313		)
Other comprehensive income (loss), net of tax	—			12			(1		)	11
Sales of MGE and NEG, net of tax	—			—			12			12
SUGS Contribution	—			—			(135		)	(135		)
Net loss	(499		)	—			(36		)	(535		)
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 (loss) income (Restated)	(45		)	—			6			(39		)
Balance, December 31, 2014 (Restated)	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 (Restated)	105			—			—			105
Balance, December 31, 2015 (Restated)	$	2,881		$	2		$	—		$	2,883

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

F - 7

PANHANDLE EASTERN PIPE LINE COMPANY, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

	Years Ended December 31,
	2015			2014			2013
	(Restated)			(Restated)
OPERATING ACTIVITIES:
Net income (loss)	$	105		$	(39	)	$	(535	)
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	133			130			189
Goodwill impairment	—			—			689
Deferred income taxes	31			(108		)	181
Amortization of deferred financing fees	(23		)	(22		)	(30		)
Unrealized gain on derivatives	—			(25		)	(52		)
(Income) loss from unconsolidated affiliates	(26		)	12			(15		)
Distributions of earnings received from unconsolidated affiliates	9			6			15
Other non-cash	13			6			33
Changes in operating assets and liabilities	(66		)	197			(159		)
Net cash flows provided by operating activities	176			157			316
INVESTING ACTIVITIES:
Proceeds from SUGS Contribution	—			—			482
Proceeds from sale of MGE assets, net of transaction costs	—			—			1,008
Proceeds from affiliates	—			20			—
Capital expenditures	(128		)	(109		)	(250		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	46			65			39
Repayment of note receivable from related party	40			—			—
Note receivable issued to related party	(40		)	—			—
Other	2			(16		)	5
Net cash flows (used in) provided by investing activities	(80		)	(40		)	1,284
FINANCING ACTIVITIES:
Distributions to partners	(125		)	(102		)	(313		)
Issuance of loans from affiliates	—			—			1,669
Repayments of loans from affiliates	—			—			(975		)
Repayment of long-term debt	—			—			(1,795		)
Net change in revolving credit facilities	—			—			(210		)
Other	—			—			(8		)
Net cash flows used in financing activities	(125		)	(102		)	(1,632		)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(29		)	15			(32		)
CASH AND CASH EQUIVALENTS, beginning of period	32			17			49
CASH AND CASH EQUIVALENTS, end of period	$	3		$	32		$	17

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

F - 8

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.

The Company’s consolidated results of operations for the year ended December 31, 2013 includes Southern Union’s former natural gas gathering and processing operations, which were contributed to an affiliate in 2013, and Southern Union’s former local distribution operations, which were sold in 2013 and were presented as discontinued operations.

Certain prior period amounts have been reclassified to conform to the 2015 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.

Restatement of Previously Issued Financial Statements. In connection with the preparation for the Form 10-Q for the three and six months ended June 30, 2016, the Company determined that, due to certain clerical errors, the state tax rate utilized to calculate the tax provision for the Company was incorrect, resulting in income tax expense being understated by $20 million and $36 million for the years ended December 31, 2015 and 2014, respectively. As a result, we have restated our consolidated financial statements, consolidated financial information and notes to the consolidated financial statements as of and for the years ended December 31, 2015 and 2014. The errors did not impact any periods prior to January 1, 2014.

The following tables present the summary of the previously reported balances, adjustments and restated balances on the Company’s consolidated balance sheets by financial statement line item as of the dates indicated:

	March 31, 2015							June 30, 2015
	(unaudited)							(unaudited)
	As Reported		Adjustment			As Restated		As Reported		Adjustment			As Restated
Accounts payable to related parties	$	33	$	6		$	39	$	29	$	5		$	34
Total current liabilities	198		6			204		207		5			212
Deferred income taxes	1,511		31			1,542		1,528		6			1,534
Partners' capital	2,957		(37		)	2,920		2,951		(11		)	2,940
Total partners' capital	2,957		(37		)	2,920		2,952		(11		)	2,941

F - 9

	September 30, 2015							December 31, 2015
	(unaudited)
	As Reported		Adjustment			As Restated		As Reported		Adjustment			As Restated
Accounts payable to related parties	$	57	$	6		$	63	$	99	$	26		$	125
Total current liabilities	238		6			244		273		26			299
Deferred income taxes	722		57			779		695		30			725
Partners' capital	2,874		(62		)	2,812		2,937		(56		)	2,881
Total partners' capital	2,875		(62		)	2,813		2,939		(56		)	2,883

	March 31, 2014							June 30, 2014
	(unaudited)							(unaudited)
	As Reported		Adjustment			As Restated		As Reported		Adjustment			As Restated
Accounts payable to related parties	$	467	$	—		$	467	$	451	$	1		$	452
Total current liabilities	776		—			776		726		1			727
Deferred income taxes	1,469		(2		)	1,467		1,461		6			1,467
Partners' capital	2,926		2			2,928		2,915		(7		)	2,908
Total partners' capital	2,928		2			2,930		2,917		(7		)	2,910

	September 30, 2014							December 31, 2014
	(unaudited)
	As Reported		Adjustment			As Restated		As Reported		Adjustment			As Restated
Accounts payable to related parties	$	462	$	1		$	463	$	38	$	5		$	43
Total current liabilities	687		1			688		237		5			242
Deferred income taxes	1,452		6			1,458		1,508		31			1,539
Partners' capital	2,925		(7		)	2,918		2,925		(36		)	2,889
Total partners' capital	2,927		(7		)	2,920		2,925		(36		)	2,889

F - 10

The following tables present a summary of the previously reported balances, adjustments and restated balances on the Company’s consolidated statements of operations and comprehensive income by financial statement line item for the periods indicated:

	Three months ended
	March 31, 2015						March 31, 2014
	(unaudited)						(unaudited)
	As Reported		Adjustment		As Restated		As Reported			Adjustment			As Restated
Income tax expense from continuing operations	$	12	$	—	$	12	$	106		$	(2	)	$	104
Income (loss) from continuing operations	31		—		31		(35		)	2			(33		)
Net income (loss)	31		—		31		(35		)	2			(33		)
Income (loss) attributable to partners	31		—		31		(41		)	2			(39		)
Comprehensive income (loss)	31		—		31		(36		)	2			(34		)

	Three months ended
	June 30, 2015								June 30, 2014
	(unaudited)								(unaudited)
	As Reported			Adjustment			As Restated		As Reported		Adjustment			As Restated
Income tax expense from continuing operations	$	25		$	(25	)	$	—	$	14	$	9		$	23
Income (loss) from continuing operations	(6		)	25			19		16		(9		)	7
Net income (loss)	(6		)	25			19		16		(9		)	7
Income (loss) attributable to partners	(6		)	25			19		16		(9		)	7
Comprehensive income (loss)	(6		)	25			19		16		(9		)	7

F - 11

	Six months ended
	June 30, 2015							June 30, 2014
	(unaudited)							(unaudited)
	As Reported		Adjustment			As Restated		As Reported			Adjustment			As Restated
Income tax expense from continuing operations	$	37	$	(25	)	$	12	$	120		$	7		$	127
Income (loss) from continuing operations	25		25			50		(19		)	(7		)	(26		)
Net income (loss)	25		25			50		(19		)	(7		)	(26		)
Income (loss) attributable to partners	25		25			50		(25		)	(7		)	(32		)
Comprehensive income (loss)	26		25			51		(20		)	(7		)	(27		)

	Three months ended
	September 30, 2015								September 30, 2014
	(unaudited)								(unaudited)
	As Reported			Adjustment			As Restated		As Reported		Adjustment		As Restated
Income tax expense from continuing operations	$	(28	)	$	51		$	23	$	8	$	—	$	8
Income (loss) from continuing operations	76			(51		)	25		23		—		23
Net income (loss)	76			(51		)	25		23		—		23
Income (loss) attributable to partners	76			(51		)	25		23		—		23
Comprehensive income (loss)	76			(51		)	25		23		—		23

	Nine months ended
	September 30, 2015							September 30, 2014
	(unaudited)							(unaudited)
	As Reported		Adjustment			As Restated		As Reported			Adjustment			As Restated
Income tax expense from continuing operations	$	9	$	26		$	35	$	128		$	7		$	135
Income (loss) from continuing operations	101		(26		)	75		4			(7		)	(3		)
Net income (loss)	101		(26		)	75		4			(7		)	(3		)
Income (loss) attributable to partners	101		(26		)	75		(2		)	(7		)	(9		)
Comprehensive income (loss)	102		(26		)	76		3			(7		)	(4		)

F - 12

	Three months ended
	December 31, 2015							December 31, 2014
	(unaudited)							(unaudited)
	As Reported		Adjustment			As Restated		As Reported			Adjustment			As Restated
Income tax expense from continuing operations	$	23	$	(6	)	$	17	$	18		$	29		$	47
Income (loss) from continuing operations	24		6			30		(7		)	(29		)	(36		)
Net income (loss)	24		6			30		(7		)	(29		)	(36		)
Income (loss) attributable to partners	24		6			30		(7		)	(29		)	(36		)
Comprehensive income (loss)	25		6			31		(9		)	(29		)	(38		)

	Year ended
	December 31, 2015							December 31, 2014
	As Reported		Adjustment			As Restated		As Reported			Adjustment			As Restated
Income tax expense from continuing operations	$	32	$	20		$	52	$	146		$	36		$	182
Income (loss) from continuing operations	125		(20		)	105		(3		)	(36		)	(39		)
Net income (loss)	125		(20		)	105		(3		)	(36		)	(39		)
Income (loss) attributable to partners	125		(20		)	105		(9		)	(36		)	(45		)
Comprehensive income (loss)	127		(20		)	107		(6		)	(36		)	(42		)

The following table represents a summary of previously reported balances, adjustments and restated balances on the Company’s consolidated statements of cash flows by financial statement line item for the years ended December 31, 2015 and 2014:

	Year ended
	December 31, 2015									December 31, 2014
	As Reported			Adjustment			As Restated			As Reported			Adjustment			As Restated
Net income (loss)	$	125		$	(20	)	$	105		$	(3	)	$	(36	)	$	(39	)
Deferred income taxes	14			17			31			(139		)	31			(108		)
Changes in operating assets and liabilities	(69		)	3			(66		)	192			5			197

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 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

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beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within those annual periods. ASU 2014-09 can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Company is currently evaluating the impact, if any, that adopting this new accounting standard will have on our revenue recognition policies.

In November 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”), which is intended to improve how deferred taxes are classified on organizations’ balance sheets. The ASU eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations are now required to classify all deferred tax assets and liabilities as noncurrent. We adopted the provisions of ASU 2015-17 upon issuance and prior period amounts have been reclassified to conform to the current period presentation. As of December 31, 2014, $3 million in current deferred tax assets were reclassified in the consolidated balance sheet from other current assets to deferred income taxes liability.

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,
	2015			2014		2013
Non-cash investing activities:
Contribution from affiliate	$	—		$	376	$	—
Note receivable issued in exchange for investment in ETP	(1,369		)	—		—
Settlement of affiliate liability	793			—		—
Supplemental cash flow information:
Accrued capital expenditures	$	21		$	15	$	13
Cash paid for interest, net of interest capitalized	76			75		142
Cash received for interest on note receivable from affiliate	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,
	2015		2014
Natural gas (1)	$	98	$	105
Materials and supplies	15		14
	$	113	$	119

⁽¹⁾  Natural gas volumes held for operations at December 31, 2015 and 2014 were 43.2 TBtu and 34.3 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

F - 14

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	2015			2014
Land and improvements		$	8		$	8
Buildings and improvements	6 – 22	340			340
Pipelines and equipment	5 – 46	2,387			2,353
Natural gas storage facilities	5 – 46	329			323
Vehicles	5	24			23
Right of way	36 – 40	23			23
Furniture and fixtures	5 – 12	34			33
Linepack		57			57
Other	2 – 19	99			192
Construction work in progress		37			43
Total property, plant and equipment		3,338			3,395
Accumulated depreciation and amortization		(286		)	(269		)
Net property, plant and equipment		$	3,052		$	3,126

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.

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 2015, the Partnership voluntarily changed the date of the annual goodwill impairment testing to the first day of the fourth quarter. The Partnership believes this new date is preferable because it allows for more timely completion

F - 15

of the annual goodwill impairment test prior to the end of the annual financial reporting period. This change in accounting principle does not delay, accelerate or avoid any potential impairment loss, nor does the change have a cumulative effect on income from continuing operations, net income or loss, or net assets.  This change was not applied retrospectively, as doing so would require the use of significant estimates and assumptions that include hindsight. Accordingly, the Partnership applied the change in annual goodwill impairment testing date prospectively beginning October 1, 2015.

The Company did not record a goodwill impairment for the years ended December 31, 2015 and 2014. The Company’s annual goodwill impairment test for the year ended December 31, 2013 resulted in a $689 million goodwill impairment related to the Lake Charles LNG reporting unit.

Changes in the carrying amount of goodwill were as follows:

	Total
Balance, December 31, 2013	$	1,336
Lake Charles LNG Transaction	(184		)
Balance, December 31, 2014	1,152
ETP common units exchange transaction	(229		)
Balance, December 31, 2015	$	923

Related Party Transactions. Related party expenses primarily include payments for services provided by ETE, ETP and other affiliates.  Other income includes interest income on a note receivable from a related party.

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,
	2015		2014
Accrued capital expenditures	$	21	$	15
Accrued property taxes	5		9
Other	29		32
Total other current liabilities	$	55	$	56

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/

F - 16

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 concentration of customers in the electric and gas utility industries as well as oil and natural gas producers and municipalities. This concentration of customers 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, 2015 and 2014.

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,
	2015		2014		2013
Customer A(1)	—	%	—	%	10	%
Customer B(2)	—		—		22
Customer C	11		11		6
Customer D	10		—		—
Other top 10 customers	28		40		20
Remaining customers	51		49		42
Total percentage	100	%	100	%	100	%

⁽¹⁾  SUGS, which was deconsolidated on April 30, 2013, had contracted to sell its entire owned or controlled output of NGL equity volumes to Customer A. Pricing for the NGL equity volumes sold to Customer A throughout the contract period was OPIS pricing based at Mont Belvieu, Texas delivery points.

⁽²⁾  Customer B is the sole customer of Lake Charles LNG, which was deconsolidated effective January 1, 2014.

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, 2015.

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

F - 17

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, 2015 and 2014. 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.

F - 18

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:

2015 Transactions

Regency Merger

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. The Company’s investment was accounted for in our consolidated financial statements using the equity method.

Investment in ETP

Effective September 1, 2015, the Company exchanged its investment in the ETP common units received during the Regency transaction, along with ETP common units that had been received in a previous transaction, for a note receivable from a subsidiary of ETP in the amount of $1.37 billion.

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.

F - 19

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.

2013 Transactions

Sale of Southern Union’s Distribution Operations

In September 2013, Southern Union completed its sale of the assets of MGE for an aggregate purchase price of $975 million, subject to customary post-closing adjustments. In December 2013, Southern Union completed its sale of the assets of NEG for cash proceeds of $40 million, subject to customary post-closing adjustments, and the assumption of $20 million of debt.

MGE and NEG have been classified as discontinued operations in the consolidated statements of operations.

Summarized financial information for MGE and NEG is as follows:

	Year Ended December 31, 2013
Revenue from discontinued operations	$	415
Net income of discontinued operations, excluding effect of taxes and overhead allocations	65

SUGS Contribution

On April 30, 2013, Southern Union completed its contribution to Regency of all of the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS (the “SUGS Contribution”). The general partner and IDRs of Regency are owned by ETE. The consideration paid by Regency in connection with this transaction consisted of (i) the issuance of 31.4 million Regency common units to Southern Union, (ii) the issuance of 6.3 million Regency Class F units to Southern Union, (iii) the distribution of $463 million in cash to Southern Union, net of closing adjustments, and (iv) the payment of $30 million in cash to a subsidiary of ETP. This transaction was between commonly controlled entities; therefore, the amounts recorded in the consolidated balance sheet for the investment in Regency and the related deferred tax liabilities were based on the historical book value of SUGS. In addition, PEPL Holdings provided a guarantee of collection with respect to the payment of the principal amounts of Regency’s debt related to the SUGS Contribution. The Regency Class F units had the same rights, terms and conditions as the Regency common units, except that the Company, as successor to Southern Union, did not receive distributions on the Regency Class F units.

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.

