UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2012

or

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

Commission File No. 1-6407

SOUTHERN UNION COMPANY

(Exact name of registrant as specified in its charter)

Delaware	75-0571592
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

5051 Westheimer Road	77056-5622
Houston, Texas	(Zip Code)
(Address of principal executive offices)

Registrant’s telephone number, including area code:  (713) 989-2000

Securities Registered Pursuant to Section 12(b) of the Act:

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 Rule 12b-2 of the Exchange Act). Yes ¨    No x

Southern Union Company 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.

TABLE OF CONTENTS

PART I
		PAGE
ITEM 1.	BUSINESS	3
ITEM 1A.	RISK FACTORS	14
ITEM 1B.	UNRESOLVED STAFF COMMENTS	27
ITEM 2.	PROPERTIES	27
ITEM 3.	LEGAL PROCEEDINGS	28
ITEM 4.	MINE SAFETY DISCLOSURES	28
PART II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	28
ITEM 6.	SELECTED FINANCIAL DATA	28
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	28
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	38
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	40
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	40
ITEM 9A.	CONTROLS AND PROCEDURES	40
ITEM 9B.	OTHER INFORMATION	41
PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	41
ITEM 11.	EXECUTIVE COMPENSATION	41
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS	41
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	41
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	42
PART IV
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	42
Signatures		42

Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by Southern Union Company and its subsidiaries (“Southern Union” or the “Company”) in periodic press releases and some oral statements of the Company’s 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,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Company believes such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such assumptions, expectations, or projections will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Company’s actual results may vary materially from those anticipated, projected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Item 1A. Risk Factors” included in this annual report.

Definitions

The following is a list of certain acronyms and terms generally used in the energy industry and throughout this document:

/d	per day
AOCI	accumulated other comprehensive income (loss)
ARO	Asset retirement obligation
Bbls	barrels
Bcf	Billion cubic feet
Btu	British thermal units
Citrus	Citrus Corp.
CrossCountry Energy	CrossCountry Energy, LLC
DGCL	Delaware General Corporation Law
EBIT	Earnings before interest and taxes
EBITDA	Earnings before interest, taxes, depreciation and amortization
EITR	Effective income tax rate
EPA	United States Environmental Protection Agency
ETE	Energy Transfer Equity, L.P.
ETP	Energy Transfer Partners, L.P., a subsidiary of ETE
ETP Merger Sub	Citrus ETP Acquisition, L.L.C.
Exchange Act	Securities Exchange Act of 1934
FERC	Federal Energy Regulatory Commission
Florida Gas	Florida Gas Transmission Company, LLC
GAAP	Accounting principles generally accepted in the United States of America
Holdco	ETP Holdco Corporation
LIBOR	London Interbank Offer Rate
KDHE	Kansas Department of Health and Environment
Laclede Massachusetts	Plaza Massachusetts Acquisition, Inc.
Laclede Missouri	Plaza Missouri Acquisition, Inc.

1

LNG	Liquefied natural gas
LNG Holdings	Trunkline LNG Holdings, LLC
MADEP	Massachusetts Department of Environmental Protection
MDPU	Massachusetts Department of Public Utilities
MGPs	Manufactured gas plants
MMBtu	Million British thermal units
MMcf	Million cubic feet
MPSC	Missouri Public Service Commission
NGL	Natural gas liquids
NMED	New Mexico Environment Department
NYMEX	New York Mercantile Exchange
OPEB plans	Other postretirement employee benefit plans
Panhandle	Panhandle Eastern Pipe Line Company, LP and its subsidiaries
PCBs	Polychlorinated biphenyls
PEPL	Panhandle Eastern Pipe Line Company, LP
PEPL Holdings	PEPL Holdings, LLC
ppb	parts per billion
PRPs	Potentially responsible parties
RCRA	Resource Conservation and Recovery Act
Regency	Regency Energy Partners LP
SARs	Stock Appreciation Rights
Sea Robin	Sea Robin Pipeline Company, LLC
SEC	United States Securities and Exchange Commission
Sigma	Sigma Acquisition Corporation
Southern Union Credit Facility	the Company’s $700 million Eighth Amended and Restated Revolving Credit Agreement
Southwest Gas	Pan Gas Storage, LLC (d.b.a. Southwest Gas)
SUGS	Southern Union Gas Services
Sunoco	Sunoco, Inc.
TBtu	Trillion British thermal units
TCEQ	Texas Commission on Environmental Quality
Trunkline	Trunkline Gas Company, LLC
Trunkline LNG	Trunkline LNG Company, LLC

Adjusted EBITDA is a term used throughout this document, which we define as earnings before interest, taxes, depreciation, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, unrealized gains and losses on commodity risk management activities, non-cash impairment charges and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities includes unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Adjusted EBITDA includes amounts for less than wholly owned subsidiaries and unconsolidated affiliates based on the Company’s proportionate ownership.

2

PART I

ITEM 1.    BUSINESS.

OUR BUSINESS

Introduction

The Company was incorporated under the laws of the State of Delaware in 1932.  The Company owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the gathering, processing, transportation, storage and distribution of natural gas in the United States.  The Company operates in three reportable segments:  Transportation and Storage, Gathering and Processing, and Distribution.

On March 26, 2012, the Company, ETE, and Sigma Acquisition Corporation, a wholly-owned subsidiary of ETE (Merger Sub), completed their previously announced merger transaction.  Pursuant to the Second Amended and Restated Agreement and Plan of Merger, dated as of July 19, 2011, as amended by Amendment No. 1 thereto dated as of September 14, 2011 (as amended, the Merger Agreement), among the Company, ETE and Merger Sub, Merger Sub was merged with and into the Company, with the Company continuing as the surviving corporation as an indirect, wholly-owned subsidiary of ETE (the Merger).  The Merger became effective on March 26, 2012 at 12:59 p.m., Eastern Time (the Effective Time).

In connection with, and immediately prior to the Effective Time of the Merger, CrossCountry Energy, an indirect wholly-owned subsidiary of the Company, ETP, ETP Merger Sub, Citrus ETP Finance LLC, ETE, PEPL Holdings, LLC, a newly created indirect wholly-owned subsidiary of the Company, and the Company consummated the transactions contemplated by that certain Amended and Restated Agreement and Plan of Merger, dated as of July 19, 2011, as amended by Amendment No. 1 thereto dated as of September 14, 2011 and Amendment No. 2 thereto dated as of March 23, 2012 (as amended, the Citrus Merger Agreement) by and among ETP, ETP Merger Sub and Citrus ETP Finance LLC, on the one hand, and ETE, CrossCountry Energy, PEPL Holdings and the Company, on the other hand.

Immediately prior to the Effective Time, the Company, CrossCountry Energy and PEPL Holdings became parties to the Citrus Merger Agreement by joinder and the Company assumed the obligations and rights of ETE thereunder.  The Company made certain customary representations, warranties, covenants and indemnities in the Citrus Merger Agreement.  Pursuant to the Citrus Merger Agreement, ETP Merger Sub was merged with and into CrossCountry Energy (the Citrus Merger), with CrossCountry Energy continuing as the surviving entity in the Citrus Merger as a wholly-owned subsidiary of ETP and, as a result thereof, ETP, through its subsidiaries, indirectly owns 50% of the outstanding capital stock of Citrus Corp. (Citrus).  As consideration for the Citrus Merger, the Company received from ETP $2.0 billion, consisting of approximately $1.9 billion in cash and $105 million of common units representing limited partner interests in ETP.

Immediately prior to the Effective Time, $1.45 billion of the total cash consideration received in respect of the Citrus Merger was contributed to Merger Sub in exchange for an equity interest in Merger Sub.  In connection with the Merger, at the Effective Time, such equity interest in Merger Sub held by CCE Holdings, LLC (CCE Holdings) was cancelled and retired.

Pursuant to the Citrus Merger Agreement, immediately prior to the Effective Time, (i) the Company contributed its ownership interests in Panhandle Eastern Pipe Line Company, LP and Southern Union Panhandle, LLC (collectively, the Panhandle Interests) to PEPL Holdings (the Panhandle Contribution); and (ii) following the Panhandle Contribution, the Company entered into a contingent residual support agreement (the Support Agreement) with ETP and Citrus ETP Finance LLC, pursuant to which the Company agreed to provide contingent, residual support to Citrus ETP Finance LLC (on a non-recourse basis to Southern Union) 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.

On October 5, 2012, ETE and ETP completed the Holdco Transaction, immediately following the closing of ETP’s acquisition of Sunoco whereby, (i) ETE contributed its interest in Southern Union into an ETP-controlled entity, in exchange for a 60% equity interest in the new entity, Holdco, and (ii) ETP contributed its interest in Sunoco to Holdco and retained a 40% equity interest in Holdco. Pursuant to a stockholders agreement between ETE and ETP, ETP will control Holdco. This transaction did not result in a new basis of accounting for Southern Union.

See Note 3 to our consolidated financial statements for information related to Southern Union’s merger with ETE.

3

BUSINESS SEGMENTS

Reportable Segments

The Company’s operations, as reported, include three reportable segments:

• The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas and also provides LNG terminalling and regasification services.  Its operations are conducted through Panhandle.

• The Gathering and Processing segment is primarily engaged in the gathering, treating, processing and redelivery of natural gas and NGL in Texas and New Mexico.  Its operations are conducted through SUGS. On February 27, 2013, the Company entered into a definitive contribution agreement to contribute to Regency all of the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS. The consideration to be paid by Regency in connection with this transaction will consist of (i) the issuance of 31,372,419 Regency common units to the Company, (ii) the issuance of 6,274,483 Regency Class F units to the Company, (iii) the distribution of $570 million in cash to the Company, and (iv) the payment of $30 million in cash to a subsidiary of ETP. The transaction is expected to close in the second quarter of 2013. The Regency Class F units will have the same rights, terms and conditions as the Regency common units, except that Southern Union will not receive distributions on the Regency Class F units for the first eight consecutive quarters following the closing, and the Regency Class F units will thereafter automatically convert into Regency common units on a one-for-one basis.

• The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts.  Its operations are conducted through the Company’s operating divisions:  Missouri Gas Energy and New England Gas Company.  On December 17, 2012, Southern Union and The Laclede Group, Inc. entered into definitive purchase and sale agreements dated December 14, 2012 with Laclede Missouri and Laclede Massachusetts, both of which are subsidiaries of Laclede Gas Company, Inc. pursuant to which Laclede Missouri has agreed to acquire the assets of Southern Union’s Missouri Gas Energy division, and Laclede Massachusetts has agreed to acquire the assets of Southern Union’s New England Gas Company division for approximately $1.035 billion, subject to customary closing adjustments.  On February 11, 2013, The Laclede Group, Inc. announced that it had entered into an agreement with Algonquin Power & Utilities Corp (APUC) that will allow a subsidiary of APUC to assume the rights of The Laclede Group, Inc. to purchase the assets of New England Gas Company, subject to certain approvals. It is expected that the transactions contemplated by the purchase and sale agreements will close by the end of the third quarter of 2013.