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

	Years Ended December 31,
	2015		2014			2013
Operating revenues	$	18	$	33		$	56
Cost of natural gas and other energy	—		—			17
Operating and maintenance	16		16			—
General and administrative	31		33			71
Interest expense, net	—		—			(31		)
Interest income — affiliates	23		23			9
Income (loss) from unconsolidated affiliates	26		(12		)	15

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

	Years Ended December 31,
	2015		2014		2013
Distributions related to investment in:
ETP	$	39	$	9	$	8
Regency	16		61		44

5. INVESTMENTS IN UNCONSOLIDATED AFFILIATES:

The Company’s investment in Regency consisted of 31.4 million Regency common units and 6.3 million Regency Class F units at December 31, 2014. In connection with the merger of ETP and Regency in April 2015, the Regency common units and Regency Class F units converted to 15.5 million ETP common units. The Company’s investment was accounted for using the equity method. Effective September 1, 2015, the Company exchanged these ETP common units, along with ETP common units that had been received in a previous transaction, for a note receivable from a subsidiary of ETP in the amount of $1.37 billion. The note receivable accrues interest annually at 4.75% and is due on September 1, 2035. In connection with this transaction, the Company also recorded a reduction in goodwill of $229 million and net deferred tax liabilities of $825 million, which amounts were associated with the exchanged ETP common units as a result of previous transactions whereby the Company had acquired ETP common units (and previously, Regency common units and Class F units) in exchange for other assets.

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

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	December 31,
	2015		2014
Current assets	$	4,698	$	6,029
Property, plant and equipment, net	45,087		38,907
Other assets	15,388		17,582
Total assets	$	65,173	$	62,518
Current liabilities	$	4,121	$	6,585
Non-current liabilities	34,021		30,622
Equity	27,031		25,311
Total liabilities and equity	$	65,173	$	62,518

	Years Ended December 31,
	2015		2014		2013
Revenue	$	34,292	$	55,475	$	48,335
Operating income	2,259		2,443		1,619
Net income	1,521		1,299		746

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,
	2015		2014
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		6
Unamortized fair value adjustments	76		99
Total debt outstanding	1,166		1,190
Less: Current maturities of long-term debt	1		1
Total long-term debt, less current maturities	$	1,165	$	1,189

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, 2015 and 2014 was $1.20 billion and $1.24 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.

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As of December 31, 2015, the Company has scheduled long-term debt principal payments as follows:

Years Ended December 31,
2016	$	—
2017	300
2018	400
2019	150
2020	—
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, 2015, 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 $12 million in the aggregate at December 31, 2015.

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 3.295% at December 31, 2015.

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, 2015, the Company is in compliance with these covenants.

7. RETIREMENT BENEFITS:

Postretirement Benefit Plans

Postretirement benefits expense for the years ended December 31, 2015 and 2014 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.

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Obligations and Funded Status

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

	December 31,
	2015			2014
Change in benefit obligation:
Benefit obligation at beginning of period	$	24		$	25
Interest cost	1			1
Actuarial (gain) loss	(2		)	1
Benefits paid, net	(2		)	(2		)
Dispositions	—			(1		)
Benefit obligation at end of period	$	21		$	24
Change in plan assets:
Fair value of plan assets at beginning of period	$	114		$	110
Return on plan assets and other	(1		)	4
Employer contributions	7			7
Benefits paid, net	(2		)	(2		)
Dispositions	—			(5		)
Fair value of plan assets at end of period	$	118		$	114
Amount overfunded at end of period (1)	$	(97	)	$	(90	)
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial loss	$	(10	)	$	(16	)
Prior service cost	14			15
	$	4		$	(1	)

⁽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,
	2015			2014			2013
Interest cost	$	1		$	1		$	1
Expected return on plan assets	(6		)	(5		)	(5		)
Prior service credit amortization	1			1			1
Actuarial loss amortization	(1		)	(1		)	(1		)
Net periodic benefit cost	$	(5	)	$	(4	)	$	(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 2016 is $1 million.

Assumptions.  The weighted-average discount rate used in determining benefit obligations was 3.84% and 3.68% at December 31, 2015 and 2014, respectively.

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

	Years Ended December 31,
	2015		2014		2013
Discount rate	3.60	%	4.29	%	3.66	%
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,
	2015		2014
Health care cost trend rate	8.10	%	7.60	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.71	%	4.90	%
Year that the rate reaches the ultimate trend rate	2021		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%, fixed income of 65% to 75% and cash and cash equivalents of up to 10%.  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,
	2015		2014
Cash and cash equivalents	$	3	$	3
Mutual fund (1)	115		111
Total	$	118	$	114

⁽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.  As of December 31, 2014, the fund was primarily comprised of 38% equities, 52% fixed income securities, and 10% cash.

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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 2016 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
2016	$	2
2017	2
2018	1
2019	1
2020	1
2021 – 2025	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, 2015, 2014, and 2013 were $2 million, $3 million, and $6 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, 2015, 2014, and 2013 were $1 million, $2 million, and $3 million, respectively.

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,
	2015		2014			2013
	(Restated)		(Restated)
Current expense (benefit):
Federal	$	21	$	258		$	(52	)
State	—		32			(7		)
Total	21		290			(59		)
Deferred expense (benefit):
Federal	$	17	$	(130	)	$	119
State	14		22			38
Total	31		(108		)	157
Total income tax expense	$	52	$	182		$	98

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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,
	2015			2014			2013
	(Restated)			(Restated)
Computed statutory income tax expense (benefit) at 35%	$	55		$	50		$	(165	)
Changes in income taxes resulting from:
Premium on debt retirement	—			(10		)	—
State income taxes, net of federal income tax benefit	9			36			21
Non-deductible goodwill impairment	—			—			241
Non-deductible goodwill included in the Lake Charles LNG Transaction	—			105			—
Audit settlements	(7		)	—			—
Other	(5		)	1			1
Income tax expense	$	52		$	182		$	98

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,
	2015			2014
	(Restated)			(Restated)
Deferred income tax assets:
Other postretirement benefits	$	5		$	5
Debt amortization	57			41
Other	32			27
Total deferred income tax assets	94			73
Valuation allowance	(2		)	(2		)
Net deferred income tax assets (included within other non-current assets, net)	$	92		$	71
Deferred income tax liabilities:
Property, plant and equipment	$	(796	)	$	(794	)
Investment in unconsolidated affiliates	(20		)	(810		)
Other	(1		)	(6		)
Total deferred income tax liabilities	(817		)	(1,610		)
Net deferred income tax liability	$	(725	)	$	(1,539	)

As of December 31, 2015, the Company has $15 million ($10 million, net of federal tax) of unrecognized tax benefits, $9 million of which would impact the Company’s effective income tax rate if recognized.  The Company expects that its unrecognized tax benefits will be reduced by $2 million within the next 12 months.

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.

F - 27

The Company and Southern Union are no longer subject to U.S. federal, state or local examinations for the tax periods prior to 2012. The Company was under examination by the Internal Revenue Service (IRS) for the tax years 2004 through 2009. In July of 2015, the Company and the IRS settled all issues related to the IRS examination of the 2004 through 2009 tax years. As a result of the settlement, the Company recognized a net tax benefit of $7 million.

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, 2015 and 2014 .

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,
	2015		2014			2013
Cash Flow Hedges:
Commodity contracts — Gathering and Processing:
Change in fair value – decrease in accumulated other comprehensive income	$	—	$	—		$	(3	)
Economic Hedges:
Interest rate contracts:
Change in fair value — increase (decrease) in interest expense	—		(7		)	29
Commodity contracts:
Change in fair value — decrease in deferred natural gas purchases	—		—			(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.

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.

F - 28

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 $18 million and were reflected as plant, property and equipment on our balance sheet as of December 31, 2015 and 2014. In addition, the Company had $6 million legally restricted for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2015.

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,
	2015			2014			2013
Beginning balance	$	58		$	55		$	46
Revisions	—			3			11
Settled	(3		)	(3		)	(1		)
Disposals	—			—			(4		)
Accretion expense	3			3			3
Ending balance	$	58		$	58		$	55

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

Trunkline Transfer Applications

In October 2011, Trunkline and Sea Robin jointly filed with FERC to transfer all of Trunkline’s offshore facilities, and certain related onshore facilities, by sale and transfer to Sea Robin to consolidate and streamline the ownership and operation of all regulated offshore assets under one entity and better position the offshore assets competitively.  Several parties filed interventions and protests of this filing.  On June 21, 2012, FERC issued an order granting Trunkline permission and approval to proceed with the transfer, subject to compliance with certain regulatory requirements.  On July 31, 2012 Sea Robin and Trunkline made the necessary compliance filings with FERC.  The transfer of the offshore facilities to Sea Robin was effective September 1, 2012.

On July 26, 2012, Trunkline filed an application with the FERC for approval to transfer approximately 770 miles of underutilized loop piping facilities by sale to an affiliate, and such facilities are contemplated to be converted to crude oil transportation service.  This sale was approved by the FERC on November 7, 2013, and the transaction was consummated on December 1, 2015.

Sea Robin Rate Case

On December 2, 2013, Sea Robin filed a general NGA Section 4 rate case at the FERC as required by a previous rate case settlement. In the filing, Sea Robin seeks to increase its authorized rates to recover costs related to asset retirement obligations, depreciation, and return and taxes. Filed rates were put into effect June 1, 2014 and estimated settlement rates were put into effect September 1, 2014, subject of refund. A settlement was reached with the shippers and a stipulation and agreement was filed with the FERC on July 23, 2014. The settlement was certified to the FERC by the administrative law judge on October 7, 2014 and was approved by the FERC on June 26, 2015. In September 2015, related to the final settlement, Sea Robin made refunds to customers totaling $11 million, including interest.

PEPL Holdings Guarantee of Collection

The Company fully and unconditionally guaranteed (the “Panhandle Guarantee”) all of the payment obligations of Regency and Regency Energy Finance Corp. under their $600 million in aggregate principal amount of 4.50% senior notes due November 2023, until May 28, 2105, at which time ETP entered into a supplemental indenture relating to the senior notes pursuant to which it has agreed to become a co-obligor with respect to the payment obligations thereunder. Accordingly, pursuant to the terms of the senior notes, the Company’s obligations under the Panhandle Guarantee were released.

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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.

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.

F - 30

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,
	2015		2014
Current	$	—	$	1
Non-current	3		3
Total environmental liabilities	$	3	$	4

Litigation and Other Claims

The Company is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business.

Attorney General of the Commonwealth of Massachusetts v New England Gas Company.  On July 7, 2011, the Massachusetts Attorney General (“AG”) filed a regulatory complaint with the Massachusetts Department of Public Utilities (“MDPU”) against New England Gas Company with respect to certain environmental cost recoveries.  The AG is seeking a refund to New England Gas Company customers for alleged “excessive and imprudently incurred costs” related to legal fees associated with Southern Union’s environmental response activities.  In the complaint, the AG requests that the MDPU initiate an investigation into the New England Gas Company’s collection and reconciliation of recoverable environmental costs including:  (i) the prudence of any and all legal fees, totaling $19 million, that were charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005, the year when a partner in the firm, Southern Union’s former Vice Chairman, President and Chief Operating Officer, joined Southern Union’s management team; (ii) the prudence of any and all legal fees that were charged by the Bishop, London & Dodds firm and passed through the recovery mechanism since 2005, the period during which a member of the firm served as Southern Union’s Chief Ethics Officer; and (iii) the propriety and allocation of certain legal fees charged that were passed through the recovery mechanism that the AG contends only qualify for a lesser, 50%, level of recovery.  Southern Union has filed its answer denying the allegations and moved to dismiss the complaint, in part on a theory of collateral estoppel.  The hearing officer has deferred consideration of Southern Union’s motion to dismiss.  The AG’s motion to be reimbursed expert and consultant costs by Southern Union of up to $150,000 was granted.  By tariff, these costs are recoverable through rates charged to New England Gas Company customers. The hearing officer previously stayed discovery pending resolution of a dispute concerning the applicability of attorney-client privilege to legal billing invoices.  The MDPU issued an interlocutory order on June 24, 2013 that lifted the stay, and discovery has resumed. The Company (as successor to Southern Union) believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, the Company will continue to assess its potential exposure for such cost recoveries as the matter progresses.

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, 2015 and 2014, the Company recorded litigation and other claim-related accrued liabilities of $22 million and $21 million, respectively. The Company does not have any material litigation or other claim contingency matters assessed as probable or reasonably possible that would require disclosure in the financial statements.

Other Commitments and Contingencies

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

F - 31

12. QUARTERLY FINANCIAL DATA (UNAUDITED) (RESTATED):

The tables below summarize the Company’s restated historical Consolidated Statements of Operations and Consolidated Balance Sheets for the interim quarters impacted by the restatement.

Consolidated Statements of Operations

	Quarters Ended
	March 31, 2015			June 30, 2015			September 30, 2015			December 31, 2015			Total
OPERATING REVENUES:
Transportation and storage of natural gas	$	149		$	123		$	121		$	135		$	528
Other	6			5			5			4			20
Total operating revenues	155			128			126			139			548
OPERATING EXPENSES:
Cost of natural gas and other energy	2			1			1			—			4
Operating and maintenance	53			50			56			57			216
General and administrative	12			11			12			7			42
Depreciation and amortization	35			35			31			32			133
Total operating expenses	102			97			100			96			395
OPERATING INOMCE (LOSS)	53			31			26			43			153
OTHER INCOME (EXPENSE):
Interest expense, net	(13		)	(12		)	(13		)	(12		)	(50		)
Equity in earnings (losses) of unconsolidated affiliates	4			(6		)	28			—			26
Interest income - affiliates	—			1			6			16			23
Other, net	(1		)	5			1			—			5
Total other income (expense),net	(10		)	(12		)	22			4			4
INCOME (LOSS) FROM BEFORE INCOME TAX EXPENSE	43			19			48			47			157
Income tax expense	12			—			23			17			52
NET INCOME (LOSS)	31			19			25			30			105
less: Net income (loss) attributable to noncontrolling interest	—			—			—			—			—
NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS	$	31		$	19		$	25		$	30		$	105

F - 32

	Quarters Ended
	March 31, 2014			June 30, 2014			September 30, 2014			December 31, 2014			Total
OPERATING REVENUES:
Transportation and storage of natural gas	$	170		$	122		$	125		$	138		$	555
Other	8			6			7			5			26
Total operating revenues	178			128			132			143			581
OPERATING EXPENSES:
Cost of natural gas and other energy	—			2			1			—			3
Operating and maintenance	47			49			55			58			209
General and administrative	10			11			12			13			46
Depreciation and amortization	31			32			33			34			130
Total operating expenses	88			94			101			105			388
OPERATING INOMCE (LOSS)	90			34			31			38			193
OTHER INCOME (EXPENSE):
Interest expense, net	(12		)	(19		)	(15		)	(20		)	(66		)
Equity in earnings (losses) of unconsolidated affiliates	(8		)	6			9			(19		)	(12		)
Interest income - affiliates	5			7			5			6			23
Other, net	(4		)	2			1			6			5
Total other income (expense),net	(19		)	(4		)	—			(27		)	(50		)
INCOME (LOSS) FROM BEFORE INCOME TAX EXPENSE	71			30			31			11			143
Income tax expense	104			23			8			47			182
NET INCOME (LOSS)	(33		)	7			23			(36		)	(39		)
less: Net income (loss) attributable to noncontrolling interest	6			—			—			—			6
NET INOME (LOSS) ATTRIBUTABLE TO PARTNERS	$	(39	)	$	7		$	23		$	(36	)	$	(45	)

F - 33

Consolidated Balance Sheets

	As of
	March 31, 2015			June 30, 2015			September 30, 2015			December 31, 2015
ASSETS
Current assets:
Cash and cash equivalents	$	47		$	65		$	30		$	3
Accounts receivable, net	51			40			41			48
Accounts receivable from related companies	42			54			120			172
Exchanges receivable	12			10			9			5
Inventories	83			106			99			113
Other current assets	13			13			15			9
Total current assets	248			288			314			350
Property, plant and equipment	3,403			3,428			3,456			3,338
Accumulated depreciation	(292		)	(319		)	(342		)	(286		)
Net property, plant and equipment	3,111			3,109			3,114			3,052
Investments in unconsolidated affiliates	1,428			1,404			15			15
Other non-current assets, net	110			116			127			122
Advances to affiliates	40			40			—			258
Note receivable from related party	40			40			1,369			574
Goodwill	1,152			1,152			923			923
Total assets	$	6,129		$	6,149		$	5,862		$	5,294
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Current maturities of long-term debt	$	1		$	1		$	1		$	1
Accounts payable and accrued liabilities	2			4			4			3
Accounts payable to related parties	39			34			63			125
Exchanges payable	76			91			83			94
Accrued interest	24			12			24			12
Customer advances and deposits	8			11			9			9
Other current liabilities	54			59			60			55
Total current liabilities	204			212			244			299
Long-term debt, less current maturities	1,184			1,178			1,172			1,165
Deferred income taxes	1,542			1,534			779			725
Advances from affiliates	—			—			566			—
Other non-current liabilities	279			284			289			222
Partners' capital:
Partners' capital	2,920			2,940			2,812			2,881
Accumulated other comprehensive income	—			1			1			2
Total partners' capital	2,920			2,941			2,813			2,883
Total liabilities and partners' capital	$	6,129		$	6,149		$	5,862		$	5,294

F - 34

	As of
	March 31, 2014			June 30, 2014			September 30, 2014			December 31, 2014
ASSETS
Current assets:
Cash and cash equivalents	$	74		$	32		$	55		$	32
Accounts receivable, net	55			51			51			58
Accounts receivable from related companies	33			57			30			128
Exchanges receivable	62			45			17			11
Inventories	160			147			115			119
Other current assets	15			20			48			10
Total current assets	399			352			316			358
Property, plant and equipment	3,316			3,331			3,360			3,395
Accumulated depreciation	(192		)	(215		)	(243		)	(269		)
Net property, plant and equipment	3,124			3,116			3,117			3,126
Investments in unconsolidated affiliates	1,502			1,488			1,480			1,443
Other non-current assets, net	95			105			106			109
Advances to affiliates	—			—			—			—
Note receivable from related party	386			386			386			—
Goodwill	1,152			1,152			1,152			1,152
Total assets	$	6,658		$	6,599		$	6,557		$	6,188
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Current maturities of long-term debt	$	1		$	1		$	1		$	1
Accounts payable and accrued liabilities	2			5			4			6
Accounts payable to related parties	467			452			463			43
Exchanges payable	214			179			117			114
Accrued interest	24			12			24			12
Customer advances and deposits	16			21			13			10
Other current liabilities	52			57			66			56
Total current liabilities	776			727			688			242
Long-term debt, less current maturities	1,203			1,201			1,195			1,189
Deferred income taxes	1,467			1,467			1,458			1,539
Advances from affiliates	—			—			—			51
Other non-current liabilities	282			294			296			278
Partners' capital:
Partners' capital	2,928			2,908			2,918			2,889
Accumulated other comprehensive income	2			2			2			—
Total partners' capital	2,930			2,910			2,920			2,889
Total liabilities and partners' capital	$	6,658		$	6,599		$	6,557		$	6,188

F - 35

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/A 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: August 8, 2016

/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/A 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: August 8, 2016

/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/A for the year ended December 31, 2015 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: August 8, 2016

/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/A for the year ended December 31, 2015 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:August 8, 2016

/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, 2015 USD ($) shares
Document Information [Abstract]
Document Type	10-K/A
Amendment Flag	true
Amendment Description	EXPLANATORY NOTE As noted in the Form 8-K filed August 4, 2016, we are filing this Amendment No. 1 to our Form 10-K (“Form 10-K/A”) for the year ended December 31, 2015, which was originally filed on February 26, 2016 (“Original Filing”), to restate our consolidated financial statements as of and for the years ended December 31, 2015 and 2014, as well as the quarterly periods within those years, and to amend related disclosures, including our controls and procedures. Accordingly, pursuant to Rule 12b-15 under the Securities Exchange Act of 1934, as amended, this Form 10-K/A contains the complete text of Item 1A of Part I, Items 7, 8 and 9A of Part II and Item 15 of Part IV. Unaffected items have not been repeated in this Form 10-K/A. In connection with the preparation of the Form 10-Q for the three and six months ended June 30, 2016, the Company determined that, due to certain clerical errors, the state tax rate utilized to calculate the tax provision for the Company was incorrect, resulting in income tax expense being understated by $20 million and $36 million for the years ended December 31, 2015 and 2014, respectively. As a result, we have restated our consolidated financial statements, consolidated financial information and notes to the consolidated financial statements as of and for the years ended December 31, 2015 and 2014. The errors did not impact any periods prior to January 1, 2014. Management has concluded that the error in the tax rate noted above resulted from a material weakness in the Company's internal controls, and as a result, management has concluded that the Company's internal controls over financial reporting were not effective as of December 31, 2015 and 2014. Management is evaluating the changes to the design of the internal controls related to income tax and anticipates remediation as of September 30, 2016. A description of the material weakness in internal controls and the related remediation is disclosed in Item 9A of this Form 10-K/A. This amendment does not reflect events occurring after the filing of the Original Filing, and does not modify or update the disclosures therein in any way other than as required to reflect the adjustments described above. Such events include the events described in our quarterly report on Form 10-Q for the quarter ended March 31, 2016. We are also filing currently dated signatures from our Directors and currently dated certifications from our Chief Executive Officer and Chief Financial Officer as Exhibits 31.1, 31.2, 32.1, 32.2, as well as various exhibits related to XBRL.
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2015
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

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 3	$ 30	$ 65	$ 47	$ 32	$ 55	$ 32	$ 74	$ 17	$ 49
Accounts receivable, net	48	41	40	51	58	51	51	55
Accounts receivable from related companies	172	120	54	42	128	30	57	33
Exchanges receivable	5	9	10	12	11	17	45	62
Inventories	113	99	106	83	119	115	147	160
Other current assets	9	15	13	13	10	48	20	15
Total current assets	350	314	288	248	358	316	352	399
Property, plant and equipment
Total property, plant and equipment	3,338	3,456	3,428	3,403	3,395	3,360	3,331	3,316
Accumulated depreciation	(286)	(342)	(319)	(292)	(269)	(243)	(215)	(192)
Net property, plant and equipment	3,052	3,114	3,109	3,111	3,126	3,117	3,116	3,124
Investments in unconsolidated affiliates	15	15	1,404	1,428	1,443	1,480	1,488	1,502
Goodwill	923	923	1,152	1,152	1,152	1,152	1,152	1,152	1,336
NOTE RECEIVABLE FROM RELATED PARTY	574	1,369	40	40	0	386	386	386
OTHER NON-CURRENT ASSETS, net	122	127	116	110	109	106	105	95
Due from Related Parties, Noncurrent	258	0	40	40	0	0	0	0
Total assets	5,294	5,862	6,149	6,129	6,188	6,557	6,599	6,658
Current liabilities:
Current maturities of long-term debt	1	1	1	1	1	1	1	1
Accounts payable and accrued liabilities	3	4	4	2	6	4	5	2
Accounts payable to related companies	125	63	34	39	43	463	452	467
Exchanges payable	94	83	91	76	114	117	179	214
Accrued interest	12	24	12	24	12	24	12	24
Customer Advances and Deposits, Current	9	9	11	8	10	13	21	16
Other current liabilities	55	60	59	54	56	66	57	52
Total current liabilities	299	244	212	204	242	688	727	776
Long-term debt, less current maturities	1,165	1,172	1,178	1,184	1,189	1,195	1,201	1,203
Deferred income taxes	725	779	1,534	1,542	1,539	1,458	1,467	1,467
ADVANCES FROM AFFILIATES	0	566	0	0	51	0	0	0
Other non-current liabilities	222	289	284	279	278	296	294	282
Commitments and contingencies
Partners’ capital:
Partners’ capital	2,881	2,812	2,940	2,920	2,889	2,918	2,908	2,928
Accumulated other comprehensive income	2	1	1	0	0	2	2	2
Total partners’ capital	2,883	2,813	2,941	2,920	2,889	2,920	2,910	2,930	$ 3,068	$ 4,028
Total liabilities and partners’ capital	$ 5,294	$ 5,862	$ 6,149	$ 6,129	$ 6,188	$ 6,557	$ 6,599	$ 6,658

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CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
OPERATING REVENUES:
Transportation and storage of natural gas	$ 528	$ 555	$ 576
LNG terminalling	0	0	216
Other	20	26	293
Total operating revenues	548	581	1,085
OPERATING EXPENSES:
Cost of Goods Sold	4	3	228
Operating, maintenance and general	216	209	248
General and Administrative Expense	42	46	113
Depreciation and amortization	133	130	189
Goodwill Impairment	0	0	689
Total operating expenses	395	388	1,467
Operating Income (Loss)	153	193	(382)
OTHER INCOME (EXPENSE):
Interest expense, net	(50)	(66)	(111)
Income (loss) from unconsolidated affiliates	26	(12)	15
Interest income — affiliates	23	23	9
Other, net	5	5	(3)
Total other expenses, net	4	(50)	(90)
Income (Loss) from Continuing Operations Before Income Tax Expense	157	143	(472)
Income tax expense from continuing operations	52	182	98
Income (Loss) from Continuing Operations	105	(39)	(570)
Income From Discontinued Operations	0	0	35
Net Income (Loss)	105	(39)	(535)
Net Income (Loss) Attributable to Noncontrolling Interest	0	6	(36)
Net Income (Loss) Attributable to Partners	$ 105	$ (45)	(499)
Successor
OPERATING EXPENSES:
Goodwill Impairment			$ 689

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Income and Comprehensive Income [Line Items]
Net income (loss)	$ 105	$ (39)	$ (535)
Other comprehensive income (loss), net of tax:
Change in fair value of commodity hedges	0	0	(3)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	0	0	(6)
Actuarial gain (loss) relating to postretirement benefits, net of tax amounts of $0, $1, and ($15), respectively	2	(3)	25
Total other comprehensive income (loss)	2	(3)	28
Comprehensive income (loss)	$ 107	$ (42)	$ (507)

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Income Taxes - Actuarial Gain Loss - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Successor
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Tax	$ 0	$ 1	$ (15)

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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, 2012	$ 4,028			$ (9)			$ (13)			$ 4,050
Dividends paid to Southern Union stockholders	(313)			0			(313)			0
Other comprehensive income, net of tax	11			12			(1)			0
SUGS Contribution	(135)			0			(135)			0
Net income (loss)	(535)			0			(36)			(499)
Lake Charles LNG Transaction	12			0			12			0
Balance at Dec. 31, 2013	3,068			3			(486)			3,551
Net income (loss)	(33)
Balance at Mar. 31, 2014	2,930
Balance at Dec. 31, 2013	3,068			3			(486)			3,551
Net income (loss)	(26)
Balance at Jun. 30, 2014	2,910
Balance at Dec. 31, 2013	3,068			3			(486)			3,551
Net income (loss)	(3)
Balance at Sep. 30, 2014	2,920
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
Balance at Mar. 31, 2014	2,930
Net income (loss)	7
Balance at Jun. 30, 2014	2,910
Net income (loss)	23
Balance at Sep. 30, 2014	2,920
Net income (loss)	(36)
Balance at Dec. 31, 2014	2,889			0			0			2,889
Net income (loss)	31
Balance at Mar. 31, 2015	2,920
Balance at Dec. 31, 2014	2,889			0			0			2,889
Net income (loss)	50
Balance at Jun. 30, 2015	2,941
Balance at Dec. 31, 2014	2,889			0			0			2,889
Net income (loss)	75
Balance at Sep. 30, 2015	2,813
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
Balance at Mar. 31, 2015	2,920
Net income (loss)	19
Balance at Jun. 30, 2015	2,941
Net income (loss)	25
Balance at Sep. 30, 2015	2,813
Net income (loss)	30
Balance at Dec. 31, 2015	$ 2,883			$ 2			$ 0			$ 2,881

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Cash Flows [Abstract]
Proceeds from SUGS Contribution	$ 0	$ 0	$ 482
OPERATING ACTIVITIES:
Net income (loss)	105	(39)	(535)
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	133	130	189
Goodwill Impairment	0	0	689
Deferred income taxes	31	(108)	181
Amortization of deferred financing fees	(23)	(22)	(30)
Unrealized gain on derivatives	0	(25)	(52)
(Income) loss from unconsolidated affiliates	(26)	12	(15)
Distributions of earnings received from unconsolidated affiliates	9	6	15
Other non-cash	13	6	33
Changes in operating assets and liabilities	(66)	197	(159)
Net cash flows provided by operating activities	176	157	316
INVESTING ACTIVITIES:
Proceeds from SUGS Contribution	0	20	0
Proceeds from sale of MGE assets, net of transaction costs	0	0	1,008
Proceeds from affiliates	40	0	0
Increase (Decrease) in Notes Receivable, Related Parties, Current	(40)	0	0
Capital expenditures	(128)	(109)	(250)
Distributions from unconsolidated affiliates in excess of cumulative earnings	46	65	39
Other	2	(16)	5
Net cash flows (used in) provided by investing activities	(80)	(40)	1,284
FINANCING ACTIVITIES:
Distribution Made to Limited Partner, Cash Distributions Paid	125	102	313
Issuance of loans from affiliates	0	0	1,669
Repayments of loans from affiliates	0	0	(975)
Repayment of long-term debt	0	0	(1,795)
Net change in revolving credit facilities	0	0	(210)
Other	0	0	(8)
Net cash flows used in financing activities	(125)	(102)	(1,632)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(29)	15	(32)
CASH AND CASH EQUIVALENTS, beginning of period	32	17	49
CASH AND CASH EQUIVALENTS, end of period	$ 3	$ 32	$ 17

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Description of the Business

12 Months Ended

Dec. 31, 2015

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.

The Company’s consolidated results of operations for the year ended December 31, 2013 includes Southern Union’s former natural gas gathering and processing operations, which were contributed to an affiliate in 2013, and Southern Union’s former local distribution operations, which were sold in 2013 and were presented as discontinued operations.

Certain prior period amounts have been reclassified to conform to the 2015 presentation. These reclassifications had no impact on net income or total equity.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2015

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.

Restatement of Previously Issued Financial Statements. In connection with the preparation for the Form 10-Q for the three and six months ended June 30, 2016, the Company determined that, due to certain clerical errors, the state tax rate utilized to calculate the tax provision for the Company was incorrect, resulting in income tax expense being understated by $20 million and $36 million for the years ended December 31, 2015 and 2014, respectively. As a result, we have restated our consolidated financial statements, consolidated financial information and notes to the consolidated financial statements as of and for the years ended December 31, 2015 and 2014. The errors did not impact any periods prior to January 1, 2014.

The following tables present the summary of the previously reported balances, adjustments and restated balances on the Company’s consolidated balance sheets by financial statement line item as of the dates indicated:

	March 31, 2015							June 30, 2015
	(unaudited)							(unaudited)
	As Reported		Adjustment			As Restated		As Reported		Adjustment			As Restated
Accounts payable to related parties	$	33	$	6		$	39	$	29	$	5		$	34
Total current liabilities	198		6			204		207		5			212
Deferred income taxes	1,511		31			1,542		1,528		6			1,534
Partners' capital	2,957		(37		)	2,920		2,951		(11		)	2,940
Total partners' capital	2,957		(37		)	2,920		2,952		(11		)	2,941

	September 30, 2015							December 31, 2015
	(unaudited)
	As Reported		Adjustment			As Restated		As Reported		Adjustment			As Restated
Accounts payable to related parties	$	57	$	6		$	63	$	99	$	26		$	125
Total current liabilities	238		6			244		273		26			299
Deferred income taxes	722		57			779		695		30			725
Partners' capital	2,874		(62		)	2,812		2,937		(56		)	2,881
Total partners' capital	2,875		(62		)	2,813		2,939		(56		)	2,883

	March 31, 2014							June 30, 2014
	(unaudited)							(unaudited)
	As Reported		Adjustment			As Restated		As Reported		Adjustment			As Restated
Accounts payable to related parties	$	467	$	—		$	467	$	451	$	1		$	452
Total current liabilities	776		—			776		726		1			727
Deferred income taxes	1,469		(2		)	1,467		1,461		6			1,467
Partners' capital	2,926		2			2,928		2,915		(7		)	2,908
Total partners' capital	2,928		2			2,930		2,917		(7		)	2,910

	September 30, 2014							December 31, 2014
	(unaudited)
	As Reported		Adjustment			As Restated		As Reported		Adjustment			As Restated
Accounts payable to related parties	$	462	$	1		$	463	$	38	$	5		$	43
Total current liabilities	687		1			688		237		5			242
Deferred income taxes	1,452		6			1,458		1,508		31			1,539
Partners' capital	2,925		(7		)	2,918		2,925		(36		)	2,889
Total partners' capital	2,927		(7		)	2,920		2,925		(36		)	2,889

The following tables present a summary of the previously reported balances, adjustments and restated balances on the Company’s consolidated statements of operations and comprehensive income by financial statement line item for the periods indicated:

	Three months ended
	March 31, 2015						March 31, 2014
	(unaudited)						(unaudited)
	As Reported		Adjustment		As Restated		As Reported			Adjustment			As Restated
Income tax expense from continuing operations	$	12	$	—	$	12	$	106		$	(2	)	$	104
Income (loss) from continuing operations	31		—		31		(35		)	2			(33		)
Net income (loss)	31		—		31		(35		)	2			(33		)
Income (loss) attributable to partners	31		—		31		(41		)	2			(39		)
Comprehensive income (loss)	31		—		31		(36		)	2			(34		)

	Three months ended
	June 30, 2015								June 30, 2014
	(unaudited)								(unaudited)
	As Reported			Adjustment			As Restated		As Reported		Adjustment			As Restated
Income tax expense from continuing operations	$	25		$	(25	)	$	—	$	14	$	9		$	23
Income (loss) from continuing operations	(6		)	25			19		16		(9		)	7
Net income (loss)	(6		)	25			19		16		(9		)	7
Income (loss) attributable to partners	(6		)	25			19		16		(9		)	7
Comprehensive income (loss)	(6		)	25			19		16		(9		)	7