The Company has other operations that support and expand its natural gas and other energy sales, which are not included in its reportable segments.  These operations do not meet the quantitative thresholds for determining reportable segments and have been combined for disclosure purposes in the Corporate and Other activities category.

For information about the results, assets and other financial information relating to reportable segments and the Corporate and Other activities, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Business Segment Results” and Note 18 to our consolidated financial statements.

Sales of products or services between segments are billed at regulated rates or at market rates, as applicable.  There were no material intersegment revenues.

Transportation and Storage Segment

Services

The Transportation and Storage segment is primarily engaged in the interstate transportation of natural gas to Midwest, Gulf Coast and Midcontinent United States markets and related storage, and also provides LNG terminalling and regasification services.

Panhandle.  Panhandle owns and operates a large natural gas open-access interstate pipeline network.  The pipeline network, consisting of the PEPL, Trunkline and Sea Robin transmission systems, serves customers in the Midwest, Gulf Coast and Midcontinent United States with a comprehensive array of transportation and storage services.  PEPL’s transmission system consists of four large diameter pipelines extending approximately 1,300 miles from producing areas in the Anadarko Basin of Texas, Oklahoma and Kansas through Missouri, Illinois, Indiana, Ohio and into Michigan.  Trunkline’s transmission system consists of two large diameter pipelines extending approximately 1,400 miles from the Gulf Coast areas of Texas and Louisiana through Arkansas, Mississippi, Tennessee, Kentucky, Illinois, Indiana and to Michigan.  Sea Robin’s transmission system consists of two offshore Louisiana natural gas supply systems extending approximately 81 miles into the Gulf of Mexico. In connection with its natural gas pipeline transmission and storage systems, Panhandle has five natural gas storage fields located in Illinois, Kansas,

4

Louisiana, Michigan and Oklahoma.  Southwest Gas operates four of these fields and Trunkline operates one.  Through Trunkline LNG, Panhandle owns and operates an LNG terminal in Lake Charles, Louisiana.

We are currently developing plans to convert certain existing pipeline assets from natural gas transportation to crude oil transportation.  These plans include the proposed abandonment of certain pipeline segments of Trunkline, which are currently operating in natural gas service, and the conversion of some or all of those segments of pipeline to crude oil transportation service.  Trunkline's application to abandon those segments of pipeline from natural gas service, filed July 26, 2012, is currently pending before the FERC.  As of February 13, 2013, ETP and Enbridge (U.S.), Inc. entered into an agreement under which they will jointly market a project to transport up to 420,000 Bbls/d of crude oil from Patoka, Illinois, to refinery markets in and around Memphis, Tennessee, Baton Rouge, Louisiana, and St. James, Louisiana, utilizing a combination of newly constructed pipeline and approximately 574 miles of pipeline to be abandoned by Trunkline.  Subject to receipt of sufficient customer commitments for long-term transportation capacity and regulatory approvals, this project is expected to be in service by 2015.

We are currently studying the commercial and engineering feasibility of constructing a liquefaction facility at Trunkline LNG's existing Lake Charles LNG regasification terminal. The project is anticipated to utilize a portion of the existing LNG regasification infrastructure, including storage tanks and marine facilities, and is expected to have the capacity to export up to 15 million tons per annum of LNG.  We expect to complete certain studies, permits and approvals through 2014, and we do not anticipate making any significant capital expenditures related to this project prior to the completion of those items.

Panhandle earns most of its revenue by entering into firm transportation and storage contracts, providing capacity for customers to transport and store natural gas or LNG in its facilities.  Panhandle provides firm transportation services under contractual arrangements to local distribution company customers and their affiliates, natural gas marketers, producers, other pipelines, electric power generators and a variety of end-users.  Panhandle’s pipelines offer both firm and interruptible transportation to customers on a short-term and long-term basis.  Demand for natural gas transmission on Panhandle’s pipeline systems peaks during the winter months, with the highest throughput and a higher portion of annual total operating revenues occurring during the first and fourth calendar quarters.  Average reservation revenue rates realized by Panhandle are dependent on certain factors, including but not limited to rate regulation, customer demand for capacity, and capacity sold for a given period and, in some cases, utilization of capacity.  Commodity or utilization revenues, which are more variable in nature, are dependent upon a number of factors including weather, storage levels and pipeline capacity availability levels, and customer demand for firm and interruptible services, including parking services.  The majority of Panhandle’s revenues are related to firm capacity reservation charges, which reservation charges accounted for approximately 87% of total segment revenues and 41% of consolidated revenues in the successor period in 2012.

Prior to the completion of the Citrus Merger in the first quarter of 2012, the Transportation and Storage segment also included the Company’s equity ownership interest in Florida Gas through our 50% equity ownership in Citrus.  See discussion of the Citrus Merger at Note 3 to our consolidated financial statements.

Operating Data

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

	Successor	Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012	Period from January 1, 2012 to March 25, 2012	Years Ended December 31,
			2011	2010
Panhandle:
PEPL transportation	430	152	564	563
Trunkline transportation	533	177	743	664
Sea Robin transportation	91	20	113	172

5

The following table provides a summary of certain statistical information associated with Panhandle at the date indicated.

	December 31, 2012
Panhandle:
Approximate Miles of Pipelines
PEPL	6,000
Trunkline	3,000
Sea Robin	1,000
Peak Day Delivery Capacity (Bcf/d)
PEPL	2.8
Trunkline	1.7
Sea Robin	1.9
Trunkline LNG Sustained Send Out Capacity (Bcf/d)	2.1
Underground Storage Capacity-Owned (Bcf)	68.1
Underground Storage Capacity-Leased (Bcf)	33.3
Trunkline LNG Terminal Storage Capacity (Bcf)	9.0
Approximate Average Number of Transportation Customers	500
Weighted Average Remaining Life in Years of Firm Transportation Contracts (1)
PEPL	5.7
Trunkline	8.9
Sea Robin  (2)	N/A
Weighted Average Remaining Life in Years of Firm Storage Contracts (1)
PEPL	8.8
Trunkline	6.0

⁽¹⁾  Weighted by firm capacity volumes.

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

Regulation and Rates

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

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

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

Panhandle is also subject to the Natural Gas Pipeline Safety Act of 1968 and the Pipeline Safety Improvement Act of 2002, which regulate the safety of natural gas pipelines.

For additional information regarding Panhandle’s regulation and rates, see “Item 1A.  Risk Factors – Risks That Relate to the Company’s Transportation and Storage Segment” and Note 14 and Note 19 to our consolidated financial statements.

6

Competition

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

Natural gas competes with other forms of energy available to the Company’s customers and end-users, including electricity, coal and fuel oils.  The primary competitive factor is price.  Changes in the availability or price of natural gas and other forms of energy, the level of business activity, conservation, legislation and governmental regulation, the capability to convert to alternate fuels and other factors, including weather and natural gas storage levels, affect the ongoing demand for natural gas in the areas served by Panhandle.  In order to meet these challenges, Panhandle will need to adapt their marketing strategies, the types of transportation and storage services provided and their pricing and rates to address competitive forces.  In addition, FERC may authorize the construction of new interstate pipelines that compete with the Company’s existing pipelines.

Gathering and Processing Segment

Services

SUGS’ operations consist of a network of natural gas and NGL pipelines, six processing plants and seven natural gas treating plants.  The principal assets of SUGS are located in the Permian Basin of Texas and New Mexico.

SUGS is primarily engaged in connecting producing wells of exploration and production companies to its gathering system, providing compression and gathering services, treating natural gas to remove impurities to meet pipeline quality specifications, processing natural gas for the removal of NGL, and redelivering natural gas and NGL to a variety of markets.  SUGS’ natural gas supply contracts primarily include fee-based, percent-of-proceeds, and margin sharing contracts (conditioning fee and wellhead purchase contracts).  SUGS’ primary sales customers include exploration and production companies, power generating companies, electric and natural gas utilities, energy marketers, industrial end-users located primarily in the Gulf Coast and southwestern United States, and petrochemical companies.  With respect to customer demand for the products and services it provides, SUGS’ business is not generally seasonal in nature; however, SUGS’ operations and the operations of its exploration and production producers can be adversely impacted by severe weather.

As a result of the operational flexibility built into SUGS’ gathering systems and plants, it is able to offer a broad array of services to producers, including:

• field gathering and compression of natural gas for delivery to its plants;

• treating, dehydration, sulfur recovery and other conditioning; and

• natural gas processing and marketing of natural gas and NGL.

The majority of SUGS’ gross margin is derived from the sale of NGL and natural gas equity volumes and fee-based services.  The prices of NGL and natural gas are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of factors beyond the Company’s control.  The Company monitors these drivers and manages the associated commodity price risk using both economic and accounting hedge derivative instruments.  For additional information related to the Company’s commodity price risk management, see Note 11 to our consolidated financial statements and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk – Gathering and Processing Segment.”

Operating Data

The following table provides a summary of certain statistical information associated with SUGS at the date indicated.

	December 31, 2012
Approximate Miles of Pipelines	5,700
Plant capacity (MMcf/d):
Processing	510
Natural gas treating	630
Approximate Average Number of Customers	52

7

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Business Segment Results – Gathering and Processing Segment” for volume information related to SUGS.

Natural Gas and NGL Connections

SUGS’ major natural gas pipeline interconnects are with ATMOS Pipeline Texas, El Paso Natural Gas Company, Energy Transfer Fuel, Enterprise Texas Pipeline, Northern Natural Gas Company, Oasis Pipeline, ONEOK Westex Transmission, Public Service Company of New Mexico and Transwestern Pipeline Company.  Its major NGL pipeline interconnects are with Chaparral Energy, Lone Star Pipeline and Chevron Natural Gas.

Natural Gas Supply Contracts

SUGS’ natural gas supply contracts primarily include percent-of-proceeds, fee-based and margin sharing contracts (conditioning fee and wellhead purchase contracts) which, as of December 31, 2012, comprised 87%, 10% and 3% by volume of its natural gas supply contracts, respectively.  These natural gas supply contracts vary in length from month-to-month to a number of years, with many of the contracts having a term of three to five years.  Additionally, some contracts contain a combination of these contractual types of structure (e.g., percent-of-proceeds contractual structure combined with a treating fee component).  

Following is a summary description of the natural gas supply contracts utilized by SUGS:

• Percent-of-Proceeds, Percent-of-Value or Percent-of-Liquids.  Under percent-of-proceeds arrangements, SUGS generally gathers, treats and processes natural gas for producers for an agreed percentage of the proceeds from the sales of residual natural gas and NGL.  The percent-of-value and percent-of-liquids arrangements are variations on the percent-of-proceeds structure.  These types of arrangements expose SUGS to significant commodity price risk as the revenues derived from the contracts are directly related to natural gas and NGL prices.

• Fee-Based.  Under fee-based arrangements, SUGS receives a fee or fees for one or more of the following services:  gathering, compressing, dehydrating, treating or processing natural gas.  The fee or fees are usually based on the volume or level of service provided to gather, compress, dehydrate, treat or process natural gas.  While fee-based arrangements are generally not subject to commodity risk, certain operating conditions as well as certain provisions of these arrangements, including fuel and system loss recovery mechanisms, may subject SUGS to a limited amount of commodity risk.