	Six months ended
	June 30, 2015							June 30, 2014
	(unaudited)							(unaudited)
	As Reported		Adjustment			As Restated		As Reported			Adjustment			As Restated
Income tax expense from continuing operations	$	37	$	(25	)	$	12	$	120		$	7		$	127
Income (loss) from continuing operations	25		25			50		(19		)	(7		)	(26		)
Net income (loss)	25		25			50		(19		)	(7		)	(26		)
Income (loss) attributable to partners	25		25			50		(25		)	(7		)	(32		)
Comprehensive income (loss)	26		25			51		(20		)	(7		)	(27		)

	Three months ended
	September 30, 2015								September 30, 2014
	(unaudited)								(unaudited)
	As Reported			Adjustment			As Restated		As Reported		Adjustment		As Restated
Income tax expense from continuing operations	$	(28	)	$	51		$	23	$	8	$	—	$	8
Income (loss) from continuing operations	76			(51		)	25		23		—		23
Net income (loss)	76			(51		)	25		23		—		23
Income (loss) attributable to partners	76			(51		)	25		23		—		23
Comprehensive income (loss)	76			(51		)	25		23		—		23

	Nine months ended
	September 30, 2015							September 30, 2014
	(unaudited)							(unaudited)
	As Reported		Adjustment			As Restated		As Reported			Adjustment			As Restated
Income tax expense from continuing operations	$	9	$	26		$	35	$	128		$	7		$	135
Income (loss) from continuing operations	101		(26		)	75		4			(7		)	(3		)
Net income (loss)	101		(26		)	75		4			(7		)	(3		)
Income (loss) attributable to partners	101		(26		)	75		(2		)	(7		)	(9		)
Comprehensive income (loss)	102		(26		)	76		3			(7		)	(4		)

	Three months ended
	December 31, 2015							December 31, 2014
	(unaudited)							(unaudited)
	As Reported		Adjustment			As Restated		As Reported			Adjustment			As Restated
Income tax expense from continuing operations	$	23	$	(6	)	$	17	$	18		$	29		$	47
Income (loss) from continuing operations	24		6			30		(7		)	(29		)	(36		)
Net income (loss)	24		6			30		(7		)	(29		)	(36		)
Income (loss) attributable to partners	24		6			30		(7		)	(29		)	(36		)
Comprehensive income (loss)	25		6			31		(9		)	(29		)	(38		)

	Year ended
	December 31, 2015							December 31, 2014
	As Reported		Adjustment			As Restated		As Reported			Adjustment			As Restated
Income tax expense from continuing operations	$	32	$	20		$	52	$	146		$	36		$	182
Income (loss) from continuing operations	125		(20		)	105		(3		)	(36		)	(39		)
Net income (loss)	125		(20		)	105		(3		)	(36		)	(39		)
Income (loss) attributable to partners	125		(20		)	105		(9		)	(36		)	(45		)
Comprehensive income (loss)	127		(20		)	107		(6		)	(36		)	(42		)

The following table represents a summary of previously reported balances, adjustments and restated balances on the Company’s consolidated statements of cash flows by financial statement line item for the years ended December 31, 2015 and 2014:

	Year ended
	December 31, 2015									December 31, 2014
	As Reported			Adjustment			As Restated			As Reported			Adjustment			As Restated
Net income (loss)	$	125		$	(20	)	$	105		$	(3	)	$	(36	)	$	(39	)
Deferred income taxes	14			17			31			(139		)	31			(108		)
Changes in operating assets and liabilities	(69		)	3			(66		)	192			5			197

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 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. Early adoption is permitted as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within those annual periods. ASU 2014-09 can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Company is currently evaluating the impact, if any, that adopting this new accounting standard will have on our revenue recognition policies.

In November 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”), which is intended to improve how deferred taxes are classified on organizations’ balance sheets. The ASU eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations are now required to classify all deferred tax assets and liabilities as noncurrent. We adopted the provisions of ASU 2015-17 upon issuance and prior period amounts have been reclassified to conform to the current period presentation. As of December 31, 2014, $3 million in current deferred tax assets were reclassified in the consolidated balance sheet from other current assets to deferred income taxes liability.

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,
	2015			2014		2013
Non-cash investing activities:
Contribution from affiliate	$	—		$	376	$	—
Note receivable issued in exchange for investment in ETP	(1,369		)	—		—
Settlement of affiliate liability	793			—		—
Supplemental cash flow information:
Accrued capital expenditures	$	21		$	15	$	13
Cash paid for interest, net of interest capitalized	76			75		142
Cash received for interest on note receivable from affiliate	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,
	2015		2014
Natural gas (1)	$	98	$	105
Materials and supplies	15		14
	$	113	$	119

⁽¹⁾  Natural gas volumes held for operations at December 31, 2015 and 2014 were 43.2 TBtu and 34.3 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	2015			2014
Land and improvements		$	8		$	8
Buildings and improvements	6 – 22	340			340
Pipelines and equipment	5 – 46	2,387			2,353
Natural gas storage facilities	5 – 46	329			323
Vehicles	5	24			23
Right of way	36 – 40	23			23
Furniture and fixtures	5 – 12	34			33
Linepack		57			57
Other	2 – 19	99			192
Construction work in progress		37			43
Total property, plant and equipment		3,338			3,395
Accumulated depreciation and amortization		(286		)	(269		)
Net property, plant and equipment		$	3,052		$	3,126

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.

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 2015, the Partnership voluntarily changed the date of the annual goodwill impairment testing to the first day of the fourth quarter. The Partnership believes this new date is preferable because it allows for more timely completion of the annual goodwill impairment test prior to the end of the annual financial reporting period. This change in accounting principle does not delay, accelerate or avoid any potential impairment loss, nor does the change have a cumulative effect on income from continuing operations, net income or loss, or net assets.  This change was not applied retrospectively, as doing so would require the use of significant estimates and assumptions that include hindsight. Accordingly, the Partnership applied the change in annual goodwill impairment testing date prospectively beginning October 1, 2015.

The Company did not record a goodwill impairment for the years ended December 31, 2015 and 2014. The Company’s annual goodwill impairment test for the year ended December 31, 2013 resulted in a $689 million goodwill impairment related to the Lake Charles LNG reporting unit.

Changes in the carrying amount of goodwill were as follows:

	Total
Balance, December 31, 2013	$	1,336
Lake Charles LNG Transaction	(184		)
Balance, December 31, 2014	1,152
ETP common units exchange transaction	(229		)
Balance, December 31, 2015	$	923

Related Party Transactions. Related party expenses primarily include payments for services provided by ETE, ETP and other affiliates.  Other income includes interest income on a note receivable from a related party.

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,
	2015		2014
Accrued capital expenditures	$	21	$	15
Accrued property taxes	5		9
Other	29		32
Total other current liabilities	$	55	$	56

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 concentration of customers in the electric and gas utility industries as well as oil and natural gas producers and municipalities. This concentration of customers 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, 2015 and 2014.

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,
	2015		2014		2013
Customer A(1)	—	%	—	%	10	%
Customer B(2)	—		—		22
Customer C	11		11		6
Customer D	10		—		—
Other top 10 customers	28		40		20
Remaining customers	51		49		42
Total percentage	100	%	100	%	100	%

⁽¹⁾  SUGS, which was deconsolidated on April 30, 2013, had contracted to sell its entire owned or controlled output of NGL equity volumes to Customer A. Pricing for the NGL equity volumes sold to Customer A throughout the contract period was OPIS pricing based at Mont Belvieu, Texas delivery points.

⁽²⁾  Customer B is the sole customer of Lake Charles LNG, which was deconsolidated effective January 1, 2014.

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, 2015.

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, 2015 and 2014. 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, 2015

Business Combinations [Abstract]

Business Combinations Disclosure

MERGERS, DECONSOLIDATIONS AND RELATED TRANSACTIONS:

2015 Transactions

Regency Merger

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. The Company’s investment was accounted for in our consolidated financial statements using the equity method.

Investment in ETP

Effective September 1, 2015, the Company exchanged its investment in the ETP common units received during the Regency transaction, along with ETP common units that had been received in a previous transaction, for a note receivable from a subsidiary of ETP in the amount of $1.37 billion.

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.

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.

2013 Transactions

Sale of Southern Union’s Distribution Operations

In September 2013, Southern Union completed its sale of the assets of MGE for an aggregate purchase price of $975 million, subject to customary post-closing adjustments. In December 2013, Southern Union completed its sale of the assets of NEG for cash proceeds of $40 million, subject to customary post-closing adjustments, and the assumption of $20 million of debt.

MGE and NEG have been classified as discontinued operations in the consolidated statements of operations.

Summarized financial information for MGE and NEG is as follows:

	Year Ended December 31, 2013
Revenue from discontinued operations	$	415
Net income of discontinued operations, excluding effect of taxes and overhead allocations	65

SUGS Contribution

On April 30, 2013, Southern Union completed its contribution to Regency of all of the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS (the “SUGS Contribution”). The general partner and IDRs of Regency are owned by ETE. The consideration paid by Regency in connection with this transaction consisted of (i) the issuance of 31.4 million Regency common units to Southern Union, (ii) the issuance of 6.3 million Regency Class F units to Southern Union, (iii) the distribution of $463 million in cash to Southern Union, net of closing adjustments, and (iv) the payment of $30 million in cash to a subsidiary of ETP. This transaction was between commonly controlled entities; therefore, the amounts recorded in the consolidated balance sheet for the investment in Regency and the related deferred tax liabilities were based on the historical book value of SUGS. In addition, PEPL Holdings provided a guarantee of collection with respect to the payment of the principal amounts of Regency’s debt related to the SUGS Contribution. The Regency Class F units had the same rights, terms and conditions as the Regency common units, except that the Company, as successor to Southern Union, did not receive distributions on the Regency Class F units.

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Related Party Transactions

12 Months Ended

Dec. 31, 2015

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,
	2015		2014			2013
Operating revenues	$	18	$	33		$	56
Cost of natural gas and other energy	—		—			17
Operating and maintenance	16		16			—
General and administrative	31		33			71
Interest expense, net	—		—			(31		)
Interest income — affiliates	23		23			9
Income (loss) from unconsolidated affiliates	26		(12		)	15

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

	Years Ended December 31,
	2015		2014		2013
Distributions related to investment in:
ETP	$	39	$	9	$	8
Regency	16		61		44

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INVESTMENTS IN UNCONSOLIDATED AFFILIATES INVESTMENTS IN UNCONSOLIDATED AFFILIATES (Notes)

12 Months Ended

Dec. 31, 2015

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

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

INVESTMENTS IN UNCONSOLIDATED AFFILIATES:

The Company’s investment in Regency consisted of 31.4 million Regency common units and 6.3 million Regency Class F units at December 31, 2014. In connection with the merger of ETP and Regency in April 2015, the Regency common units and Regency Class F units converted to 15.5 million ETP common units. The Company’s investment was accounted for using the equity method. Effective September 1, 2015, the Company exchanged these ETP common units, along with ETP common units that had been received in a previous transaction, for a note receivable from a subsidiary of ETP in the amount of $1.37 billion. The note receivable accrues interest annually at 4.75% and is due on September 1, 2035. In connection with this transaction, the Company also recorded a reduction in goodwill of $229 million and net deferred tax liabilities of $825 million, which amounts were associated with the exchanged ETP common units as a result of previous transactions whereby the Company had acquired ETP common units (and previously, Regency common units and Class F units) in exchange for other assets.

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		2014
Current assets	$	4,698	$	6,029
Property, plant and equipment, net	45,087		38,907
Other assets	15,388		17,582
Total assets	$	65,173	$	62,518
Current liabilities	$	4,121	$	6,585
Non-current liabilities	34,021		30,622
Equity	27,031		25,311
Total liabilities and equity	$	65,173	$	62,518

	Years Ended December 31,
	2015		2014		2013
Revenue	$	34,292	$	55,475	$	48,335
Operating income	2,259		2,443		1,619
Net income	1,521		1,299		746

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,
	2015		2014
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		6
Unamortized fair value adjustments	76		99
Total debt outstanding	1,166		1,190
Less: Current maturities of long-term debt	1		1
Total long-term debt, less current maturities	$	1,165	$	1,189

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, 2015 and 2014 was $1.20 billion and $1.24 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, 2015, the Company has scheduled long-term debt principal payments as follows:

Years Ended December 31,
2016	$	—
2017	300
2018	400
2019	150
2020	—
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, 2015, 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 $12 million in the aggregate at December 31, 2015.

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 3.295% at December 31, 2015.

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, 2015, the Company is in compliance with these covenants.

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Benefits

12 Months Ended

Dec. 31, 2015

Postemployment Benefits [Abstract]

Benefits

RETIREMENT BENEFITS:

Postretirement Benefit Plans

Postretirement benefits expense for the years ended December 31, 2015 and 2014 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,
	2015			2014
Change in benefit obligation:
Benefit obligation at beginning of period	$	24		$	25
Interest cost	1			1
Actuarial (gain) loss	(2		)	1
Benefits paid, net	(2		)	(2		)
Dispositions	—			(1		)
Benefit obligation at end of period	$	21		$	24
Change in plan assets:
Fair value of plan assets at beginning of period	$	114		$	110
Return on plan assets and other	(1		)	4
Employer contributions	7			7
Benefits paid, net	(2		)	(2		)
Dispositions	—			(5		)
Fair value of plan assets at end of period	$	118		$	114
Amount overfunded at end of period (1)	$	(97	)	$	(90	)
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial loss	$	(10	)	$	(16	)
Prior service cost	14			15
	$	4		$	(1	)

⁽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,
	2015			2014			2013
Interest cost	$	1		$	1		$	1
Expected return on plan assets	(6		)	(5		)	(5		)
Prior service credit amortization	1			1			1
Actuarial loss amortization	(1		)	(1		)	(1		)
Net periodic benefit cost	$	(5	)	$	(4	)	$	(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 2016 is $1 million.

Assumptions.  The weighted-average discount rate used in determining benefit obligations was 3.84% and 3.68% at December 31, 2015 and 2014, 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,
	2015		2014		2013
Discount rate	3.60	%	4.29	%	3.66	%
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,
	2015		2014
Health care cost trend rate	8.10	%	7.60	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.71	%	4.90	%
Year that the rate reaches the ultimate trend rate	2021		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%, fixed income of 65% to 75% and cash and cash equivalents of up to 10%.  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,
	2015		2014
Cash and cash equivalents	$	3	$	3
Mutual fund (1)	115		111
Total	$	118	$	114

⁽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.  As of December 31, 2014, the fund was primarily comprised of 38% equities, 52% fixed income securities, and 10% 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 2016 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
2016	$	2
2017	2
2018	1
2019	1
2020	1
2021 – 2025	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, 2015, 2014, and 2013 were $2 million, $3 million, and $6 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, 2015, 2014, and 2013 were $1 million, $2 million, and $3 million, respectively.

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Taxes on Income

12 Months Ended

Dec. 31, 2015

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,
	2015		2014			2013
	(Restated)		(Restated)
Current expense (benefit):
Federal	$	21	$	258		$	(52	)
State	—		32			(7		)
Total	21		290			(59		)
Deferred expense (benefit):
Federal	$	17	$	(130	)	$	119
State	14		22			38
Total	31		(108		)	157
Total income tax expense	$	52	$	182		$	98

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,
	2015			2014			2013
	(Restated)			(Restated)
Computed statutory income tax expense (benefit) at 35%	$	55		$	50		$	(165	)
Changes in income taxes resulting from:
Premium on debt retirement	—			(10		)	—
State income taxes, net of federal income tax benefit	9			36			21
Non-deductible goodwill impairment	—			—			241
Non-deductible goodwill included in the Lake Charles LNG Transaction	—			105			—
Audit settlements	(7		)	—			—
Other	(5		)	1			1
Income tax expense	$	52		$	182		$	98

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,
	2015			2014
	(Restated)			(Restated)
Deferred income tax assets:
Other postretirement benefits	$	5		$	5
Debt amortization	57			41
Other	32			27
Total deferred income tax assets	94			73
Valuation allowance	(2		)	(2		)
Net deferred income tax assets (included within other non-current assets, net)	$	92		$	71
Deferred income tax liabilities:
Property, plant and equipment	$	(796	)	$	(794	)
Investment in unconsolidated affiliates	(20		)	(810		)
Other	(1		)	(6		)
Total deferred income tax liabilities	(817		)	(1,610		)
Net deferred income tax liability	$	(725	)	$	(1,539	)

As of December 31, 2015, the Company has $15 million ($10 million, net of federal tax) of unrecognized tax benefits, $9 million of which would impact the Company’s effective income tax rate if recognized.  The Company expects that its unrecognized tax benefits will be reduced by $2 million within the next 12 months.

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 the tax periods prior to 2012. The Company was under examination by the Internal Revenue Service (IRS) for the tax years 2004 through 2009. In July of 2015, the Company and the IRS settled all issues related to the IRS examination of the 2004 through 2009 tax years. As a result of the settlement, the Company recognized a net tax benefit of $7 million.