• Conditioning Fee.  Conditioning fee arrangements provide a guaranteed minimum unit margin or fee on natural gas that must be processed for NGL extraction in order to meet the quality specifications of the natural gas transmission pipelines.  In addition to the minimum unit margin or fee, SUGS retains a significant percentage of the processing spread, if any.  While the revenue earned is directly related to the processing spread, SUGS is guaranteed a positive margin with a minimum unit margin or fee in low processing spread environments.

• Keep-Whole and Wellhead.  A keep-whole arrangement allows SUGS to keep 100% of the NGL produced, but requires the return of the Btu or dollar value of the underlying natural gas to the producer or owner.  Since some of the natural gas is converted to NGL during processing, resulting in Btu shrinkage, SUGS must compensate the producer or owner for the Btu shrinkage by replacing the shrinkage in-kind or by paying an agreed, market-based value for the Btu shrinkage.  These arrangements have the highest commodity price exposure for SUGS because the costs are dependent on the price of natural gas and the revenues are based on the price of NGL.  As a result, SUGS benefits from these types of arrangements when the Btu value of the NGL is high relative to the Btu value of the natural gas and is disadvantaged when the Btu value of the natural gas is high relative to the Btu value of NGL.  Rather than incurring negative margins during an unfavorable processing spread environment, SUGS may have the ability to reduce its exposure to negative processing spreads by (i) treating, dehydrating and blending the wellhead natural gas with leaner natural gas in order to meet downstream transmission pipeline specifications rather than processing the natural gas or (ii) reducing the volume of ethane recovered at the processing facility.

Natural Gas Sales Contracts

SUGS’ natural gas sales contracts (physical) are consummated under North American Energy Standards Board or Gas Industry Standards Board contracts.  Pricing is predominately based on Platt’s Gas Daily at El Paso-Permian or Waha pricing points.  Some monthly baseload sales are made using FERC (Platt’s) pricing at El Paso-Permian or Waha pricing points.

8

NGL Sales Contracts

SUGS has contracted to sell its entire owned or controlled output of NGL to Conoco through December 31, 2014.  Pricing for the NGL volumes sold to Conoco throughout the contract period are based on OPIS pricing at Mont Belvieu, Texas delivery points.  SUGS has an option to extend the sales agreement for an additional five-year period.

For information related to SUGS’ use of various derivative financial instruments to manage its commodity price risk and related operating cash flows, see Note 11 to our consolidated financial statements.

NGL Fractionation

SUGS has a multi-year, firm agreement with Enterprise Products Operations, LLC (Enterprise) for the fractionation of its NGL.  Enterprise owns several fractionation facilities in the Gulf coast area.

Regulation

While FERC does not directly regulate SUGS’ facilities for cost-based ratemaking purposes, SUGS is subject to certain oversight by FERC and various other governmental agencies, primarily with respect to matters of asset integrity, safety and environmental protection.  The relevant agencies include the EPA and its state counterparts, the Occupational Safety and Health Administration and the U.S. Department of Transportation’s Office of Pipeline Safety and its state counterparts.  The Company believes that its operations are in compliance, in all material respects, with applicable safety and environmental statutes and regulations.

Competition

SUGS competes with other midstream service providers and producer-owned midstream facilities in the Permian Basin. Industry factors that typically affect SUGS’ ability to compete are:

• contract fees charged;

• capacity and pressures maintained on gathering systems;

• location of its gathering systems relative to competitors and producer drilling activity;

• capacity and type of processing and treating available to SUGS and its competitors;

• efficiency and reliability of operations;

• availability and cost of third-party NGL transportation, fractionation capacity and residual natural gas markets;

• delivery capabilities in each system and plant location;

• natural gas and NGL pricing available to SUGS; and

• ability to secure rights-of-way and various facility sites.

Commodity prices for natural gas and NGL also play a major role in drilling activity on or near SUGS’ gathering and processing systems.  Generally, lower commodity prices will result in less producer drilling activity and, conversely, higher commodity prices will result in increased producer drilling activity.

SUGS has responded to these industry conditions by positioning and configuring its gathering and processing facilities to offer a broad array of services to accommodate the types and quality of natural gas produced in the region, while many competing systems provide only certain of these services.

9

Distribution Segment

Services

The Company’s Distribution segment is primarily engaged in the local distribution of natural gas in Missouri, through its Missouri Gas Energy division, and in Massachusetts, through its New England Gas Company division.  These utilities serve residential, commercial and industrial customers through local distribution systems.  The distribution operations in Missouri and Massachusetts are regulated by the MPSC and the MDPU, respectively. The assets and liabilities of the Distribution segment were reflected as held for sale as of December 31, 2012.

The Distribution segment’s operations have historically been sensitive to weather and seasonal in nature, with the primary impact on operating revenues, which include pass through gas purchase costs that are seasonally impacted,  occurring in the traditional winter heating season during the first and fourth calendar quarters. For additional information related to rates, see Note 19 to our consolidated financial statements.

Operating Data

The following table provides a summary of miles of pipelines associated with the Distribution segment at the date indicated.

	December 31, 2012
Approximate Miles of Pipelines
Mains	9,180
Service lines	5,990
Transmission lines	40

10

The following table sets forth the Distribution segment’s customers served, natural gas volumes sold or transported and weather-related information for the periods presented.

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Year Ended December 31, 2011
Average number of customers:
Residential	477,211			487,009			480,356
Commercial	60,734			65,141			62,659
Industrial	95			94			97
	538,040			552,244			543,112
Transportation	1,934			1,909			1,821
Total customers	539,974			554,153			544,933
Natural gas sales (MMcf):
Residential	15,286			14,085			38,897
Commercial	6,375			5,749			17,553
Industrial	104			122			393
Natural gas sales billed	21,765			19,956			56,843
Net change in unbilled natural gas sales	642			1			(1,720		)
Total natural gas sales	22,407			19,957			55,123
Natural gas transported	17,851			7,379			24,119
Total natural gas sales and gas transported	40,258			27,336			79,242
Natural gas sales revenues (in millions):
Residential	$	207		$	142		$	474
Commercial	69			54			177
Industrial	3			1			6
Natural gas revenues billed	279			197			657
Net change in unbilled natural gas sales revenues	4			—			(19		)
Total natural gas sales revenues	283			197			638
Natural gas transportation revenues	12			7			16
Other revenues	9			3			13
Total operating revenues	$	304		$	207		$	667
Weather:
Missouri Utility Operations:
Degree days (1)	2,040			1,898			5,183
Percent of 10-year measure (2)	82		%	70		%	100		%
Percent of 30-year measure (2)	52		%	146		%	100		%
Massachusetts Utility Operations:
Degree days (1)	2,542			2,170			5,162
Percent of 10-year measure (2)	42		%	35		%	85		%
Percent of 30-year measure (2)	42		%	36		%	84		%

⁽¹⁾  “Degree days” are a measure of the coldness of the weather experienced.  A degree day is equivalent to each degree that the daily mean temperature for a day falls below 65 degrees Fahrenheit.

11

⁽²⁾  Information with respect to weather conditions is provided by the National Oceanic and Atmospheric Administration.  Percentages of 10- and 30-year measures are computed based on the weighted average volumes of natural gas sales billed.  The 10- and 30-year measures are used for consistent external reporting purposes.  Measures of normal weather used by the Company’s regulatory authorities to set rates vary by jurisdiction.  Periods used to measure normal weather for regulatory purposes range from 10 years to 30 years.

Natural Gas Supply

The cost and reliability of natural gas service are largely dependent upon the Company’s ability to achieve favorable mixes of long-term and short-term natural gas supply agreements and fixed and variable transportation contracts.  The Company acquires its natural gas supplies directly.  The Company has enhanced the reliability of the service provided to its customers by obtaining the ability to dispatch and monitor natural gas volumes on a daily, hourly or real-time basis.

For the year ended December 31, 2012, the majority of the natural gas requirements for the utility operations of Missouri Gas Energy were delivered under short- and long-term transportation contracts through four major pipeline companies and approximately fifty-four commodity suppliers.  For this same period, the majority of the natural gas requirements of New England Gas Company were delivered under long-term contracts through five major pipeline companies and contracts with three commodity suppliers.  These contracts have various expiration dates ranging from 2013 through 2036.  Missouri Gas Energy and New England Gas Company also have firm natural gas supply commitments under short-term and seasonal arrangements available for all of its service territories.  Missouri Gas Energy and New England Gas Company hold contract rights to over 17 Bcf and 1 Bcf of storage capacity, respectively, to assist in meeting peak demands.

Like the natural gas industry as a whole, Missouri Gas Energy and New England Gas Company utilize natural gas sales and/or transportation contracts with interruption provisions, by which large volume users purchase natural gas with the understanding that they may be forced to shut down or switch to alternate sources of energy at times when the natural gas is needed by higher priority customers for load management.  In addition, during times of special supply problems, curtailments of deliveries to customers with firm contracts may be made in accordance with guidelines established by appropriate federal and state regulatory agencies.

Regulation and Rates

The Company’s utility operations are regulated as to rates, operations and other matters by the regulatory commissions of the states in which each operates.  In Missouri, natural gas rates are established by the MPSC on a system-wide basis.  In Massachusetts, natural gas rates for New England Gas Company are subject to the regulatory authority of the MDPU.  For additional information concerning recent state and federal regulatory developments, see Note 19 to our consolidated financial statements.

The Company holds non-exclusive franchises with varying expiration dates in all incorporated communities where it is necessary to carry on its business as it is now being conducted.  Fall River, Massachusetts; Kansas City, Missouri; and St. Joseph, Missouri are the largest cities in which the Company’s utility customers are located.  The franchise in Kansas City, Missouri expires in 2020.  The franchises in Fall River, Massachusetts and St. Joseph, Missouri are perpetual. Regulatory authorities establish natural gas service rates so as to permit utilities the opportunity to recover operating, administrative and financing costs, and the opportunity to earn a reasonable return on equity.  Natural gas costs are billed to customers through purchased natural gas adjustment clauses, which permit the Company to adjust its sales price as the cost of purchased natural gas changes.  This is important because the cost of natural gas accounts for a significant portion of the Company’s total expenses.  The appropriate regulatory authority must receive notice of such adjustments prior to billing implementation.  The MPSC allows Missouri Gas Energy to make rate adjustments for purchased natural gas cost changes up to four times per year.  The MDPU requires New England Gas Company to file for purchased natural gas cost rate adjustments at any time its projected revenues and purchased natural gas costs vary by more than 5%.

The Company supports any service rate changes that it proposes to its regulators using an historic test year of operating results adjusted to normal conditions and for any known and measurable revenue or expense changes.  Because the regulatory process has certain inherent time delays, rate orders in these jurisdictions may not reflect the operating costs at the time new rates are put into effect.