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Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2015

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, 2015 and 2014 .

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,
	2015		2014			2013
Cash Flow Hedges:
Commodity contracts — Gathering and Processing:
Change in fair value – decrease in accumulated other comprehensive income	$	—	$	—		$	(3	)
Economic Hedges:
Interest rate contracts:
Change in fair value — increase (decrease) in interest expense	—		(7		)	29
Commodity contracts:
Change in fair value — decrease in deferred natural gas purchases	—		—			(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, 2015

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 $18 million and were reflected as plant, property and equipment on our balance sheet as of December 31, 2015 and 2014. In addition, the Company had $6 million legally restricted for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2015.

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,
	2015			2014			2013
Beginning balance	$	58		$	55		$	46
Revisions	—			3			11
Settled	(3		)	(3		)	(1		)
Disposals	—			—			(4		)
Accretion expense	3			3			3
Ending balance	$	58		$	58		$	55

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies [Abstract]

Commitments and Contingencies Disclosure

REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:

Trunkline Transfer Applications

In October 2011, Trunkline and Sea Robin jointly filed with FERC to transfer all of Trunkline’s offshore facilities, and certain related onshore facilities, by sale and transfer to Sea Robin to consolidate and streamline the ownership and operation of all regulated offshore assets under one entity and better position the offshore assets competitively.  Several parties filed interventions and protests of this filing.  On June 21, 2012, FERC issued an order granting Trunkline permission and approval to proceed with the transfer, subject to compliance with certain regulatory requirements.  On July 31, 2012 Sea Robin and Trunkline made the necessary compliance filings with FERC.  The transfer of the offshore facilities to Sea Robin was effective September 1, 2012.

On July 26, 2012, Trunkline filed an application with the FERC for approval to transfer approximately 770 miles of underutilized loop piping facilities by sale to an affiliate, and such facilities are contemplated to be converted to crude oil transportation service.  This sale was approved by the FERC on November 7, 2013, and the transaction was consummated on December 1, 2015.

Sea Robin Rate Case

On December 2, 2013, Sea Robin filed a general NGA Section 4 rate case at the FERC as required by a previous rate case settlement. In the filing, Sea Robin seeks to increase its authorized rates to recover costs related to asset retirement obligations, depreciation, and return and taxes. Filed rates were put into effect June 1, 2014 and estimated settlement rates were put into effect September 1, 2014, subject of refund. A settlement was reached with the shippers and a stipulation and agreement was filed with the FERC on July 23, 2014. The settlement was certified to the FERC by the administrative law judge on October 7, 2014 and was approved by the FERC on June 26, 2015. In September 2015, related to the final settlement, Sea Robin made refunds to customers totaling $11 million, including interest.

PEPL Holdings Guarantee of Collection

The Company fully and unconditionally guaranteed (the “Panhandle Guarantee”) all of the payment obligations of Regency and Regency Energy Finance Corp. under their $600 million in aggregate principal amount of 4.50% senior notes due November 2023, until May 28, 2105, at which time ETP entered into a supplemental indenture relating to the senior notes pursuant to which it has agreed to become a co-obligor with respect to the payment obligations thereunder. Accordingly, pursuant to the terms of the senior notes, the Company’s obligations under the Panhandle Guarantee were released.

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.

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,
	2015		2014
Current	$	—	$	1
Non-current	3		3
Total environmental liabilities	$	3	$	4

Litigation and Other Claims

The Company is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business.

Attorney General of the Commonwealth of Massachusetts v New England Gas Company.  On July 7, 2011, the Massachusetts Attorney General (“AG”) filed a regulatory complaint with the Massachusetts Department of Public Utilities (“MDPU”) against New England Gas Company with respect to certain environmental cost recoveries.  The AG is seeking a refund to New England Gas Company customers for alleged “excessive and imprudently incurred costs” related to legal fees associated with Southern Union’s environmental response activities.  In the complaint, the AG requests that the MDPU initiate an investigation into the New England Gas Company’s collection and reconciliation of recoverable environmental costs including:  (i) the prudence of any and all legal fees, totaling $19 million, that were charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005, the year when a partner in the firm, Southern Union’s former Vice Chairman, President and Chief Operating Officer, joined Southern Union’s management team; (ii) the prudence of any and all legal fees that were charged by the Bishop, London & Dodds firm and passed through the recovery mechanism since 2005, the period during which a member of the firm served as Southern Union’s Chief Ethics Officer; and (iii) the propriety and allocation of certain legal fees charged that were passed through the recovery mechanism that the AG contends only qualify for a lesser, 50%, level of recovery.  Southern Union has filed its answer denying the allegations and moved to dismiss the complaint, in part on a theory of collateral estoppel.  The hearing officer has deferred consideration of Southern Union’s motion to dismiss.  The AG’s motion to be reimbursed expert and consultant costs by Southern Union of up to $150,000 was granted.  By tariff, these costs are recoverable through rates charged to New England Gas Company customers. The hearing officer previously stayed discovery pending resolution of a dispute concerning the applicability of attorney-client privilege to legal billing invoices.  The MDPU issued an interlocutory order on June 24, 2013 that lifted the stay, and discovery has resumed. The Company (as successor to Southern Union) believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, the Company will continue to assess its potential exposure for such cost recoveries as the matter progresses.

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, 2015 and 2014, the Company recorded litigation and other claim-related accrued liabilities of $22 million and $21 million, respectively. The Company does not have any material litigation or other claim contingency matters assessed as probable or reasonably possible that would require disclosure in the financial statements.

Other Commitments and Contingencies

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

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2015

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 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. Early adoption is permitted as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within those annual periods. ASU 2014-09 can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Company is currently evaluating the impact, if any, that adopting this new accounting standard will have on our revenue recognition policies.

In November 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”), which is intended to improve how deferred taxes are classified on organizations’ balance sheets. The ASU eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations are now required to classify all deferred tax assets and liabilities as noncurrent. We adopted the provisions of ASU 2015-17 upon issuance and prior period amounts have been reclassified to conform to the current period presentation. As of December 31, 2014, $3 million in current deferred tax assets were reclassified in the consolidated balance sheet from other current assets to deferred income taxes liability.

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	2015			2014
Land and improvements		$	8		$	8
Buildings and improvements	6 – 22	340			340
Pipelines and equipment	5 – 46	2,387			2,353
Natural gas storage facilities	5 – 46	329			323
Vehicles	5	24			23
Right of way	36 – 40	23			23
Furniture and fixtures	5 – 12	34			33
Linepack		57			57
Other	2 – 19	99			192
Construction work in progress		37			43
Total property, plant and equipment		3,338			3,395
Accumulated depreciation and amortization		(286		)	(269		)
Net property, plant and equipment		$	3,052		$	3,126

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 2015, the Partnership voluntarily changed the date of the annual goodwill impairment testing to the first day of the fourth quarter. The Partnership believes this new date is preferable because it allows for more timely completion of the annual goodwill impairment test prior to the end of the annual financial reporting period. This change in accounting principle does not delay, accelerate or avoid any potential impairment loss, nor does the change have a cumulative effect on income from continuing operations, net income or loss, or net assets.  This change was not applied retrospectively, as doing so would require the use of significant estimates and assumptions that include hindsight. Accordingly, the Partnership applied the change in annual goodwill impairment testing date prospectively beginning October 1, 2015.

The Company did not record a goodwill impairment for the years ended December 31, 2015 and 2014. The Company’s annual goodwill impairment test for the year ended December 31, 2013 resulted in a $689 million goodwill impairment related to the Lake Charles LNG reporting unit.

Changes in the carrying amount of goodwill were as follows:

	Total
Balance, December 31, 2013	$	1,336
Lake Charles LNG Transaction	(184		)
Balance, December 31, 2014	1,152
ETP common units exchange transaction	(229		)
Balance, December 31, 2015	$	923

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 a note receivable from a related party.

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 concentration of customers in the electric and gas utility industries as well as oil and natural gas producers and municipalities. This concentration of customers 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, 2015 and 2014.

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, 2015

Error Corrections and Prior Period Adjustments Restatement [Line Items]

Restatement to Cash Flow [Table Text Block]

	Year ended
	December 31, 2015									December 31, 2014
	As Reported			Adjustment			As Restated			As Reported			Adjustment			As Restated
Net income (loss)	$	125		$	(20	)	$	105		$	(3	)	$	(36	)	$	(39	)
Deferred income taxes	14			17			31			(139		)	31			(108		)
Changes in operating assets and liabilities	(69		)	3			(66		)	192			5			197

Other Current Liabilities [Table Text Block]

	December 31,
	2015		2014
Accrued capital expenditures	$	21	$	15
Accrued property taxes	5		9
Other	29		32
Total other current liabilities	$	55	$	56

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,
	2015			2014		2013
Non-cash investing activities:
Contribution from affiliate	$	—		$	376	$	—
Note receivable issued in exchange for investment in ETP	(1,369		)	—		—
Settlement of affiliate liability	793			—		—
Supplemental cash flow information:
Accrued capital expenditures	$	21		$	15	$	13
Cash paid for interest, net of interest capitalized	76			75		142
Cash received for interest on note receivable from affiliate	16			—		—

Property, Plant and Equipment [Table Text Block]

		December 31,
	Lives in Years	2015			2014
Land and improvements		$	8		$	8
Buildings and improvements	6 – 22	340			340
Pipelines and equipment	5 – 46	2,387			2,353
Natural gas storage facilities	5 – 46	329			323
Vehicles	5	24			23
Right of way	36 – 40	23			23
Furniture and fixtures	5 – 12	34			33
Linepack		57			57
Other	2 – 19	99			192
Construction work in progress		37			43
Total property, plant and equipment		3,338			3,395
Accumulated depreciation and amortization		(286		)	(269		)
Net property, plant and equipment		$	3,052		$	3,126

Schedule of Inventory, Current [Table Text Block]

The following table presents the components of inventory:

	December 31,
	2015		2014
Natural gas (1)	$	98	$	105
Materials and supplies	15		14
	$	113	$	119

⁽¹⁾  Natural gas volumes held for operations at December 31, 2015 and 2014 were 43.2 TBtu and 34.3 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,
	2015		2014		2013
Customer A(1)	—	%	—	%	10	%
Customer B(2)	—		—		22
Customer C	11		11		6
Customer D	10		—		—
Other top 10 customers	28		40		20
Remaining customers	51		49		42
Total percentage	100	%	100	%	100	%

⁽¹⁾  SUGS, which was deconsolidated on April 30, 2013, had contracted to sell its entire owned or controlled output of NGL equity volumes to Customer A. Pricing for the NGL equity volumes sold to Customer A throughout the contract period was OPIS pricing based at Mont Belvieu, Texas delivery points.

⁽²⁾  Customer B is the sole customer of Lake Charles LNG, which was deconsolidated effective January 1, 2014.

MarchJune2015Restatement [Member]

Error Corrections and Prior Period Adjustments Restatement [Line Items]

Restatement to Balance Sheet [Table Text Block]

	March 31, 2015							June 30, 2015
	(unaudited)							(unaudited)
	As Reported		Adjustment			As Restated		As Reported		Adjustment			As Restated
Accounts payable to related parties	$	33	$	6		$	39	$	29	$	5		$	34
Total current liabilities	198		6			204		207		5			212
Deferred income taxes	1,511		31			1,542		1,528		6			1,534
Partners' capital	2,957		(37		)	2,920		2,951		(11		)	2,940
Total partners' capital	2,957		(37		)	2,920		2,952		(11		)	2,941

SeptemberDecember2015Restatement [Member]

Error Corrections and Prior Period Adjustments Restatement [Line Items]

Restatement to Balance Sheet [Table Text Block]

	September 30, 2015							December 31, 2015
	(unaudited)
	As Reported		Adjustment			As Restated		As Reported		Adjustment			As Restated
Accounts payable to related parties	$	57	$	6		$	63	$	99	$	26		$	125
Total current liabilities	238		6			244		273		26			299
Deferred income taxes	722		57			779		695		30			725
Partners' capital	2,874		(62		)	2,812		2,937		(56		)	2,881
Total partners' capital	2,875		(62		)	2,813		2,939		(56		)	2,883

MarchJune2014Restatement [Member]

Error Corrections and Prior Period Adjustments Restatement [Line Items]

Restatement to Balance Sheet [Table Text Block]

	March 31, 2014							June 30, 2014
	(unaudited)							(unaudited)
	As Reported		Adjustment			As Restated		As Reported		Adjustment			As Restated
Accounts payable to related parties	$	467	$	—		$	467	$	451	$	1		$	452
Total current liabilities	776		—			776		726		1			727
Deferred income taxes	1,469		(2		)	1,467		1,461		6			1,467
Partners' capital	2,926		2			2,928		2,915		(7		)	2,908
Total partners' capital	2,928		2			2,930		2,917		(7		)	2,910

SeptemberDecember2014 [Member]

Error Corrections and Prior Period Adjustments Restatement [Line Items]

Restatement to Balance Sheet [Table Text Block]

	September 30, 2014							December 31, 2014
	(unaudited)
	As Reported		Adjustment			As Restated		As Reported		Adjustment			As Restated
Accounts payable to related parties	$	462	$	1		$	463	$	38	$	5		$	43
Total current liabilities	687		1			688		237		5			242
Deferred income taxes	1,452		6			1,458		1,508		31			1,539
Partners' capital	2,925		(7		)	2,918		2,925		(36		)	2,889
Total partners' capital	2,927		(7		)	2,920		2,925		(36		)	2,889

QTDMarch2015.2014 [Member]

Error Corrections and Prior Period Adjustments Restatement [Line Items]

Restatement to Prior Year Income [Table Text Block]

	Three months ended
	March 31, 2015						March 31, 2014
	(unaudited)						(unaudited)
	As Reported		Adjustment		As Restated		As Reported			Adjustment			As Restated
Income tax expense from continuing operations	$	12	$	—	$	12	$	106		$	(2	)	$	104
Income (loss) from continuing operations	31		—		31		(35		)	2			(33		)
Net income (loss)	31		—		31		(35		)	2			(33		)
Income (loss) attributable to partners	31		—		31		(41		)	2			(39		)
Comprehensive income (loss)	31		—		31		(36		)	2			(34		)

QTDJune2015.2014 [Member]

Error Corrections and Prior Period Adjustments Restatement [Line Items]

Restatement to Prior Year Income [Table Text Block]

	Three months ended
	June 30, 2015								June 30, 2014
	(unaudited)								(unaudited)
	As Reported			Adjustment			As Restated		As Reported		Adjustment			As Restated
Income tax expense from continuing operations	$	25		$	(25	)	$	—	$	14	$	9		$	23
Income (loss) from continuing operations	(6		)	25			19		16		(9		)	7
Net income (loss)	(6		)	25			19		16		(9		)	7
Income (loss) attributable to partners	(6		)	25			19		16		(9		)	7
Comprehensive income (loss)	(6		)	25			19		16		(9		)	7

YTDJune2015.2014 [Member]

Error Corrections and Prior Period Adjustments Restatement [Line Items]

Restatement to Prior Year Income [Table Text Block]

	Six months ended
	June 30, 2015							June 30, 2014
	(unaudited)							(unaudited)
	As Reported		Adjustment			As Restated		As Reported			Adjustment			As Restated
Income tax expense from continuing operations	$	37	$	(25	)	$	12	$	120		$	7		$	127
Income (loss) from continuing operations	25		25			50		(19		)	(7		)	(26		)
Net income (loss)	25		25			50		(19		)	(7		)	(26		)
Income (loss) attributable to partners	25		25			50		(25		)	(7		)	(32		)
Comprehensive income (loss)	26		25			51		(20		)	(7		)	(27		)

QTDSeptember2015.2014 [Member]

Error Corrections and Prior Period Adjustments Restatement [Line Items]

Restatement to Prior Year Income [Table Text Block]

	Three months ended
	September 30, 2015								September 30, 2014
	(unaudited)								(unaudited)
	As Reported			Adjustment			As Restated		As Reported		Adjustment		As Restated
Income tax expense from continuing operations	$	(28	)	$	51		$	23	$	8	$	—	$	8
Income (loss) from continuing operations	76			(51		)	25		23		—		23
Net income (loss)	76			(51		)	25		23		—		23
Income (loss) attributable to partners	76			(51		)	25		23		—		23
Comprehensive income (loss)	76			(51		)	25		23		—		23

YTDSeptember2015.2014 [Member]

Error Corrections and Prior Period Adjustments Restatement [Line Items]

Restatement to Prior Year Income [Table Text Block]

	Nine months ended
	September 30, 2015							September 30, 2014
	(unaudited)							(unaudited)
	As Reported		Adjustment			As Restated		As Reported			Adjustment			As Restated
Income tax expense from continuing operations	$	9	$	26		$	35	$	128		$	7		$	135
Income (loss) from continuing operations	101		(26		)	75		4			(7		)	(3		)
Net income (loss)	101		(26		)	75		4			(7		)	(3		)
Income (loss) attributable to partners	101		(26		)	75		(2		)	(7		)	(9		)
Comprehensive income (loss)	102		(26		)	76		3			(7		)	(4		)

QTDDecember2015.2014 [Member]

Error Corrections and Prior Period Adjustments Restatement [Line Items]

Restatement to Prior Year Income [Table Text Block]

	Three months ended
	December 31, 2015							December 31, 2014
	(unaudited)							(unaudited)
	As Reported		Adjustment			As Restated		As Reported			Adjustment			As Restated
Income tax expense from continuing operations	$	23	$	(6	)	$	17	$	18		$	29		$	47
Income (loss) from continuing operations	24		6			30		(7		)	(29		)	(36		)
Net income (loss)	24		6			30		(7		)	(29		)	(36		)
Income (loss) attributable to partners	24		6			30		(7		)	(29		)	(36		)
Comprehensive income (loss)	25		6			31		(9		)	(29		)	(38		)

YTDDecember2015.2014 [Member]

Error Corrections and Prior Period Adjustments Restatement [Line Items]

Restatement to Prior Year Income [Table Text Block]

	Year ended
	December 31, 2015							December 31, 2014
	As Reported		Adjustment			As Restated		As Reported			Adjustment			As Restated
Income tax expense from continuing operations	$	32	$	20		$	52	$	146		$	36		$	182
Income (loss) from continuing operations	125		(20		)	105		(3		)	(36		)	(39		)
Net income (loss)	125		(20		)	105		(3		)	(36		)	(39		)
Income (loss) attributable to partners	125		(20		)	105		(9		)	(36		)	(45		)
Comprehensive income (loss)	127		(20		)	107		(6		)	(36		)	(42		)

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ETE Merger and Other Transactions (Tables)

12 Months Ended

Dec. 31, 2015

ETE Merger and Holdco Transaction [Abstract]

Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]

Summarized financial information for MGE and NEG is as follows:

	Year Ended December 31, 2013
Revenue from discontinued operations	$	415
Net income of discontinued operations, excluding effect of taxes and overhead allocations	65

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2015

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,
	2015		2014			2013
Operating revenues	$	18	$	33		$	56
Cost of natural gas and other energy	—		—			17
Operating and maintenance	16		16			—
General and administrative	31		33			71
Interest expense, net	—		—			(31		)
Interest income — affiliates	23		23			9
Income (loss) from unconsolidated affiliates	26		(12		)	15

dividends received from unconsolidated affiliates [Table Text Block]

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

	Years Ended December 31,
	2015		2014		2013
Distributions related to investment in:
ETP	$	39	$	9	$	8
Regency	16		61		44

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INVESTMENTS IN UNCONSOLIDATED AFFILIATES INVESTMENTS IN UNCONSOLIDATED AFFILIATES (Tables)

12 Months Ended

Dec. 31, 2015

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		2014
Current assets	$	4,698	$	6,029
Property, plant and equipment, net	45,087		38,907
Other assets	15,388		17,582
Total assets	$	65,173	$	62,518
Current liabilities	$	4,121	$	6,585
Non-current liabilities	34,021		30,622
Equity	27,031		25,311
Total liabilities and equity	$	65,173	$	62,518

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

12 Months Ended

Dec. 31, 2015

Equity Method Investments and Joint Ventures [Abstract]

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

	Years Ended December 31,
	2015		2014		2013
Revenue	$	34,292	$	55,475	$	48,335
Operating income	2,259		2,443		1,619
Net income	1,521		1,299		746

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Debt Obligations (Tables)

12 Months Ended

Dec. 31, 2015

Debt Instrument

Debt Disclosure [Text Block]

DEBT OBLIGATIONS:

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

	December 31,
	2015		2014
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		6
Unamortized fair value adjustments	76		99
Total debt outstanding	1,166		1,190
Less: Current maturities of long-term debt	1		1
Total long-term debt, less current maturities	$	1,165	$	1,189

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, 2015 and 2014 was $1.20 billion and $1.24 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, 2015, the Company has scheduled long-term debt principal payments as follows:

Years Ended December 31,
2016	$	—
2017	300
2018	400
2019	150
2020	—
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, 2015, 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 $12 million in the aggregate at December 31, 2015.

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 3.295% at December 31, 2015.

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, 2015, the Company is in compliance with these covenants.

Schedule Of Debt Instruments

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

	December 31,
	2015		2014
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		6
Unamortized fair value adjustments	76		99
Total debt outstanding	1,166		1,190
Less: Current maturities of long-term debt	1		1
Total long-term debt, less current maturities	$	1,165	$	1,189

Schedule of Maturities of Long-term Debt

As of December 31, 2015, the Company has scheduled long-term debt principal payments as follows:

Years Ended December 31,
2016	$	—
2017	300
2018	400
2019	150
2020	—
Thereafter	240
Total	$	1,090

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Benefits (Tables)

12 Months Ended

Dec. 31, 2015

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,
	2015			2014
Change in benefit obligation:
Benefit obligation at beginning of period	$	24		$	25
Interest cost	1			1
Actuarial (gain) loss	(2		)	1
Benefits paid, net	(2		)	(2		)
Dispositions	—			(1		)
Benefit obligation at end of period	$	21		$	24
Change in plan assets:
Fair value of plan assets at beginning of period	$	114		$	110
Return on plan assets and other	(1		)	4
Employer contributions	7			7
Benefits paid, net	(2		)	(2		)
Dispositions	—			(5		)
Fair value of plan assets at end of period	$	118		$	114
Amount overfunded at end of period (1)	$	(97	)	$	(90	)
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial loss	$	(10	)	$	(16	)
Prior service cost	14			15
	$	4		$	(1	)

⁽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,
	2015			2014			2013
Interest cost	$	1		$	1		$	1
Expected return on plan assets	(6		)	(5		)	(5		)
Prior service credit amortization	1			1			1
Actuarial loss amortization	(1		)	(1		)	(1		)
Net periodic benefit cost	$	(5	)	$	(4	)	$	(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,
	2015		2014		2013
Discount rate	3.60	%	4.29	%	3.66	%
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,
	2015		2014
Health care cost trend rate	8.10	%	7.60	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.71	%	4.90	%
Year that the rate reaches the ultimate trend rate	2021		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,
	2015		2014
Cash and cash equivalents	$	3	$	3
Mutual fund (1)	115		111
Total	$	118	$	114

⁽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.  As of December 31, 2014, the fund was primarily comprised of 38% equities, 52% 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
2016	$	2
2017	2
2018	1
2019	1
2020	1
2021 – 2025	6

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Taxes on Income (Tables)

12 Months Ended

Dec. 31, 2015

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,
	2015		2014			2013
	(Restated)		(Restated)
Current expense (benefit):
Federal	$	21	$	258		$	(52	)
State	—		32			(7		)
Total	21		290			(59		)
Deferred expense (benefit):
Federal	$	17	$	(130	)	$	119
State	14		22			38
Total	31		(108		)	157
Total income tax expense	$	52	$	182		$	98

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,
	2015			2014			2013
	(Restated)			(Restated)
Computed statutory income tax expense (benefit) at 35%	$	55		$	50		$	(165	)
Changes in income taxes resulting from:
Premium on debt retirement	—			(10		)	—
State income taxes, net of federal income tax benefit	9			36			21
Non-deductible goodwill impairment	—			—			241
Non-deductible goodwill included in the Lake Charles LNG Transaction	—			105			—
Audit settlements	(7		)	—			—
Other	(5		)	1			1
Income tax expense	$	52		$	182		$	98

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,
	2015			2014
	(Restated)			(Restated)
Deferred income tax assets:
Other postretirement benefits	$	5		$	5
Debt amortization	57			41
Other	32			27
Total deferred income tax assets	94			73
Valuation allowance	(2		)	(2		)
Net deferred income tax assets (included within other non-current assets, net)	$	92		$	71
Deferred income tax liabilities:
Property, plant and equipment	$	(796	)	$	(794	)
Investment in unconsolidated affiliates	(20		)	(810		)
Other	(1		)	(6		)
Total deferred income tax liabilities	(817		)	(1,610		)
Net deferred income tax liability	$	(725	)	$	(1,539	)

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Derivative Instrument and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2015

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,
	2015		2014			2013
Cash Flow Hedges:
Commodity contracts — Gathering and Processing:
Change in fair value – decrease in accumulated other comprehensive income	$	—	$	—		$	(3	)
Economic Hedges:
Interest rate contracts:
Change in fair value — increase (decrease) in interest expense	—		(7		)	29
Commodity contracts:
Change in fair value — decrease in deferred natural gas purchases	—		—			(7		)

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

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

		December 31,
	Lives in Years	2015			2014
Land and improvements		$	8		$	8
Buildings and improvements	6 – 22	340			340
Pipelines and equipment	5 – 46	2,387			2,353
Natural gas storage facilities	5 – 46	329			323
Vehicles	5	24			23
Right of way	36 – 40	23			23
Furniture and fixtures	5 – 12	34			33
Linepack		57			57
Other	2 – 19	99			192
Construction work in progress		37			43
Total property, plant and equipment		3,338			3,395
Accumulated depreciation and amortization		(286		)	(269		)
Net property, plant and equipment		$	3,052		$	3,126

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ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2015

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,
	2015			2014			2013
Beginning balance	$	58		$	55		$	46
Revisions	—			3			11
Settled	(3		)	(3		)	(1		)
Disposals	—			—			(4		)
Accretion expense	3			3			3
Ending balance	$	58		$	58		$	55

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2015

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,
	2015		2014
Current	$	—	$	1
Non-current	3		3
Total environmental liabilities	$	3	$	4

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QUARTERLY OPERATIONS Quarterly Operations (Tables)

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Error Corrections and Prior Period Adjustments Restatement [Line Items]

Schedule of Quarterly Financial Information [Table Text Block]

	Quarters Ended
	March 31, 2015			June 30, 2015			September 30, 2015			December 31, 2015			Total
OPERATING REVENUES:
Transportation and storage of natural gas	$	149		$	123		$	121		$	135		$	528
Other	6			5			5			4			20
Total operating revenues	155			128			126			139			548
OPERATING EXPENSES:
Cost of natural gas and other energy	2			1			1			—			4
Operating and maintenance	53			50			56			57			216
General and administrative	12			11			12			7			42
Depreciation and amortization	35			35			31			32			133
Total operating expenses	102			97			100			96			395
OPERATING INOMCE (LOSS)	53			31			26			43			153
OTHER INCOME (EXPENSE):
Interest expense, net	(13		)	(12		)	(13		)	(12		)	(50		)
Equity in earnings (losses) of unconsolidated affiliates	4			(6		)	28			—			26
Interest income - affiliates	—			1			6			16			23
Other, net	(1		)	5			1			—			5
Total other income (expense),net	(10		)	(12		)	22			4			4
INCOME (LOSS) FROM BEFORE INCOME TAX EXPENSE	43			19			48			47			157
Income tax expense	12			—			23			17			52
NET INCOME (LOSS)	31			19			25			30			105
less: Net income (loss) attributable to noncontrolling interest	—			—			—			—			—
NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS	$	31		$	19		$	25		$	30		$	105

	As of
	March 31, 2015			June 30, 2015			September 30, 2015			December 31, 2015
ASSETS
Current assets:
Cash and cash equivalents	$	47		$	65		$	30		$	3
Accounts receivable, net	51			40			41			48
Accounts receivable from related companies	42			54			120			172
Exchanges receivable	12			10			9			5
Inventories	83			106			99			113
Other current assets	13			13			15			9
Total current assets	248			288			314			350
Property, plant and equipment	3,403			3,428			3,456			3,338
Accumulated depreciation	(292		)	(319		)	(342		)	(286		)
Net property, plant and equipment	3,111			3,109			3,114			3,052
Investments in unconsolidated affiliates	1,428			1,404			15			15
Other non-current assets, net	110			116			127			122
Advances to affiliates	40			40			—			258
Note receivable from related party	40			40			1,369			574
Goodwill	1,152			1,152			923			923
Total assets	$	6,129		$	6,149		$	5,862		$	5,294
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Current maturities of long-term debt	$	1		$	1		$	1		$	1
Accounts payable and accrued liabilities	2			4			4			3
Accounts payable to related parties	39			34			63			125
Exchanges payable	76			91			83			94
Accrued interest	24			12			24			12
Customer advances and deposits	8			11			9			9
Other current liabilities	54			59			60			55
Total current liabilities	204			212			244			299
Long-term debt, less current maturities	1,184			1,178			1,172			1,165
Deferred income taxes	1,542			1,534			779			725
Advances from affiliates	—			—			566			—
Other non-current liabilities	279			284			289			222
Partners' capital:
Partners' capital	2,920			2,940			2,812			2,881
Accumulated other comprehensive income	—			1			1			2
Total partners' capital	2,920			2,941			2,813			2,883
Total liabilities and partners' capital	$	6,129		$	6,149		$	5,862		$	5,294

	Quarters Ended
	March 31, 2014			June 30, 2014			September 30, 2014			December 31, 2014			Total
OPERATING REVENUES:
Transportation and storage of natural gas	$	170		$	122		$	125		$	138		$	555
Other	8			6			7			5			26
Total operating revenues	178			128			132			143			581
OPERATING EXPENSES:
Cost of natural gas and other energy	—			2			1			—			3
Operating and maintenance	47			49			55			58			209
General and administrative	10			11			12			13			46
Depreciation and amortization	31			32			33			34			130
Total operating expenses	88			94			101			105			388
OPERATING INOMCE (LOSS)	90			34			31			38			193
OTHER INCOME (EXPENSE):
Interest expense, net	(12		)	(19		)	(15		)	(20		)	(66		)
Equity in earnings (losses) of unconsolidated affiliates	(8		)	6			9			(19		)	(12		)
Interest income - affiliates	5			7			5			6			23
Other, net	(4		)	2			1			6			5
Total other income (expense),net	(19		)	(4		)	—			(27		)	(50		)
INCOME (LOSS) FROM BEFORE INCOME TAX EXPENSE	71			30			31			11			143
Income tax expense	104			23			8			47			182
NET INCOME (LOSS)	(33		)	7			23			(36		)	(39		)
less: Net income (loss) attributable to noncontrolling interest	6			—			—			—			6
NET INOME (LOSS) ATTRIBUTABLE TO PARTNERS	$	(39	)	$	7		$	23		$	(36	)	$	(45	)

	As of
	March 31, 2014			June 30, 2014			September 30, 2014			December 31, 2014
ASSETS
Current assets:
Cash and cash equivalents	$	74		$	32		$	55		$	32
Accounts receivable, net	55			51			51			58
Accounts receivable from related companies	33			57			30			128
Exchanges receivable	62			45			17			11
Inventories	160			147			115			119
Other current assets	15			20			48			10
Total current assets	399			352			316			358
Property, plant and equipment	3,316			3,331			3,360			3,395
Accumulated depreciation	(192		)	(215		)	(243		)	(269		)
Net property, plant and equipment	3,124			3,116			3,117			3,126
Investments in unconsolidated affiliates	1,502			1,488			1,480			1,443
Other non-current assets, net	95			105			106			109
Advances to affiliates	—			—			—			—
Note receivable from related party	386			386			386			—
Goodwill	1,152			1,152			1,152			1,152
Total assets	$	6,658		$	6,599		$	6,557		$	6,188
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Current maturities of long-term debt	$	1		$	1		$	1		$	1
Accounts payable and accrued liabilities	2			5			4			6
Accounts payable to related parties	467			452			463			43
Exchanges payable	214			179			117			114
Accrued interest	24			12			24			12
Customer advances and deposits	16			21			13			10
Other current liabilities	52			57			66			56
Total current liabilities	776			727			688			242
Long-term debt, less current maturities	1,203			1,201			1,195			1,189
Deferred income taxes	1,467			1,467			1,458			1,539
Advances from affiliates	—			—			—			51
Other non-current liabilities	282			294			296			278
Partners' capital:
Partners' capital	2,928			2,908			2,918			2,889
Accumulated other comprehensive income	2			2			2			—
Total partners' capital	2,930			2,910			2,920			2,889
Total liabilities and partners' capital	$	6,658		$	6,599		$	6,557		$	6,188

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Description of the Business (Details)	12 Months Ended
	Dec. 31, 2015
General partnership
Description of the Business
General 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, 2015	Dec. 31, 2014	Dec. 31, 2013
Restricted Cash and Cash Equivalents Items
Non-cash contribution from affiliate	$ 0	$ 376	$ 0
Notes Receivable, Related Parties, Noncurrent	(1,369)	0	0
non-cash payment from subsidiary of ETP	793	0	0
Accrued Capital Expenditures	21	15	13
Interest Paid, Net	76	75	142
Increase (Decrease) in Notes Receivables	$ 16	$ 0	$ 0

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Policies - Inventory (Details) MMbtu in Millions, $ in Millions		Dec. 31, 2015 USD ($) MMbtu	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2014 USD ($) MMbtu	Sep. 30, 2014 USD ($)	Jun. 30, 2014 USD ($)	Mar. 31, 2014 USD ($)
Natural Gas Volumes | MMbtu		43.2				34.3
Natural Gas Inventory	[1]	$ 98				$ 105
Inventory, Raw Materials and Supplies		15				14
Inventories		113	$ 99	$ 106	$ 83	119	$ 115	$ 147	$ 160
Energy Related Inventory		$ 113				$ 119

[1] Natural gas volumes held for operations at December 31, 2015 and 2014 were 43.2 TBtu and 34.3 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, 2015	Dec. 31, 2014	Dec. 31, 2013	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Feb. 19, 2014
Goodwill	$ 923	$ 1,152	$ 1,336	$ 923	$ 1,152	$ 1,152	$ 1,152	$ 1,152	$ 1,152
Goodwill, Other Changes	(229)
Goodwill, Impairment Loss	$ 0	0	689
Successor
Goodwill, Impairment Loss			$ 689
Lake Charles LNG Transaction [Member]
Goodwill										$ 184
Goodwill, Other Changes		$ (184)

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Policies - Top Customers (Details)		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Entity-Wide Revenue, Major Customer, Percentage		100.00%	100.00%	100.00%
Phillips 66 Company [Member]
Entity-Wide Revenue, Major Customer, Percentage	[1]	0.00%	0.00%	10.00%
BG LNG Services
Entity-Wide Revenue, Major Customer, Percentage	[2]	0.00%	0.00%	22.00%
Ameren Corporation [Member]
Entity-Wide Revenue, Major Customer, Percentage		11.00%	11.00%	6.00%
Exelon Generation Company [Member] [Member]
Entity-Wide Revenue, Major Customer, Percentage		10.00%	0.00%	0.00%
Other Top 10 Customers
Entity-Wide Revenue, Major Customer, Percentage		28.00%	40.00%	20.00%
Remaining Customers
Entity-Wide Revenue, Major Customer, Percentage		51.00%	49.00%	42.00%

[1] SUGS, which was deconsolidated on April 30, 2013, had contracted to sell its entire owned or controlled output of NGL equity volumes to Customer A. Pricing for the NGL equity volumes sold to Customer A throughout the contract period was OPIS pricing based at Mont Belvieu, Texas delivery points.