Except for Missouri Gas Energy’s residential customers and small general service customers, who are billed a fixed monthly charge for services provided and a charge for the amount of natural gas used, the Company’s monthly customer bills contain a fixed service charge, a usage charge for service to deliver natural gas, and a charge for the amount of natural gas used.  Although the monthly fixed charge provides an even revenue stream, the usage charge increases the Company’s revenue and earnings in the traditional heating load months when usage of natural gas increases.

12

In addition to public service commission regulation, the Distribution segment is affected by certain other regulations, including pipeline safety regulations under the Natural Gas Pipeline Safety Act of 1968, the Pipeline Safety Improvement Act of 2002, safety regulations under the Occupational Safety and Health Act and various state and federal environmental statutes and regulations.  The Company believes that its utility operations are in compliance, in all material respects, with applicable safety and environmental statutes and regulations.

Competition

As energy providers, Missouri Gas Energy and New England Gas Company have historically competed with alternative energy sources available to end-users in their service areas, particularly electricity, propane, fuel oil, coal, NGL and other refined products.  At present rates, the cost of electricity to residential and commercial customers in the Company’s regulated utility service areas generally is higher than the effective cost of natural gas service.  There can be no assurance, however, that future fluctuations in natural gas and electric costs will not reduce the cost advantage of natural gas service.

Competition from the use of fuel oils and propane, particularly by industrial and electric generation customers, has increased due to the volatility of natural gas prices and increased marketing efforts from various energy companies.  Competition from the use of fuel oils and propane is generally greater in the Company’s Massachusetts service area than in its Missouri service area. Nevertheless, this competition affects the nationwide market for natural gas.  Additionally, the general economic conditions in the Company’s regulated utility service areas continue to affect certain customers and market areas, thus impacting the results of the Company’s operations.  The Company’s regulated utility operations are not currently in significant direct competition with any other distributors of natural gas to residential and small commercial customers within their service areas.

OTHER MATTERS

Environmental

The Company is subject to federal, state and local laws and regulations relating to the protection of the environment.  These laws and regulations require the Company to conduct its operations in a specified manner and to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals.  Failure to comply with environmental requirements may expose the Company to significant fines, penalties and/or interruptions in operations.  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.  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 “Item 1A. Risk Factors” and Note 14 to our consolidated financial statements.

Insurance

The Company maintains insurance coverage provided under its policies similar to other comparable companies in the same lines of business.  This includes, but is not limited to, insurance for potential liability to third parties, worker’s compensation, automobile and property insurance.  The insurance policies are subject to terms, conditions, limitations and exclusions that do not fully compensate the Company for all losses.  Except for windstorm property insurance more fully described below, insurance deductibles range from $100,000 to $10 million for the various policies utilized by the Company.  As the Company renews its policies, it is possible that some of the current insurance coverage may not be renewed or obtainable on commercially reasonable terms due to restrictive insurance markets.

Oil Insurance Limited (OIL), the Company’s member mutual property insurer, revised its windstorm insurance coverage effective January 1, 2010.  Based on the revised coverage,  the per occurrence windstorm claims for onshore and offshore assets are limited to $250 million per member subject to a fixed 60% payout, up to $150 million per member, and are subject to the $750 million aggregate limit for total payout to members per incident and a $10 million deductible.  The revised windstorm coverage also limits annual individual member recovery to $300 million in the aggregate.  The Company has also purchased additional excess insurance coverage for its onshore assets arising from windstorm damage, which provides up to an additional $100 million of property insurance coverage over and above existing coverage or in excess of the base OIL coverage.  In the event windstorm damage claims are made by the Company for its onshore assets and such damage claims are subject to a scaled or aggregate limit reduction by OIL, the Company may have additional uninsured exposure prior to application of the excess insurance coverage. 

13

Employees

As of January 31, 2013, the Company employed 2,256 persons, of which 791 are represented by labor unions. None of the current contracts with the respective bargaining units expire within the next year. The Company believes that its relations with its employees are good.  From time to time, however, the Company may be subject to labor disputes.  The Company did not experience any strikes or work stoppages during the years ended December 31, 2012 and December 31, 2011.

SEC Reporting

We file or furnish annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any related amendments and supplements thereto with the SEC. You may read and copy any materials we file or furnish with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information regarding the Public Reference Room by calling the SEC at 1-800-732-0330. In addition, the SEC maintains an internet website at http://www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

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

ITEM 1A.  RISK FACTORS

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

Risks That Relate to Southern Union

Southern Union 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 Southern Union from meeting its future capital needs.

Southern Union has a significant amount of debt outstanding.  As of December 31, 2012, consolidated debt on the consolidated balance sheet totaled $3.28 billion outstanding, compared to total capitalization (long- and short-term debt plus stockholders’ equity) of $7.31 billion.

Covenants exist in certain of the Company’s debt agreements that require the Company to maintain a certain level of net worth, to meet certain debt to total capitalization ratios 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.  A 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.

Further, in order for the Company to receive equity contributions or loans from its parent or incur long-term debt, certain state regulatory approvals are required. This may limit the Company’s overall access to sources of capital otherwise available.

14

Restrictions on the Company’s ability to access capital markets could affect its ability to execute its business plan or limit its ability to pursue improvements or acquisitions on which it may otherwise rely for future growth.

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;

• The costs of maintaining certain contractual relationships could increase, primarily related to the potential requirement for the Company to post collateral associated with its derivative financial instruments; and

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

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 Southern Union.

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 Unitholders' 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 for investors.

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

15

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

• its success in valuing and bidding for the opportunities;

• its ability to assess the risks of the opportunities;

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

• its access to financing on acceptable terms.

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

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

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

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

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

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

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

The Company is subject to operating risks.

The Company’s operations are subject to all operating hazards and risks incident to handling, storing, transporting and providing customers with natural gas or NGL, 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, such as the attacks that occurred on September 11, 2001, have resulted in increased costs, and the consequences of terrorism may adversely impact the Company’s 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, LNG facilities, 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.

The success of the pipeline and gathering and processing businesses 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 Panhandle.  Additionally, third parties produce all of the natural gas gathered and processed by SUGS, and third parties provide all of the NGL transportation and fractionation services for SUGS.  As a result, the volume of natural gas or NGL transported, stored, gathered, processed or fractionated 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, storage, gathering or processing 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.

16

The success of the pipeline and gathering and processing businesses depends on the continued development of additional natural gas reserves in the vicinity of their facilities and their ability to access additional reserves to offset the natural decline from existing sources connected to their systems.

The amount of revenue generated by Panhandle ultimately depends upon their access to reserves of available natural gas. Additionally, the amount of revenue generated by SUGS depends substantially upon the volume of natural gas gathered and processed and NGL extracted.  As the reserves available through the supply basins connected to these systems naturally decline, a decrease in development or production activity could cause a decrease in the volume of natural gas available for transmission, gathering or processing. 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 AROs.  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 AROs 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 and gathering and processing businesses’ revenues are generated under contracts that must be renegotiated periodically.

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

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

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

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

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

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

• adverse weather conditions;

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

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

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

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

• the lack of transportation, storage or throughput commitments or gathering and processing 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.

17

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 Panhandle or SUGS 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 for Panhandle, which 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.

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 operation, 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, 2012, our consolidated balance sheet reflected $2.36 billion 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 use of derivative financial instruments could result in material financial losses by us.

From time to time, we have sought to reduce our exposure to fluctuations in commodity prices and interest rates by using derivative financial instruments and other risk management mechanisms and by our trading, marketing and/or system optimization activities. To the extent that we hedge our commodity price and interest rate exposures, we forgo the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor.

18

The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions that are effective economically (whether to mitigate our exposure to fluctuations in commodity prices, or to balance our exposure to fixed and variable interest rates), these transactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at that point. It is also not always possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices. Our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.

In addition, even though monitored by management, our derivatives activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the derivative arrangement, the hedge is imperfect, commodity prices move unfavorably related to our physical or financial positions or hedging policies and procedures are not followed.

The adoption of the Dodd-Frank Act could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business, resulting in our operations becoming more volatile and our cash flows less predictable.

Congress has adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act), a comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The legislation was signed into law by President Obama on July 21, 2010 and requires the U.S. Commodity Futures Trading Commission (CFTC), the SEC and other regulators to promulgate rules andregulations implementing the new legislation. While certain regulations have been promulgated and are already in effect, the rulemaking and implementation process is still ongoing, and we cannot yet predict the ultimate effect of the rules and regulations on our business.

The Dodd-Frank Act expanded the types of entities that are required to register with the CFTC and the SEC as a result of their activities in the derivatives markets or otherwise become specifically qualified to enter into derivatives contracts. We will be required to assess our activities in the derivatives markets, and to monitor such activities on an ongoing basis, to ascertain and to identify any potential change in our regulatory status.

Reporting and recordkeeping requirements also could significantly increase operating costs and expose us to penalties for non-compliance. Certain CFTC recordkeeping requirements became effective on October 14, 2010, and additional recordkeeping requirements will be phased in through April 2013. Beginning on December 31, 2012, certain CFTC reporting rules became effective, and additional reporting requirements will be phased in through April 2013. These additional recordkeeping and reporting requirements may require additional compliance resources. Added public transparency as a result of the reporting rules may also have a negative effect on market liquidity which could also negatively impact commodity prices and our ability to hedge.

The CFTC has also issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The CFTC's position limits rules were to become effective on October 12, 2012, but a United States District Court vacated and remanded the position limits rules to the CFTC. The CFTC has appealed that ruling and it is uncertain at this time whether, when, and to what extent the CFTC's position limits rules will become effective.

The new regulations may also require us to comply with certain margin requirements for our over-the-counter derivative contracts with certain CFTC- or SEC-registered entities that could require us to enter into credit support documentation and/or post significant amounts of cash collateral, which could adversely affect our liquidity and ability to use derivatives to hedge our commercial price risk; however, the proposed margin rules are not yet final and therefore the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.

The new legislation also requires that certain derivative instruments be centrally cleared and executed through an exchange or other approved trading platform. Mandatory exchange trading and clearing requirements could result in increased costs in the form of additional margin requirements imposed by clearing organizations. On December 13, 2012, the CFTC published final rules regarding mandatory clearing of certain interest rate swaps and certain index credit default swaps and setting compliance dates for different categories of market participants, the earliest of which is March 11, 2013. The CFTC has not yet proposed any rules requiring the clearing of any other classes of swaps, including physical commodity swaps. Although there may be an exception to the mandatory exchange trading and clearing requirement that applies to our trading activities, we must obtain approval from the board of directors of our General Partner and make certain filings in order to rely on this exception. In addition,

19

mandatory clearing requirements applicable to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging.

Rules promulgated under the Dodd-Frank Act further defined forwards as well as instances where forwards may become swaps. Because the CFTC rules, interpretations, no-action letters, and case law are still developing, it is possible that some arrangements that previously qualified as forwards or energy service contracts may fall in the regulatory category of swaps or options. In addition, the CFTC's rules applicable to trade options may further impose burdens on our ability to conduct our traditional hedging operations and could become subject to CFTC investigations in the future.

The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through restrictions on the types of collateral we are required to post), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable. Finally, if we fail to comply with applicable laws, rules or regulations, we may be subject to fines, cease-and-desist orders, civil and criminal penalties or other sanctions.

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

As of December 31, 2012, approximately 791 of the Company’s 2,256 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 Company is subject to risks associated with climate change.

It has been advanced that emissions of “greenhouse gases” (GHGs) are linked to climate change. Climate change and the costs that may be associated with its impact and the regulation of GHGs have the potential to affect the Company’s business in many ways, including negatively impacting (i) the costs it incurs in providing its products and services, including costs to operate and maintain its facilities, install new emission controls on its facilities, acquire allowances to authorize its GHG emissions, pay any taxes related to GHG emissions, administer and manage a GHG emissions program, pay higher insurance premiums or accept greater risk of loss in areas affected by adverse weather and coastal regions in the event of rising sea levels, (ii) the demand for and consumption of its products and services (due to change in both costs and weather patterns), and (iii) the economic health of the regions in which it operates, all of which could have a material adverse effect on the Company’s business, financial condition, results of operations and cash flows.

Recently proposed rules regulating air emissions from natural gas operations could cause us to incur increased capital expenditures and operating costs, which may be significant.

On April 17, 2012, the EPA issued final rules that would establish new air emission controls for natural gas production and processing operations. Specifically, the EPA's proposed rule package includes New Source Performance Standards (NSPS) to address emissions of sulfur dioxide and volatile organic compounds (VOCs), and a separate set of emission standards to address hazardous air pollutants frequently associated with natural gas production and processing activities. The EPA's proposal would require the reduction of VOC emissions from natural gas production facilities by mandating the use of "green completions" for hydraulic fracturing by January 2015, which requires the operator to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. These rules will require us to modify certain of our operations, including the possible installation of new equipment. Compliance with such rules will be required within three years of their effective date, and it could result in significant costs, including increased capital expenditures and operating costs, which may adversely impact our business.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas that we transport, store or otherwise handle.

In December 2009, the EPA 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 begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. The

20

EPA has recently adopted rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and another which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. In November 2011, the EPA also adopted rules requiring companies with facilities that emit over 25,000 metric tons or more of carbon dioxide to report their greenhouse gas emissions to the EPA by September 30, 2012, a requirement with which we timely complied.

In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase may be reduced over time in an effort to achieve the overall greenhouse gas emission reduction goal.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, natural gas, NGLs, crude oil and refined products. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations.

Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. If such effects were to occur, our operations could be adversely affected in various ways, including damages to our facilities from powerful winds or rising waters, or increased costs for insurance. Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for our fuels is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our fuels could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.

The Company is subject to risks resulting from the moratorium in 2010 on and the resulting increased costs of offshore deepwater drilling.

The United States Department of Interior (DOI) implemented a six-month moratorium on offshore drilling in water deeper than 500 feet in response to the blowout and explosion on April 20, 2010 at the British Petroleum Plc deepwater well in the Gulf of Mexico.  The offshore drilling moratorium was implemented to permit the DOI to review the safety protocols and procedures used by offshore drilling companies, which review will enable the DOI to recommend enhanced safety and training needs for offshore drilling companies.  The moratorium was lifted in October 2010.  Additionally, the United States Bureau of Ocean Energy Management, Regulation and Enforcement (formerly the United States Mineral Management Service) has been fundamentally restructured by the DOI with the intent of providing enhanced oversight of onshore and offshore drilling operations for regulatory compliance enforcement, energy development and revenue collection.   Certain enhanced regulatory mandates have been enacted with additional regulatory mandates expected.  The new regulatory requirements will increase the cost of offshore drilling and production operations.  The increased regulations and cost of drilling operations could result in decreased drilling activity in the areas serviced by the Company.  Furthermore, the imposed moratorium did result in some offshore drilling companies relocating their offshore drilling operations for currently indeterminable periods of time to regions outside of the United States.   Business decisions to not drill in the areas serviced by the Company resulting from the increased regulations and costs could result in a reduction in the future development and production of natural gas reserves in the vicinity of the Company’s facilities, which could adversely affect the Company’s business, financial condition, results of operations and cash flows.

The costs of providing pension and other postretirement health care benefits and related funding requirements are subject to changes in pension fund values, changing demographics 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 pension plan and other postretirement healthcare benefits to certain of its employees.  The costs of providing pension and other postretirement health care benefits and related funding requirements are subject to changes in pension and other postretirement fund values, changing demographics 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

21

increase the cost of health care benefits for its employees.  While certain of the costs incurred in providing such pension and other 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 is subject to risks related to cybersecurity.

The Company is subject to cybersecurity risks and may incur increasing costs in connection with its efforts to enhance and ensure security and in response to actual or attempted cybersecurity attacks.

Substantial aspects of the Company’s business depend on the secure operation of its computer systems and websites. Security breaches could expose the Company to a risk of loss, misuse or interruption of sensitive and critical information and functions, including its own proprietary information and that of its customers, suppliers and employees and functions that affect the operation of the business.  Such losses could result in operational impacts, reputational harm, competitive disadvantage, litigation, regulatory enforcement actions, and liability. While the Company devotes substantial resources to maintaining adequate levels of cybersecurity, there can be no assurance that it will be able to prevent all of the rapidly evolving types of cyber attacks. Actual or anticipated attacks and risks may cause the Company to incur increasing costs for technology, personnel and services to enhance security or to respond to occurrences.

If the Company’s security measures are circumvented, proprietary information may be misappropriated, its operations may be disrupted, and its computers or those of its customers or other third parties may be damaged. Compromises of the Company’s security may result in an interruption of operations, violation of applicable privacy and other laws, significant legal and financial exposure, damage to its reputation, and a loss of confidence in its security measures.

Risk That Relate to the Company’s Transportation and Storage Business

The transportation and storage 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 Panhandle for the transportation and storage of natural gas in interstate commerce.  FERC also has authority over the construction, acquisition, operation and disposition of these pipeline and storage assets.  In addition, the U.S. Coast Guard has oversight over certain issues including the importation of LNG.

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

22

adverse effect on the Company’s business, financial condition, results of operations or cash flows.  In 2010, in response to an intervention and protest filed by BG LNG Services (BGLS) regarding its rates with Trunkline LNG applicable to certain LNG expansions, FERC determined that there was no reason at that time to expend FERC’s resources on a Section 5 proceeding with respect to Trunkline LNG even though cost and revenue studies provided by the Company to FERC indicated Trunkline LNG’s revenues were in excess of its associated cost of service.  However, since the current fixed rates expire at the end of 2015 and revert to tariff rate for these LNG expansions as well as the base LNG facilities for which rates were set in 2002, a Section 5 proceeding could be initiated at that time and result in significant revenue reductions if the cost of service remains lower than revenues.  For additional related information, see “Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations – Other Matters – Rate Matters – Trunkline LNG Cost and Revenue Study.”

A rate reduction is also a possible outcome with any Section 4 rate case proceeding for the regulated entities of Panhandle, 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 businesses are subject to competition.

The interstate pipeline and storage businesses of Panhandle 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 Panhandle.

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

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

Fluctuations in energy commodity prices could adversely affect the pipeline businesses.

If natural gas prices in the supply basins connected to the pipeline systems of Panhandle 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 businesses are dependent on a small number of customers for a significant percentage of their sales.

Panhandle’s top two customers accounted for 43% of its 2012 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.

Risks That Relate to the Company’s Gathering and Processing Business

The Company’s gathering and processing business is unregulated.

Unlike the Company’s returns on its regulated transportation and distribution businesses, the natural gas gathering and processing operations conducted at SUGS are not regulated for cost-based ratemaking purposes and may potentially have a higher level of risk in recovering incurred costs than the Company’s regulated operations.

23

Although SUGS operates in an unregulated market, the business is subject to certain regulatory risks, most notably environmental and safety regulations.  Moreover, the Company cannot predict when additional legislation or regulation might affect the gathering and processing industry, nor the impact of any such changes on the Company’s business, financial position, results of operations or cash flows.

The Company’s gathering and processing business is subject to competition.

The gathering and processing industry is expected to remain highly competitive.  Most customers of SUGS have access to more than one gathering and/or processing system.  The Company’s ability to compete depends on a number of factors, including the infrastructure and contracting strategies of competitors in the Company’s gathering region and the efficiency, quality and reliability of the Company’s plant and gathering system.

In addition to SUGS’ current competitive position in the gathering and processing industry, its business is subject to pricing risks associated with changes in the supply of, and the demand for, natural gas and NGL.  Since the demand for natural gas or NGL is influenced by commodity prices (including prices for alternative energy sources), customer usage rates, weather, economic conditions, service costs and other factors beyond the control of the Company, volumes processed and/or NGL extracted during processing may, after analysis, be reduced from time to time based on existing market conditions.

The Company’s profit margin in the gathering and processing business is highly dependent on energy commodity prices.

SUGS’ gross margin is largely derived from (i) percentage of proceeds arrangements based on the volume and quality of natural gas gathered and/or NGL recovered through its facilities and (ii) specified fee arrangements for a range of services.  Under percent-of-proceeds arrangements, SUGS generally gathers and processes natural gas from producers for an agreed percentage of the proceeds from the sales of the resulting residue natural gas and NGL. The percent-of-proceeds arrangements, in particular, expose SUGS’ revenues and cash flows to risks associated with the fluctuation of the price of natural gas, NGL and crude oil and their relationships to each other. 

The markets and prices for natural gas and NGL depend upon many factors beyond the Company’s control. These factors include demand for these commodities, which fluctuates with changes in market and economic conditions, and other factors, including:

• the impact of seasonality and weather;

• general economic conditions;

• the level of domestic crude oil and natural gas production and consumption;

• the level of worldwide crude oil and NGL production and consumption;

• the availability and level of natural gas and NGL storage;

• the availability of imported natural gas, LNG, NGL and crude oil;

• actions taken by foreign oil and natural gas producing nations;

• the availability of local, intrastate and interstate transportation systems;

• the availability of NGL transportation and fractionation capacity;

• the availability and marketing of competitive fuels;

• the impact of energy conservation efforts;

• the extent of governmental regulation and taxation; and

• the availability and effective liquidity of natural gas and NGL derivative counterparties.

To manage its commodity price risk related to natural gas and NGL, the Company uses a combination of puts, fixed-rate (i.e., receive fixed price) or floating-rate (i.e. receive variable price) index and basis swaps, NGL gross processing spread puts and fixed-rate swaps and exchange-traded futures and options.  These derivative financial instruments allow the Company to preserve value and protect margins because changes in the value of the derivative financial instruments are highly effective in offsetting changes in physical market commodity prices and reducing basis risk.  Basis risk exists primarily due to price differentials between cash market delivery locations and futures contract delivery locations.  However, the Company does not fully hedge against commodity price changes, and therefore retains some exposure to market risk.  Accordingly, any adverse changes to commodity prices could result in decreased revenue and increased cost.  For information related to derivative financial instruments, see Note 11 to our consolidated financial statements.