[2] is the sole customer of Lake Charles LNG, which was deconsolidated effective January 1, 2014.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Policies - PPE (Details) - USD ($) $ in Millions	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 3,338	$ 3,456	$ 3,428	$ 3,403	$ 3,395	$ 3,360	$ 3,331	$ 3,316
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	286	342	319	292	269	243	215	192
Net property, plant and equipment	$ 3,052	$ 3,114	$ 3,109	$ 3,111	$ 3,126	$ 3,117	$ 3,116	$ 3,124

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Policies - Other Current Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013
Other Liabilities, Current [Abstract]
Accrued Capital Expenditures	$ 21				$ 15				$ 13
Accrued Property Tax	5				9
Customer advances and deposits	29				32
Other current liabilities	$ 55	$ 60	$ 59	$ 54	$ 56	$ 66	$ 57	$ 52

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Policies - New Accounting Pronouncements (Details) $ in Millions	Dec. 31, 2014 USD ($)
Accounting Policies [Abstract]
Deferred Tax Assets, Net, Current	$ 3

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Restatement (Details) - USD ($)	3 Months Ended								6 Months Ended		9 Months Ended		12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Jun. 30, 2015	Jun. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Accounts Payable, Related Parties, Current	$ 125,000,000	$ 63,000,000	$ 34,000,000	$ 39,000,000	$ 43,000,000	$ 463,000,000	$ 452,000,000	$ 467,000,000	$ 34,000,000	$ 452,000,000	$ 63,000,000	$ 463,000,000	$ 125,000,000	$ 43,000,000
Income Tax Expense (Benefit)	17,000,000	23,000,000	0	12,000,000	47,000,000	8,000,000	23,000,000	104,000,000	12,000,000	127,000,000	35,000,000	135,000,000	52,000,000	182,000,000	$ 98,000,000
Liabilities, Current	299,000,000	244,000,000	212,000,000	204,000,000	242,000,000	688,000,000	727,000,000	776,000,000	212,000,000	727,000,000	244,000,000	688,000,000	299,000,000	242,000,000
Deferred Tax Liabilities, Net, Noncurrent	725,000,000	779,000,000	1,534,000,000	1,542,000,000	1,539,000,000	1,458,000,000	1,467,000,000	1,467,000,000	1,534,000,000	1,467,000,000	779,000,000	1,458,000,000	725,000,000	1,539,000,000
General Partners' Capital Account	2,881,000,000	2,812,000,000	2,940,000,000	2,920,000,000	2,889,000,000	2,918,000,000	2,908,000,000	2,928,000,000	2,940,000,000	2,908,000,000	2,812,000,000	2,918,000,000	2,881,000,000	2,889,000,000
Partners' Capital	2,883,000,000	2,813,000,000	2,941,000,000	2,920,000,000	2,889,000,000	2,920,000,000	2,910,000,000	2,930,000,000	2,941,000,000	2,910,000,000	2,813,000,000	2,920,000,000	2,883,000,000	2,889,000,000	3,068,000,000	$ 4,028,000,000
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest	30,000,000	25,000,000	19,000,000	31,000,000	(36,000,000)	23,000,000	7,000,000	(33,000,000)	50,000,000	(26,000,000)	75,000,000	(3,000,000)	105,000,000	(39,000,000)	(570,000,000)
Net Income (Loss) Attributable to Parent	30,000,000	25,000,000	19,000,000	31,000,000	(36,000,000)	23,000,000	7,000,000	(33,000,000)	50,000,000	(26,000,000)	75,000,000	(3,000,000)	105,000,000	(39,000,000)	(535,000,000)
Net Income (Loss) Allocated to Limited Partners	30,000,000	25,000,000	19,000,000	31,000,000	(36,000,000)	23,000,000	7,000,000	(39,000,000)	50,000,000	(32,000,000)	75,000,000	(9,000,000)	105,000,000	(45,000,000)	(499,000,000)
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	31,000,000	25,000,000	19,000,000	31,000,000	(38,000,000)	23,000,000	7,000,000	(34,000,000)	51,000,000	(27,000,000)	76,000,000	(4,000,000)	107,000,000	(42,000,000)	(507,000,000)
Increase (Decrease) in Deferred Income Taxes													31,000,000	(108,000,000)	181,000,000
Increase (Decrease) in Other Operating Assets and Liabilities, Net													(66,000,000)	197,000,000	$ (159,000,000)
Scenario, Previously Reported [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Accounts Payable, Related Parties, Current	99,000,000	57,000,000	29,000,000	33,000,000	38,000,000	462,000,000	451,000,000	467,000,000	29,000,000	451,000,000	57,000,000	462,000,000	99,000,000	38,000,000
Income Tax Expense (Benefit)	23,000,000	(28,000,000)	25,000,000	12,000,000	18,000,000	8,000,000	14,000,000	106,000,000	37,000,000	120,000,000	9,000,000	128,000,000	32,000,000	146,000,000
Liabilities, Current	273,000,000	238,000,000	207,000,000	198,000,000	237,000,000	687,000,000	726,000,000	776,000,000	207,000,000	726,000,000	238,000,000	687,000,000	273,000,000	237,000,000
Deferred Tax Liabilities, Net, Noncurrent	695,000,000	722,000,000	1,528,000,000	1,511,000,000	1,508,000,000	1,452,000,000	1,461,000,000	1,469,000,000	1,528,000,000	1,461,000,000	722,000,000	1,452,000,000	695,000,000	1,508,000,000
General Partners' Capital Account	2,937,000,000	2,874,000,000	2,951,000,000	2,957,000,000	2,925,000,000	2,925,000,000	2,915,000,000	2,926,000,000	2,951,000,000	2,915,000,000	2,874,000,000	2,925,000,000	2,937,000,000	2,925,000,000
Partners' Capital	2,939,000,000	2,875,000,000	2,952,000,000	2,957,000,000	2,925,000,000	2,927,000,000	2,917,000,000	2,928,000,000	2,952,000,000	2,917,000,000	2,875,000,000	2,927,000,000	2,939,000,000	2,925,000,000
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest	24,000,000	76,000,000	(6,000,000)	31,000,000	(7,000,000)	23,000,000	16,000,000	(35,000,000)	25,000,000	(19,000,000)	101,000,000	4,000,000	125,000,000	(3,000,000)
Net Income (Loss) Attributable to Parent	24,000,000	76,000,000	(6,000,000)	31,000,000	(7,000,000)	23,000,000	16,000,000	(35,000,000)	25,000,000	(19,000,000)	101,000,000	4,000,000	125,000,000	(3,000,000)
Net Income (Loss) Allocated to Limited Partners	24,000,000	76,000,000	(6,000,000)	31,000,000	(7,000,000)	23,000,000	16,000,000	(41,000,000)	25,000,000	(25,000,000)	101,000,000	(2,000,000)	125,000,000	(9,000,000)
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	25,000,000	76,000,000	(6,000,000)	31,000,000	(9,000,000)	23,000,000	16,000,000	(36,000,000)	26,000,000	(20,000,000)	102,000,000	3,000,000	127,000,000	(6,000,000)
Increase (Decrease) in Deferred Income Taxes													14,000,000	(139,000,000)
Increase (Decrease) in Other Operating Assets and Liabilities, Net													(69,000,000)	192,000,000
Restatement Adjustment [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Accounts Payable, Related Parties, Current	26,000,000	6,000,000	5,000,000	6,000,000	5,000,000	1,000,000	1,000,000	0	5,000,000	1,000,000	6,000,000	1,000,000	26,000,000	5,000,000
Income Tax Expense (Benefit)	(6,000,000)	51,000,000	(25,000,000)	0	29,000,000	0	9,000,000	(2,000,000)	(25,000,000)	7,000,000	26,000,000	7,000,000	20,000,000	36,000,000
Liabilities, Current	26,000,000	6,000,000	5,000,000	6,000,000	5,000,000	1,000,000	1,000,000	0	5,000,000	1,000,000	6,000,000	1,000,000	26,000,000	5,000,000
Deferred Tax Liabilities, Net, Noncurrent	30,000,000	57,000,000	6,000,000	31,000,000	31,000,000	6,000,000	6,000,000	(2,000,000)	6,000,000	6,000,000	57,000,000	6,000,000	30,000,000	31,000,000
General Partners' Capital Account	(56,000,000)	(62,000,000)	(11,000,000)	(37,000,000)	(36,000,000)	(7,000,000)	(7,000,000)	2,000,000	(11,000,000)	(7,000,000)	(62,000,000)	(7,000,000)	(56,000,000)	(36,000,000)
Partners' Capital	(56,000,000)	(62,000,000)	(11,000,000)	(37,000,000)	(36,000,000)	(7,000,000)	(7,000,000)	2,000,000	(11,000,000)	(7,000,000)	(62,000,000)	(7,000,000)	(56,000,000)	(36,000,000)
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest	6,000,000	(51,000,000)	25,000,000	0	(29,000,000)	0	(9,000,000)	2,000,000	25,000,000	(7,000,000)	(26,000,000)	(7,000,000)	(20,000,000)	(36,000,000)
Net Income (Loss) Attributable to Parent	6,000,000	(51,000,000)	25,000,000	0	(29,000,000)	0	(9,000,000)	2,000,000	25,000,000	(7,000,000)	(26,000,000)	(7,000,000)	(20,000,000)	(36,000,000)
Net Income (Loss) Allocated to Limited Partners	6,000,000	(51,000,000)	25,000,000	0	(29,000,000)	0	(9,000,000)	2,000,000	25,000,000	(7,000,000)	(26,000,000)	(7,000,000)	(20,000,000)	(36,000,000)
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ 6,000,000	$ (51,000,000)	$ 25,000,000	$ 0	$ (29,000,000)	$ 0	$ (9,000,000)	$ 2,000,000	$ 25,000,000	$ (7,000,000)	$ (26,000,000)	$ (7,000,000)	(20,000,000)	(36,000,000)
Increase (Decrease) in Deferred Income Taxes													17,000,000	31,000,000
Increase (Decrease) in Other Operating Assets and Liabilities, Net													3,000,000	5,000,000
Restatement Adjustment [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Income Tax Expense (Benefit)													$ 20,000,000	$ 36,000,000

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Mergers and Other Transactions (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended			12 Months Ended
	Feb. 28, 2014	Dec. 31, 2013	Apr. 30, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Jan. 31, 2015	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Feb. 19, 2014	Jun. 24, 2013
Disposal Group, Including Discontinued Operation, Revenue						$ 415
Proceeds from sale of MGE assets, net of transaction costs				$ 0	$ 0	1,008
Goodwill		$ 1,336		$ 923	$ 1,152	1,336	$ 923	$ 1,152	$ 1,152		$ 1,152	$ 1,152	$ 1,152
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax						65
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						31,400,000
ETP [Member]
Notes Receivable, Related Parties							$ 1,370
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.							15,500,000
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						6,300,000
Lake Charles LNG Transaction [Member]
Partners' Capital Account, Units, Redeemed	18,700,000
Goodwill														184
Intangible Assets, Net (Excluding Goodwill)														$ 50
SUGS Contribution [Member]
Business Combination, Consideration Transferred			$ 463
Cash Acquired from Acquisition			$ 30
New England Gas Company [Member]
Proceeds from sale of MGE assets, net of transaction costs		40
Noncash or Part Noncash Divestiture, Amount of Consideration Received		$ 20
Missouri Gas Energy
Proceeds from sale of MGE assets, net of transaction costs						$ 975
Regency Merger [Member]
Business Acquisition, Number Of Share Received In Exchange Of Each Share										0.4066
Business Acquisition, Share Price										$ 0.32

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Related Party Balances (Details) - USD ($) $ in Millions	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014
Related Party Transaction
Non-current notes receivable from related party — ETP	$ 574	$ 1,369	$ 40	$ 40	$ 0	$ 386	$ 386	$ 386
ADVANCES FROM AFFILIATES	$ 0	$ 566	$ 0	$ 0	$ 51	$ 0	$ 0	$ 0

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Related Party Transactions (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction
Interest income — affiliates	$ 16	$ 6	$ 1	$ 0	$ 6	$ 5	$ 7	$ 5	$ 23	$ 23	$ 9
Income (loss) from unconsolidated affiliates	$ 0	$ 28	$ (6)	$ 4	$ (19)	$ 9	$ 6	$ (8)	26	(12)	15
Southern Union
Related Party Transaction
Revenue from Related Parties									18	33	56
Interest income — affiliates									23	23	9
Affiliated Entity
Related Party Transaction
Cost of natural gas and other energy									0	0	17
Related Party Transaction, Expenses from Transactions with Related Party									16	16	0
Related Party Operating, Maintenance and General Expenses									31	33	71
Interest expense, net									0	0	(31)
Income (loss) from unconsolidated affiliates									$ 26	$ (12)	$ 15

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RELATED PARTY TRANSACTIONS Related Party Distributions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Distributions of earnings received from unconsolidated affiliates	$ 9	$ 6	$ 15
ETP [Member]
Distributions of earnings received from unconsolidated affiliates	39	9	8
Regency [Member]
Distributions of earnings received from unconsolidated affiliates	$ 16	$ 61	$ 44

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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	Dec. 31, 2013	Sep. 30, 2014
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Summarized Financial Information, Current Assets	$ 4,698	$ 6,029
Equity Method Investment Summarized Financial information, PPE	45,087	38,907
Equity Method Investment Summarized Financial information, Other Assets	15,388	17,582
Equity Method Investment, Summarized Financial Information, Assets	65,173	62,518
Equity Method Investment, Summarized Financial Information, Revenue	34,292	55,475	$ 48,335
Equity Method Investment, Summarized Financial Information, Income (Loss) from Continuing Operations before Extraordinary Items	2,259	2,443	1,619
Equity Method Investment, Summarized Financial Information, Net Income (Loss)	1,521	1,299	$ 746
Equity Method Investment, Summarized Financial Information, Current Liabilities	4,121	6,585
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities	34,021	30,622
Equity Method Investment Summarized Financial Information, Equity	27,031	25,311
equity method investment summarized financial information, total liabilities and equity	$ 65,173	$ 62,518
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		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		6.3

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INVESTMENTS IN UNCONSOLIDATED AFFILIATES Investment in unconsolidated affiliates detail (Details) - USD ($) shares in Millions, $ in Millions	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013
Schedule of Equity Method Investments [Line Items]
GOODWILL	$ 923	$ 923	$ 1,152	$ 1,152	$ 1,152	$ 1,152	$ 1,152	$ 1,152	$ 1,336
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.		15.5
Notes Receivable, Related Parties		$ 1,370
Investment In ETP [Member]
Schedule of Equity Method Investments [Line Items]
GOODWILL		229
Deferred Tax Liabilities, Deferred Expense		$ 825
SUG Holding Note Receivable [Member]
Schedule of Equity Method Investments [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.75%