A reduction in demand for NGL products by the petrochemical, refining or heating industries could materially adversely affect the Company’s gathering and processing business.

The NGL products the Company produces have a variety of applications, including for use as heating fuels, petrochemical feed stocks and refining blend stocks.  A reduction in demand for NGL products, whether because of general economic conditions, new

24

government regulations, reduced demand by consumers for products made with NGL products, increased competition from petroleum-based products due to pricing differences, mild winter weather, severe weather such as hurricanes causing damage to Gulf Coast petrochemical facilities or other reasons, could result in a decline in the value of the NGL products the Company sells and/or reduce the volume of NGL products the Company produces.

Operational risks are involved in operating a gathering and processing business.

Numerous operational risks are associated with the operation of a natural gas gathering and processing business. These include adverse weather conditions, accidents, the breakdown or failure of equipment or processes, the performance of processing and fractionation facilities below expected levels of capacity or efficiency, the collision of equipment with facilities and catastrophic events such as explosions, fires, earthquakes, floods, landslides, tornadoes, lightning or other similar events beyond the Company’s control. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Insurance proceeds may be inadequate to cover all liabilities or expenses incurred or revenues lost.

The Company does not obtain independent evaluations of natural gas reserves dedicated to its gathering and processing business, potentially resulting in future volumes of natural gas available to the Company being less than anticipated.

The Company does not obtain independent evaluations of natural gas reserves connected to its gathering systems due to the unwillingness of producers to provide reserve information, as well as the cost of such evaluations.  Accordingly, the Company does not have independent estimates of total reserves dedicated to its gathering systems or the anticipated life of such reserves.  If the total reserves or estimated lives of the reserves connected to the Company’s gathering systems are less than anticipated and the Company is unable to secure additional sources of natural gas, then the volumes of natural gas in the future and associated gross margin could be less than anticipated.  A decline in the volumes of natural gas and associated NGL in the Company’s gathering and processing business could have a material adverse effect on its business.

The Company depends on two natural gas producers for a significant portion of its supply of natural gas.  The loss of these producers or the replacement of its contracts on less favorable terms could result in a decline in the Company’s volumes and/or gross margin.

SUGS’ two largest natural gas suppliers for the year ended December 31, 2012 accounted for approximately 29% of the Company’s wellhead throughput under multiple contracts.  The loss of all or even a portion of the natural gas volumes supplied by these producers or the extension or replacement of these contracts on less favorable terms, if at all, as a result of competition or otherwise, could reduce the Company’s gross margin.  Although these producers represent a large volume of natural gas, the gross margin per unit of volume is significantly lower than the average gross margin per unit of volume on the Company’s gathering and processing system due to the lack of need for services required to make the natural gas merchantable (e.g. high pressure, low NGL content, essentially transmission pipeline quality natural gas).

The Company depends on one NGL customer for a significant portion of its sales of NGLs.  The loss of this customer or the replacement of its contract on less favorable terms could result in a decline in the Company’s gross margin.

Through December 31, 2014, SUGS has contracted to sell its entire owned or controlled output of NGL to Conoco Phillips Company (Conoco).  Pricing for the NGL volumes sold to Conoco throughout the contract period are based on OPIS pricing at Mont Belvieu, Texas delivery points.  For the period from March 26, 2012 to December 31, 2012, Conoco accounted for approximately 35% and 68% of the Company’s and SUGS’ operating revenues, respectively.

Risks That Relate to the Company’s Distribution Business

The distribution business is highly regulated and the Company’s revenues, operating results and financial condition may fluctuate with the distribution business’ ability to achieve timely and effective rate relief from state regulators.

The Company’s distribution business is subject to regulation by the MPSC and the MDPU. These authorities regulate many aspects of the Company’s distribution operations, including construction and maintenance of facilities, operations, safety, the rates that can be charged to customers and the maximum rate of return that the Company is allowed to realize. The ability to obtain rate increases depends upon regulatory discretion.

The distribution business is influenced by fluctuations in costs, including operating costs such as insurance, postretirement and other benefit costs, wages, changes in the provision for the allowance for doubtful accounts associated with volatile natural gas costs and other operating costs. The profitability of regulated operations depends on the business’ ability to recover costs related to providing services to its customers. To the extent that such operating costs increase in an amount greater than that for which

25

rate recovery is allowed, this differential could impact operating results until the business files for and is allowed an increase in rates. The lag between an increase in costs and the rate relief obtained from the regulators 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, regulators may prevent the business from passing along some costs in the form of higher rates.

The distribution business’ operating results and liquidity needs are seasonal in nature and may fluctuate based on weather conditions and natural gas prices.

The natural gas distribution business is a seasonal business with a significant percentage of annual operating revenues and EBITDA occurring in the traditional winter heating season in the first and fourth calendar quarters.  The business is also subject to seasonal and other variations in working capital due to changes in natural gas prices and the fact that customers pay for the natural gas delivered to them after they use it, whereas the business is required to pay for the natural gas before delivery.  As a result, fluctuations in natural gas prices may have a significant effect on results of operations and cash flows.

Operational risks are involved in operating a distribution business.

Numerous risks are associated with the operations of a natural gas distribution business.  These include adverse weather conditions, accidents, the breakdown or failure of equipment or processes, the performance of suppliers’ processing facilities below expected levels of capacity or efficiency, the collision of equipment with facilities and catastrophic events such as explosions, fires, earthquakes, floods, landslides, tornadoes, lightning or other similar events beyond the Company’s control. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Insurance proceeds may be inadequate to cover all liabilities or expenses incurred or revenues lost.

The distribution business has recorded certain assets that may not be recoverable from its customers.

The distribution business records certain assets on the Company’s balance sheet resulting from the regulatory process that could not be recorded under GAAP for non-regulated entities.  As of December 31, 2012, the Company’s regulatory assets recorded in its consolidated balance sheet as held-for-sale assets were $123 million, as the regulatory assets are included in the LDC Disposal Group. When establishing regulatory assets, the distribution business considers factors such as rate orders from its regulators, previous rate orders for substantially similar costs, written approval from the regulators and analysis of recoverability from legal counsel to determine the probability of future recovery of these assets.  The Company would be required to write-off any regulatory assets for which future recovery is determined not to be probable.

Cautionary Note Regarding Forward-Looking Statements

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

• changes in demand for natural gas or NGL and related services by customers, in the composition of the Company’s customer base and in the sources of natural gas or NGL 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 or NGL as well as electricity, oil, coal and other bulk materials and chemicals;

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

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

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

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

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

• unanticipated environmental liabilities;

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

26

• the impact of potential impairment charges;

• exposure to highly competitive commodity businesses and the effectiveness of the Company’s hedging program;

• 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 continue to access its revolving credit facility and 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 defined benefit pension plans and other postretirement benefit plans;

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

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

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

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

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

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

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

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

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

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

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2.  PROPERTIES

See “Item 1. Business – Business Segments” for information concerning the general location and characteristics of the important physical properties and assets of the Transportation and Storage, Gathering and Processing and Distribution segments.

27

ITEM 3. LEGAL PROCEEDINGS

The Company and certain of its affiliates are occasionally parties to lawsuits and administrative proceedings incidental to their businesses involving, for example, claims for personal injury and property damage, contractual matters, various tax matters, and rates and licensing.  The Company and its affiliates are also subject to various federal, state and local laws and regulations relating to the environment, as described in “Item 1. Business.” Several of these companies have been named parties to various actions involving environmental issues.  Based on the Company’s current knowledge and subject to future legal and factual developments, the Company’s management believes that it is unlikely that these actions, individually or in the aggregate, will have a material adverse effect on its consolidated financial position, results of operations or cash flows.  For additional information regarding various pending administrative and judicial proceedings involving regulatory, environmental and other legal matters, reference is made to Note 19 and Note 14 to our consolidated financial statements. Also see “Item 1A. Risk Factors.”

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

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

All of the interests in the Company are privately held by ETP Holdco Corporation, which is held by Energy Transfer Partners, L.P. through a 40% equity interest and Energy Transfer Equity, L.P., the parent of ETP, through the remaining 60% equity interest in Holdco. See Note 1 to our consolidated financial statements.

ITEM 6.  SELECTED FINANCIAL DATA

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

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

AND RESULTS OF OPERATIONS

(Tabular dollar amounts are in millions, except per gallon and per MMBtu amounts)

INTRODUCTION

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.

RESULTS OF OPERATIONS

Overview

The Company evaluates operational and financial segment performance using several factors, of which the primary financial measure is Segment Adjusted EBITDA.  For additional information related to the Company’s use of Segment Adjusted EBITDA as its primary financial measure for its reportable segments, see Note 18 to our consolidated financial statements.

The Merger, which was completed on March 26, 2012, was accounted for by ETE using business combination accounting.  By the application of “push-down” accounting, the Company allocated the purchase price paid by ETE to its assets, liabilities and equity as of the acquisition date based on preliminary estimates.  Accordingly, the successor financial statements reflect a new basis of accounting and predecessor and successor period financial results (separated by a heavy black line) are presented, but are not comparable.

The most significant impacts of the new basis of accounting going forward are expected to be (i) higher depreciation expense due to the step-up of depreciable assets and assignment of purchase price to certain amortizable intangible assets and (ii) lower interest

28

expense (though not cash payments) for the remaining life of the related long-term debt due to its revaluation and related debt premium amortization. 

The results of operations for the successor and predecessor periods reflect certain merger-related expenses, which are not expected to have a continuing impact on the results going forward, and those amounts are discussed in the segments results below. For information regarding expenses related to the merger, see Note 3 to our consolidated financial statements. The Holdco Transaction did not result in a new basis of accounting for Southern Union.

The Company previously reported segment earnings before interest and taxes (EBIT) as a measure of segment performance.  Subsequent to the ETE Merger, the chief operating decision maker assesses performance of the Company’s business based on Segment Adjusted EBITDA.  The Company defines Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, amortization and other non-cash items, such as non-cash compensation expense, unrealized gains and losses on unhedged derivative activities, accretion expense and amortization of regulatory assets and other non-operating income or expense items.  Segment Adjusted EBITDA reflects amounts for less than wholly owned subsidiaries and unconsolidated affiliates based on the Company’s proportionate ownership.  Based on the change in its segment performance measure, the Company has recast the presentation of its segment results for the prior periods to be consistent with the current period presentation.

Segment Adjusted EBITDA may not be comparable to measures used by other companies and should be considered in conjunction with net earnings and other performance measures such as operating income or net cash flows provided by operating activities.

The following table provides a reconciliation of Segment Adjusted EBITDA (by segment) to net income for the periods presented.

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Year Ended December 31, 2011
Segment Adjusted EBITDA:
Transportation and storage segment	$	326		$	186		$	778
Gathering and processing segment	40			25			125
Distribution segment	68			34			90
Corporate and other activities	8			(19		)	(6		)
Total Segment Adjusted EBITDA	442			226			987
Depreciation and amortization	(179		)	(49		)	(204		)
Interest expense	(131		)	(50		)	(218		)
Non-cash equity-based compensation, accretion expense and amortization of regulatory assets	(4		)	(1		)	(9		)
Net gain on curtailment of OPEB plans	15			—			—
Other, net	2			(2		)	—
Earnings (losses) from unconsolidated investments	(7		)	16			99
Adjusted EBITDA attributable to unconsolidated investments	(5		)	(61		)	(262		)
Adjusted EBITDA attributable to discontinued operations	(83		)	(34		)	(99		)
Income from continuing operations before income tax expense	50			45			294
Income tax expense	39			12			80
Income from continuing operations	11			33			214
Income from discontinued operations	28			17			41
Net income	$	39		$	50		$	255

29

The segment analysis in the following section describes the significant items impacting the Segment Adjusted EBITDA amounts reflected above. In addition, as discussed in the “Overview” section above, the comparability of net income between predecessor and successor periods was impacted by the application of “push-down” accounting. The most significant impacts of this new basis of accounting were:

• Incremental depreciation and amortization expense of approximately $13 million per quarter has been recognized in the successor periods subsequent to March 25, 2012 as a result of the application of the new basis of accounting.

• The application of “push-down” accounting also resulted in the Company’s long-term debt being recorded at fair value, which impacted the amount of amortization recorded in interest expense. This change in the amount of amortization resulted in a net reduction within interest expense of approximately $10 million per quarter subsequent to March 25, 2012.

The Company’s consolidated net income was also impacted by changes in income taxes that were driven by the ETE Merger; those impacts were described in the “Federal and State Income Taxes” section below.

The “Supplemental Pro Forma Information” section, which follows the “Business Segment Results” section, provides additional analysis of the Company’s consolidated net income on a year-to-date basis, assuming the ETE Merger had been completed on January 1, 2011.

Federal and State Income Taxes

The following table sets forth the Company’s income taxes on continuing operations for the periods presented.

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Year Ended December 31, 2011
Income tax expense	$	39		$	12		$	80
Effective tax rate	78		%	27		%	27		%

The increases in the effective tax rate during the successor period were primarily due to:

• The impact of non-deductible executive compensation resulting from the Merger-related employee severance expenses in the successor periods; and,

• Lower effective rates during the predecessor periods as a result of the dividend received deduction for the anticipated receipt of dividends associated with earnings from the Company’s unconsolidated investment in Citrus. The dividend received deduction was not applicable to the successor period as a result of the Company’s contribution of its investment in Citrus to ETP concurrent with the ETE Merger on March 26, 2012.

Business Segment Results

Transportation and Storage Segment

The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas in the Midwest, Gulf Coast and Midcontinent United States, and LNG terminalling and regasification services.  The Transportation and Storage segment’s operations, conducted through Panhandle and, through March 26, 2012 (the date of the Citrus Merger), Florida Gas Transmission Company, LLC (Florida Gas), are regulated as to rates and other matters by FERC. Demand for natural gas transmission services on Panhandle’s pipeline system is seasonal, with the highest throughput and a higher portion of annual total operating revenues and Segment Adjusted EBITDA occurring in the traditional winter heating season, which occurs during the first and fourth calendar quarters.  Florida Gas’ pipeline system experiences the highest throughput in the traditional summer cooling season during the second and third calendar quarters, primarily due to increased natural gas-fired electric generation loads.  See Note 3 to our consolidated financial statements for information related to the Citrus Merger.

The Company’s business within the Transportation and Storage segment 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,

30

changing supply sources and volatility in natural gas prices and basis differentials.  Since the majority of the revenues within the Transportation and Storage segment 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.

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.

The following table illustrates the results of operations applicable to the Company’s Transportation and Storage segment for the periods presented.

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Year Ended December 31, 2011
Operating revenues (1)	$	592		$	194		$	804
Operating, maintenance and general, net of non-cash compensation expense, accretion and gain on curtailment	(238		)	(60		)	(252		)
Taxes other than on income and revenues	(28		)	(9		)	(35		)
Adjusted EBITDA related to unconsolidated investments	—			61			261
Segment Adjusted EBITDA	$	326		$	186		$	778
Panhandle natural gas volumes transported (TBtu): (2)
PEPL	430			152			564
Trunkline	533			177			743
Sea Robin	91			20			113

⁽¹⁾  Reservation revenues comprised 87% in the successor period. Reservation revenues comprised 88% and 89% of total operating revenues in the 2012 and 2011 predecessor periods, respectively.

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

Following is a discussion of the significant items and variance impacting Segment Adjusted EBITDA for the Company’s Transportation and Storage segment.

• Operating Revenues. Operating revenues were lower in the successor period primarily due to the impact of customer contract buyouts of $14 million in 2011.

• Operating, Maintenance and General Expenses. The period from March 26, 2012 to December 31, 2012 included $48 million of merger-related employee severance expenses. The year ended December 31, 2011 reflected legal expenses that were lower than the legal expenses recorded during the predecessor and successor periods in 2012; this was due to settlement in 2011 of certain litigation with several contractors related to the Company’s East End projects. The successor period also reflected higher depreciation compared to the predecessor period, due to the step-up in depreciable assets in connection with the merger, offset by lower corporate allocations due to merger-related synergies.

• Unconsolidated Investments. The primary driver for the reduction in Segment Adjusted EBITDA for the Company’s Transportation and Storage segment was the contribution of Citrus to ETP on March 26, 2012. Citrus was reflected in Adjusted EBITDA attributable to unconsolidated investments for all of the predecessor periods shown above but was not reflected in the successor periods. The predecessor periods reflected Adjusted EBITDA attributable to Citrus of $261 million for the year ended December 31, 2011, and $61 million for the period from January 1, 2012 to March 25, 2012.

31

Gathering and Processing Segment

The Gathering and Processing segment is primarily engaged in connecting producing wells of exploration and production companies to its gathering system, providing compression and gathering services, treating natural gas to remove impurities to meet pipeline quality specifications, processing natural gas for the removal of NGL, and redelivering natural gas and NGL to a variety of markets.  Its operations are conducted through SUGS.  SUGS’ natural gas supply contracts primarily include fee-based, percent-of-proceeds and margin sharing (conditioning fee and wellhead) purchase contracts.  These natural gas supply contracts vary in length from month-to-month to a number of years, with many of the contracts having a term of three to five years.  SUGS’ primary sales customers include exploration and production companies, power generating companies, electric and gas utilities, energy marketers, industrial end-users located primarily in the Gulf Coast and southwestern United States, and petrochemical companies.  With respect to customer demand for the products and services it provides, SUGS’ business is not generally seasonal in nature; however, SUGS’ operations and the operations of its natural gas producers can be adversely impacted by severe weather.

The majority of SUGS’ gross margin is derived from the sale of NGL and natural gas equity volumes and fee-based services.  The prices of NGL and natural gas are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of factors beyond the Company’s control.  The Company monitors these risks and manages the associated commodity price risk using both economic and accounting hedge derivative instruments.  For additional information related to the Company’s commodity price risk management, see Note 11 to our consolidated financial statements.

32

The following table presents the results of operations applicable to the Company’s Gathering and Processing segment for the periods presented.

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Year Ended December 31, 2011
Operating revenues	$	663		$	246		$	1,180
Cost of natural gas and other energy (1)	(518		)	(196		)	(961		)
Gross margin (2)	145			50			219
Operating, maintenance and general, excluding non-cash compensation expense and accretion	(91		)	(23		)	(88		)
Taxes other than on income and revenues	(7		)	(2		)	(6		)
Adjusted EBITDA related to unconsolidated investments	(7		)	—			—
Segment Adjusted EBITDA	$	40		$	25		$	125
Operating Information:
Volumes:
Avg natural gas processed (MMBtu/d)	487,255			451,893			417,398
Avg NGL produced (gallons/d)	1,727,592			1,624,666			1,474,648
Avg natural gas wellhead volumes (MMBtu/d)	509,651			504,822			488,109
Natural gas sales (MMBtu)	68,307,744			16,017,102			72,353,292
NGL sales (gallons)	513,013,211			143,078,360			663,945,640
Average Pricing:
Realized natural gas ($/MMBtu)  (3)	$	2.76		$	2.44		$	3.86
Realized NGL ($/gallon)  (3)	0.93			1.17			1.33
Natural Gas Daily Waha ($/MMBtu)	2.77			2.43			3.91
Natural Gas Daily El Paso ($/MMBtu)	2.74			2.42			3.87
Estimated plant processing spread ($/gallon)	0.65			0.96			0.97

⁽¹⁾  Cost of natural gas and other energy consists of natural gas and NGL purchase costs, fractionation and other fees.

⁽²⁾  Gross margin consists of operating revenues less cost of natural gas and other energy.  The Company believes that this measurement is meaningful for understanding and analyzing the Gathering and Processing segment’s operating results for the periods presented because commodity costs are a significant factor in the determination of the segment’s revenues.

⁽³⁾  Excludes impact of realized and unrealized commodity derivative gains and losses.

Following is a discussion of the significant items and variance impacting Segment Adjusted EBITDA for the Company’s Gathering and Processing segment.

• Gross Margin. Gross margin for the predecessor and successor periods in 2012 decreased compared to 2011 due to decreases in market-driven realized average natural gas and NGL prices. Realized average natural gas and NGL prices were $2.76 per MMBtu and $0.93 per gallon for the period from March 26, 2012 to December 31, 2012, $2.44 per MMBtu and $1.17 per gallon for the period from January 1, 2012 to March 25, 2012, versus $3.86 per MMBtu and $1.33 per gallon for the year ended December 31, 2011.

• Operating, Maintenance and General Expenses. The period from March 26, 2012 to December 31, 2012 included $17 million of merger-related employee severance expenses. Operating, maintenance and general expenses have also increased between the end of the periods presented due to expansion of plant facilities.

33

Distribution Segment

The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts through the Company’s Missouri Gas Energy and New England Gas Company operating divisions, respectively.  The operations of the Distribution segment have been classified as discontinued operations as of December 31, 2012. The Distribution segment’s operations are regulated by the public utility regulatory commissions of the states in which each operates.  The Distribution segment’s operations have historically been sensitive to weather and seasonal in nature, with a significant percentage of annual operating revenues (which include pass-through gas purchase costs that are seasonally impacted) and Segment Adjusted EBITDA occurring in the traditional winter heating season during the first and fourth calendar quarters.  Most of Missouri Gas Energy’s revenues are based on a distribution rate structure that eliminates the impact of weather and conservations.  For additional information related to rate matters within the Distribution segment, seeNote 19 to our consolidated financial statements.

The following table illustrates the results of operations applicable to the Company’s Distribution segment for the periods presented.

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Year Ended December 31, 2011
Amounts reported within discontinued operations:
Net operating revenues  (1)	$	176		$	66		$	234
Operating, maintenance and general expenses, excluding non-cash compensation expense and amortization of regulatory assets	(97		)	(29		)	(132		)
Taxes other than on income and revenues	(11		)	(3		)	(12		)
Segment Adjusted EBITDA	$	68		$	34		$	90
Operating Information:
Natural gas sales volumes (MMcf)	22,407			19,957			55,123
Natural gas transported volumes (MMcf)	17,851			7,379			24,119
Weather – Degree Days: (2)
Missouri Gas Energy service territories	2,040			1,898			5,183
New England Gas Company service territories	2,542			2,170			5,162

⁽¹⁾ Operating revenues for the Distribution segment were reported net of cost of natural gas and other energy and revenue-related taxes, which are pass-through costs.