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Comprehensive Income (Loss) - Tax amounts in other comprehensive income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Successor
Income taxes included in other comprehensive income:
Actuarial loss relating to postretirement benefits	$ 0	$ 1	$ (15)

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Comprehensive Income (Loss) - Components of AOCI (Details) - USD ($) $ in Millions	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014
Comprehensive Income Loss [Line Items]
Total accumulated other comprehensive income, net of tax	$ 2	$ 1	$ 1	$ 0	$ 0	$ 2	$ 2	$ 2

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Debt Obligations - Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Feb. 19, 2014
Debt Instrument
Junior Subordinated Notes	$ 54				$ 54
Other Long-term Debt	5				6
Unamortized Net Premiums And Fair Value Adjustments	76				99
Total debt outstanding	1,166				1,190
Less: Current maturities of long-term debt	(1)	$ (1)	$ (1)	$ (1)	(1)	$ (1)	$ (1)	$ (1)
Long-term Debt, Excluding Current Maturities	1,165				1,189
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
Debt Instrument, Interest Rate, Stated Percentage	7.60%
Senior Notes Due 2029 [Member]
Debt Instrument
Senior Notes	$ 66				66
Debt Instrument, Interest Rate, Stated Percentage	7.00%
8.25% Senior Notes, due November 14, 2029 [Member]
Debt Instrument
Senior Notes	$ 33				$ 33
Debt Instrument, Interest Rate, Stated Percentage	8.25%
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, 2015 USD ($)
Debt Instrument
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	$ 0
Long-term Debt, Maturities, Repayments of Principal in Year Two	300
Long-term Debt, Maturities, Repayments of Principal in Year Three	400
Long-term Debt, Maturities, Repayments of Principal in Year Four	150
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, 2015	Dec. 31, 2014	Feb. 19, 2014	Jun. 24, 2013
Debt Instrument
Debt Instrument, Unamortized Discount (Premium), Net	$ 12
Debt Instrument, Fair Value Disclosure	1,200	$ 1,240
Long term debt, amount outstanding	1,166	1,190
Junior Subordinated Notes	54	54
Unamortized Net Premiums And Fair Value Adjustments	76	$ 99
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				3.295%
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, 2015	Dec. 31, 2014	Dec. 31, 2013
Interest cost		$ 1	$ 1	$ 1
Fair value of plan assets at beginning of period		114
Fair value of plan assets at end of period		118	114
Other Postretirement Benefit Plan [Member]
Benefit obligation at beginning of period		24	25
Interest cost		1	1
Actuarial (gain) loss		(2)	1
Benefits paid, net		(2)	(2)
Change in Benefit Obligations, Dispositions		0	(1)
Benefit obligation at end of period		21	24	25
Fair value of plan assets at beginning of period		114	110
Return on plan assets and other		(1)	4
Employer contributions		7	7
Change in Plan Assets, Dispositions		0	(5)
Fair value of plan assets at end of period		118	114	$ 110
Amount overfunded at end of period (1)	[1]	(97)	(90)
Net actuarial loss		(10)	(16)
Prior service cost		14	15
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:		$ 4	$ (1)

[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, 2015	Dec. 31, 2014	Dec. 31, 2013
Postemployment Benefits [Abstract]
Interest cost	$ 1	$ 1	$ 1
Expected return on plan assets	(6)	(5)	(5)
Prior service credit amortization	1	1	1
Actuarial loss amortization	(1)	(1)	(1)
Net periodic benefit cost	$ (5)	$ (4)	$ (4)

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BENEFITS Benefits - Weighted-average Assumptions (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Postemployment Benefits [Abstract]
Discount rate	3.60%	4.29%	3.66%
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, 2015	Dec. 31, 2014
Postemployment Benefits [Abstract]
Health care cost trend rate	8.10%	7.60%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.71%	4.90%
Year that the rate reaches the ultimate trend rate	2021	2021

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BENEFITS Benefits - 1% Change in Assumed Health Care Cost Trend Rates Used (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
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, 2015	Dec. 31, 2014
Defined Benefit Plan, Fair Value of Plan Assets		$ 118	$ 114
Cash and Cash Equivalents
Defined Benefit Plan, Fair Value of Plan Assets		3	3
Mutual Fund
Defined Benefit Plan, Fair Value of Plan Assets	[1]	$ 115	$ 111

[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. As of December 31, 2014, the fund was primarily comprised of 38% equities, 52% fixed income securities, and 10% cash.

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BENEFITS Benefits - Estimate of Expected Benefit Payments (Details) $ in Millions	Dec. 31, 2015 USD ($)
Postemployment Benefits [Abstract]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	$ 2
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	2
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	1
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	1
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	1
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	$ 6

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BENEFITS Benefits - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	$ 8
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan Disclosure
Company Contributions Vested	100.00%
Company Contributions Years	five
Defined Contribution Plan, Cost Recognized	$ 1	$ 2	$ 3
Defined Contribution Plan, Employer Matching Contribution, Percent	3.00%
Savings Plan [Member]
Defined Benefit Plan Disclosure
Defined Contribution Plan, Cost Recognized	$ 2	$ 3	$ 6
Defined Contribution Plan Employers Matching Contribution Percentage to Participants Percentage Conribution	100.00%
Defined Contribution Plan, Employer Matching Contribution, Percent	5.00%
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure
Large Cap US Equitiies	36.00%	38.00%
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	3.84%	3.68%
Fixed Income Securities	54.00%	52.00%
Cash Fund Investments	10.00%	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] | Cash and Cash Equivalents
Defined Benefit Plan Disclosure
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	10.00%

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Taxes on Income - Current and Deferred (Details) - USD ($) $ in Millions	3 Months Ended								6 Months Ended		9 Months Ended		12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Jun. 30, 2015	Jun. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure
Federal													$ 21	$ 258	$ (52)
State													0	32	(7)
Current Income Tax Expense (Benefit)													21	290	(59)
Federal													17	(130)	119
State													14	22	38
Deferred income taxes													31	(108)	157
Total income tax expense	$ 17	$ 23	$ 0	$ 12	$ 47	$ 8	$ 23	$ 104	$ 12	$ 127	$ 35	$ 135	$ 52	$ 182	$ 98

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TAXES ON INCOME Income Taxes - Effective Rate Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended								6 Months Ended		9 Months Ended		12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Jun. 30, 2015	Jun. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule of Effective Income Tax Rate Reconciliation [Line Items]
Computed statutory income tax expense at 35%													$ 55	$ 50	$ (165)
Premium on debt retirement													0	(10)	0
State income taxes, net of federal income tax benefit													9	36	21
Non-deductible goodwill impairment													0	0	241
Other													(5)	1	1
Effective Income Tax Rate Reconciliation, Audit Settlements													(7)	0	0
Total income tax expense	$ 17	$ 23	$ 0	$ 12	$ 47	$ 8	$ 23	$ 104	$ 12	$ 127	$ 35	$ 135	52	182	98
Trunkline LNG Transaction [Member]
Schedule of Effective Income Tax Rate Reconciliation [Line Items]
Other													$ 0	$ 105	$ 0

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TAXES ON INCOME Taxes on Income - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014
Other postretirement benefits	$ 5				$ 5
Debt amortization	57				41
Other	32				27
Total deferred income tax assets	94				73
Deferred Tax Assets, Valuation Allowance	(2)				(2)
Deferred Tax Assets, Net	92				71
Property, plant and equipment	(796)				(794)
Deferred Tax Liabilities, Investment in Noncontrolled Affiliates	(20)				810
Other	(1)				6
Deferred Tax Liabilities, Gross	817				1,610
Deferred Tax Liabilities, Net	725				1,539
Deferred Tax Liabilities, Net, Noncurrent	$ 725	$ 779	$ 1,534	$ 1,542	$ 1,539	$ 1,458	$ 1,467	$ 1,467

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TAXES ON INCOME Taxes on Income - Narrative (Details) $ in Millions	Dec. 31, 2015 USD ($)
Income Tax Disclosure [Abstract]
Unrecognized Tax Benefits	$ 15
Unrecognized tax benfits for state filing positions, net of federal tax	10
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	9
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit	2
IRS Audit Settlement	$ 7

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TAXES ON INCOME Audit Settlement (Details) $ in Millions	Dec. 31, 2015 USD ($)
Income Tax Disclosure [Abstract]
IRS Audit Settlement	$ 7

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Derivative Instrument and Hedging Activities - Income Stmt (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
Gain Loss Recognized In Other Comprehensive Income Interest Rate Hedges	$ 0	$ 0	$ (3)
Gain Loss Recognized in Interest Expense	0	(7)	29
Gain Loss Recognized In Distribution Commodity Contracts	$ 0	$ 0	$ (7)

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PROPERTY, PLANT AND EQUIPMENT Property, Plant and Equipment - PPE Type (Details) - USD ($) $ in Millions	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	$ 3,338	$ 3,456	$ 3,428	$ 3,403	$ 3,395	$ 3,360	$ 3,331	$ 3,316
Accumulated depreciation	(286)	(342)	(319)	(292)	(269)	(243)	(215)	(192)
Net property, plant and equipment	3,052	$ 3,114	$ 3,109	$ 3,111	3,126	$ 3,117	$ 3,116	$ 3,124
Land and Land Improvements [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	8				8
Building and Building Improvements [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	340				340
Pipelines [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	2,387				2,353
Natural Gas Storage [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	329				323
Vehicles [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	24				23
Right Of Way [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	23				23
Furniture and Fixtures [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	34				33
Linepack [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	57				57
Property, Plant and Equipment, Other Types [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	99				192
Construction work in progress
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	$ 37				$ 43

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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) $ in Millions	Dec. 31, 2015 USD ($)
ARO Underlying Asset	$ 6
Other ARO Assets
ARO Underlying Asset	$ 18

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ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations - Schedule of Changes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Beginning balance	$ 58	$ 55	$ 46
Revisions	0	3	11
Settled	$ (3)	$ (3)	$ (1)
Asset Retirement Obligations, Significant Changes	0	0	-4
Accretion expense	$ 3	$ 3	$ 3
Ending balance	$ 58	$ 58	$ 55

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ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
ARO Underlying Asset	$ 6
Asset Retirement Obligation, Revision of Estimate	0	$ 3	$ 11
Asset Retirement Obligation, Liabilities Settled	$ 3	$ 3	$ 1
Asset Retirement Obligations, Significant Changes	0	0	-4
Other ARO Assets
ARO Underlying Asset	$ 18

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Commitments and Contingencies - Accrued Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Loss Contingencies [Line Items]
Current	$ 0	$ 1
Non-current	3	3
Total environmental liabilities	$ 3	$ 4

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Commitment and Contingenices (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Loss Contingencies [Line Items]
Refundable Gas Costs		$ 11,000,000
Contingent Residual Support Agreement, Amount	$ 2,000,000,000
Estimated litigation liability	22,000,000		$ 21,000,000
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								6 Months Ended		9 Months Ended		12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Jun. 30, 2015	Jun. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash and Cash Equivalents, at Carrying Value	$ 3	$ 30	$ 65	$ 47	$ 32	$ 55	$ 32	$ 74	$ 65	$ 32	$ 30	$ 55	$ 3	$ 32	$ 17	$ 49
Gas Domestic Regulated Revenue	135	121	123	149	138	125	122	170					528	555	576
Operating revenues	139	126	128	155	143	132	128	178					548	581	1,085
Operating income	43	26	31	53	38	31	34	90					153	193	(382)
Income Tax Expense (Benefit)	17	23	0	12	47	8	23	104	12	127	35	135	52	182	98
Net income (loss)	30	25	19	31	(36)	23	7	(33)	50	(26)	75	(3)	105	(39)	(535)
Net income (loss) attributable to partners	30	25	19	31	(36)	23	7	(39)	50	(32)	75	(9)	105	(45)	(499)
Other Revenue, Net	4	5	5	6	5	7	6	8					20	26	293
Cost of Goods Sold	0	1	1	2	0	1	2	0					4	3	228
Operating Costs and Expenses	57	56	50	53	58	55	49	47					216	209	248
General and Administrative Expense	7	12	11	12	13	12	11	10					42	46	113
Depreciation, Depletion and Amortization, Nonproduction	32	31	35	35	34	33	32	31					133	130	189
Costs and Expenses	96	100	97	102	105	101	94	88					395	388	1,467
Interest Expense	(12)	(13)	(12)	(13)	(20)	(15)	(19)	(12)					(50)	(66)	(111)
Income (Loss) from Equity Method Investments	0	28	(6)	4	(19)	9	6	(8)					26	(12)	15
Interest Income, Related Party	16	6	1	0	6	5	7	5					23	23	9
Other Nonoperating Income (Expense)	0	1	5	(1)	6	1	2	(4)					5	5	(3)
Nonoperating Income (Expense)	4	22	(12)	(10)	(27)	0	(4)	(19)					4	(50)	(90)
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	47	48	19	43	11	31	30	71					157	143	(472)
Net Income (Loss) Attributable to Noncontrolling Interest	0	0	0	0	0	0	0	6					0	6	(36)
Accounts Receivable, Net, Current	48	41	40	51	58	51	51	55	40	51	41	51	48	58
Due from Related Parties, Current	172	120	54	42	128	30	57	33	54	57	120	30	172	128
Gas Balancing Asset (Liability)	5	9	10	12	11	17	45	62	10	45	9	17	5	11
Inventory, Net	113	99	106	83	119	115	147	160	106	147	99	115	113	119
Other Assets, Current	9	15	13	13	10	48	20	15	13	20	15	48	9	10
Assets, Current	350	314	288	248	358	316	352	399	288	352	314	316	350	358
Property, Plant and Equipment, Gross	3,338	3,456	3,428	3,403	3,395	3,360	3,331	3,316	3,428	3,331	3,456	3,360	3,338	3,395
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	286	342	319	292	269	243	215	192	319	215	342	243	286	269
Property, Plant and Equipment, Net	3,052	3,114	3,109	3,111	3,126	3,117	3,116	3,124	3,109	3,116	3,114	3,117	3,052	3,126
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures	15	15	1,404	1,428	1,443	1,480	1,488	1,502	1,404	1,488	15	1,480	15	1,443
Other Assets, Noncurrent	122	127	116	110	109	106	105	95	116	105	127	106	122	109
Due from Related Parties, Noncurrent	258	0	40	40	0	0	0	0	40	0	0	0	258	0
NOTE RECEIVABLE FROM RELATED PARTY	574	1,369	40	40	0	386	386	386	40	386	1,369	386	574	0
Goodwill	923	923	1,152	1,152	1,152	1,152	1,152	1,152	1,152	1,152	923	1,152	923	1,152	1,336
Assets	5,294	5,862	6,149	6,129	6,188	6,557	6,599	6,658	6,149	6,599	5,862	6,557	5,294	6,188
Long-term Debt, Current Maturities	1	1	1	1	1	1	1	1	1	1	1	1	1	1
Accounts Payable and Accrued Liabilities, Current	3	4	4	2	6	4	5	2	4	5	4	4	3	6
Accounts Payable, Related Parties, Current	125	63	34	39	43	463	452	467	34	452	63	463	125	43
Gas Balancing Payable, Current	94	83	91	76	114	117	179	214	91	179	83	117	94	114
Interest Payable, Current	12	24	12	24	12	24	12	24	12	12	24	24	12	12
Customer Advances and Deposits, Current	9	9	11	8	10	13	21	16	11	21	9	13	9	10
Other Liabilities, Current	55	60	59	54	56	66	57	52	59	57	60	66	55	56
Liabilities, Current	299	244	212	204	242	688	727	776	212	727	244	688	299	242
Long-term Debt and Capital Lease Obligations	1,165	1,172	1,178	1,184	1,189	1,195	1,201	1,203	1,178	1,201	1,172	1,195	1,165	1,189
Deferred Tax Liabilities, Net, Noncurrent	725	779	1,534	1,542	1,539	1,458	1,467	1,467	1,534	1,467	779	1,458	725	1,539
Due to Affiliate	0	566	0	0	51	0	0	0	0	0	566	0	0	51
Other Liabilities, Noncurrent	222	289	284	279	278	296	294	282	284	294	289	296	222	278
Commitments and Contingencies
General Partners' Capital Account	2,881	2,812	2,940	2,920	2,889	2,918	2,908	2,928	2,940	2,908	2,812	2,918	2,881	2,889
Accumulated Other Comprehensive Income (Loss), Net of Tax	2	1	1	0	0	2	2	2	1	2	1	2	2	0
Partners' Capital	2,883	2,813	2,941	2,920	2,889	2,920	2,910	2,930	2,941	2,910	2,813	2,920	2,883	2,889	$ 3,068	$ 4,028
Liabilities and Equity	$ 5,294	$ 5,862	$ 6,149	$ 6,129	$ 6,188	$ 6,557	$ 6,599	$ 6,658	$ 6,149	$ 6,599	$ 5,862	$ 6,557	$ 5,294	$ 6,188