⁽²⁾ “Degree days” are a measure of the coldness of the weather experienced.  A degree day is equivalent to each degree that the daily mean temperature for a day falls below 65 degrees Fahrenheit.

Following is a discussion of the significant items and variance impacting Segment Adjusted EBITDA for the Company’s Distribution segment.

• Net Operating Revenues. The predecessor and successor periods in 2012 were higher compared to the year ended December 31, 2011 primarily due to new customer rates at New England Gas Company effective April 1, 2011.

• Operating, Maintenance and General Expenses. The predecessor and successor periods in 2012 reflected lower uncollectible customer accounts as a result of lower gas costs and energy assistance payments compared to the year ended December 31, 2011.

Corporate and Other Activities

The period from January 1, 2012 to March 25, 2012 included $19 million of merger-related expenses.

See Note 3 to our consolidated financial statements for additional information related to the Company’s merger with ETE.

34

Supplemental Pro Forma Financial Information

The following unaudited pro forma consolidated financial information of the Company has been prepared in accordance with Article 11 of Regulation S-X and reflects the pro forma impacts of the ETE Merger for the years ended December 31, 2012 and 2011, giving effect to the ETE Merger as if it had occurred on January 1, 2011. This unaudited pro forma financial information is provided to supplement the discussion and analysis of the historical financial information and should be read in conjunction with such historical financial information. This unaudited pro forma information is for illustrative purposes only and is not necessarily indicative of the financial results that would have occurred if the ETE Merger had been consummated on January 1, 2011.

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Pro forma adjustments				Pro forma year ended December 31, 2012
OPERATING REVENUES	$	1,263		$	443		$	—			$	1,706
OPERATING EXPENSES:
Cost of natural gas and other energy	521			197							718
Operating, maintenance and general	340			105			(81		)	(a)	364
Depreciation and amortization	179			49			6			(b)	234
Taxes, other than on income and revenues	37			11							48
Total operating expenses	1,077			362			(75		)		1,364
OPERATING INCOME	186			81			75				342
OTHER INCOME (EXPENSE):
Interest expense	(131		)	(50		)	9			(c)	(172		)
Earnings from unconsolidated investments	(7		)	16			(16		)	(d)	(7		)
Other, net	2			(2		)	—				—
Total other expenses, net	(136		)	(36		)	(7		)		(179		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	50			45			68				163
Income tax expense	39			12			10			(e)	61
INCOME (LOSS) FROM CONTINUING OPERATIONS	11			33			58				102
Income from discontinued operations	28			17			—				45
NET INCOME	$	39		$	50		$	58			$	147

35

	Predecessor
	Year Ended December 31, 2011			Pro forma adjustments				Pro forma year ended December 31, 2011
OPERATING REVENUES	$	1,997		$	—			$	1,997
OPERATING EXPENSES:
Cost of natural gas and other energy	965			—				965
Operating, maintenance and general	373			(16		)	(a)	357
Depreciation and amortization	204			25			(b)	229
Taxes, other than on income and revenues	42			—				42
Total operating expenses	1,584			9				1,593
OPERATING INCOME	413			(9		)		404
OTHER INCOME (EXPENSE):
Interest expense	(218		)	38			(c)	(180		)
Earnings from unconsolidated investments	99			(93		)	(d)	6
Other, net	—			—				—
Total other expenses, net	(119		)	(55		)		(174		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	294			(64		)		230
Income tax expense	80			5			(e)	85
INCOME FROM CONTINUING OPERATIONS	214			(69		)		145
Income from discontinued operations	41			—				41
NET INCOME	$	255		$	(69	)		$	186

(a) To eliminate the merger-related costs incurred by the Company in connection with the ETE Merger, including change in control and severance costs. These costs are eliminated from the Company’s pro forma income statement because such costs would not have a continuing impact on the Company’s results of operations.

(b) To record incremental depreciation on the excess purchase price allocated to property, plant and equipment based on a weighted average useful life of 24 years.

(c) To adjust amortization included in interest expense to (i) reverse historical amortization of financing costs and fair value adjustments related to debt and (ii) record pro forma amortization related to the pro forma adjustment of the Company’s debt to fair value.

(d) To adjust earnings from unconsolidated investments to (i) eliminate historical earnings related to Citrus to give effect to the transfer of the Company’s interest in Citrus in connection with the ETE Merger and (ii) record incremental earnings from the Company’s investment in ETP common units received in connection with the transfer of Citrus.

(e) To reflect income tax impacts from the pro forma adjustments to pre-tax income, including the elimination of the dividend received deduction recorded in the historical income tax provision for the predecessor periods in connection with the Company’s investment in Citrus.

Analysis of Supplemental Pro Forma Financial Information

Following is a discussion of the significant items impacting the pro forma results for the year ended December 31, 2012 compared to pro forma results for the year ended December 31, 2011.

• Pro forma operating revenues and cost of natural gas and other energy decreased between periods primarily due to the actual results from the Company’s Gathering and Processing segment attributable to (i) lower throughput volumes in the 2012 period as a result of processing plant outages and producer well freeze-offs resulting from unusually cold weather in early 2012, and (ii) the impact of lower market-driven realized average natural gas and NGL prices (unadjusted for the impact of realized and unrealized commodity derivative gains and losses) of $2.70 per MMBtu and $0.98 per gallon in the 2012 period versus $3.86 per MMBtu and $1.33 per gallon in the 2011 period.

• Pro forma interest expense decreased between periods primarily due to the term loan repayment in February 2012.

36

OTHER MATTERS

Off-Balance Sheet Arrangements and Aggregate Contractual Obligations

The Company does not have any material off-balance sheet arrangements other than that as noted in Note 8 to our consolidated financial statements.

The following table summarizes the Company’s expected contractual obligations by payment due date as of December 31, 2012, excluding those obligations of our disposal group.

	Contractual Obligations
	Total		2013		2014		2015		2016		2017		2018 and thereafter
Long-term debt  (1) (2)	$	3,098	$	251	$	1	$	456	$	211	$	301	$	1,878
Natural gas purchases  (3)	31		3		3		3		3		3		16
Transportation contracts	31		2		7		7		7		7		1
Natural gas storage contracts   (4)	119		26		26		20		15		14		18
Operating lease payments	127		20		16		15		8		7		61
Interest payments on debt (5)	2,306		158		149		142		138		137		1,582
Fractionation contract	280		27		33		37		38		38		107
Other   (6)	39		5		4		4		5		5		16
	$	6,031	$	492	$	239	$	684	$	425	$	512	$	3,679

⁽¹⁾  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 certain level of net worth, to meet certain debt to total capitalization ratios, and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense.  At December 31, 2012, the Company was in compliance with all of its covenants.  See Note 8 to our consolidated financial statements.

⁽²⁾  The long-term debt principal payment obligations exclude $185 million of unamortized debt premium as of December 31, 2012.

⁽³⁾  The Company has tariffs in effect for all its utility service areas that provide for recovery of its purchased natural gas costs under defined methodologies.

⁽⁴⁾  Represents charges for third party natural gas storage capacity.

⁽⁵⁾  Interest payments on debt are based upon the applicable stated or variable interest rates as of December 31, 2012.  Includes approximately $1.12 billion of interest payments associated with the Junior Subordinated Notes due November 1, 2066.

⁽⁶⁾  Various other contractual obligations. Excludes non-current deferred tax liabilities of $1.59 billion due to uncertainty of the timing of future cash flows for such liabilities

Contingencies

SeeNote 14 to our consolidated financial statements.

Inflation

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

Regulatory

SeeNote 19 to our consolidated financial statements.

37

Rate Matters

Trunkline LNG Cost and Revenue Study.  On July 1, 2009, Trunkline LNG filed a Cost and Revenue Study with respect to the Trunkline LNG facility expansions completed in 2006, in compliance with FERC orders.  Such filing, which was as of March 31, 2009, reflected an annualized cost of service level for these expansions of $55 million, less than the associated actual revenues during the same period of $69 million.  BGLS filed a motion to intervene and protest on July 14, 2009.  By order dated July 26, 2010, FERC determined that since (i) Trunkline LNG has fixed negotiated rates with BGLS through 2015, which would be unaffected by any rate change that might be determined through hearing at this time, and (ii) current costs and revenues are not necessarily representative of Trunkline LNG’s costs and revenues at the termination of the negotiated rate period in 2015, there was no reason to expend FERC’s and the parties’ resources on a Natural Gas Act Section 5 proceeding at this time.  The order is final and not subject to rehearing.

SeeNote 19 to our consolidated financial statements for information related to the Company’s other rate matters.

LNG Export License.  On July 22, 2011, the United States Department of Energy, Office of Fossil Energy issued an order authorizing Lake Charles Exports, LLC, an entity owned by subsidiaries of the Company and BG Group plc, to export domestically produced LNG by vessel from Trunkline LNG’s Lake Charles LNG terminal.  The authorization, for a 25-year term beginning on the earlier of the date of first export or 10 years from the issuance of the order, permits export of up to approximately 2 Bcf/d to countries that have or will enter into a free trade agreement (FTA) with the United States that requires national treatment for trade in natural gas.  Lake Charles Exports, LLC is permitted to use the authorization to export LNG on its own behalf or as an agent for BGLS.  A proceeding for approval to export to non-FTA countries is ongoing. Another affiliate of the Company, Trunkline LNG Export, LLC has also filed with the United States Department of Energy, Office of Fossil Energy for LNG export authorization to export up to approximately 2 Bcf/d to FTA and non-FTA countries. This authorization is non-additive to the LCE authorization request, but is requested by Trunkline LNG Export, LLC to provide greater flexibility and optionality in their potential marketing of LNG. The companies are developing plans to install liquefaction facilities at the Lake Charles terminal to export LNG. Modifications to the Lake Charles terminal would be subject to approval by the FERC.  The Company and BG Group plc have not finalized the economic terms of their arrangement, but the Company expects that any such arrangement will take into account, among other things, the December 31, 2015 termination of certain contracted rates at the existing Trunkline LNG terminal, which otherwise revert to tariff rates in 2016, and the term of BGLS contracts related to the Trunkline LNG terminal, which otherwise all expire in 2030.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

The Company is subject to the risk of loss associated with movements in market interest rates.  The Company manages this risk through the use of fixed-rate debt, floating-rate debt and interest rate swaps.  Fixed-rate swaps are used to reduce the risk of increased interest costs during periods of rising interest rates.  Floating-rate swaps are used to convert the fixed rates of long-term borrowings into short-term variable rates.  At December 31, 2012, the interest rate on 78% of the Company’s long-term debt was fixed after considering the impact of interest rate swaps.

At December 31, 2012, $18 million was included in derivative instruments - liabilities and $59 million was included in deferred credits in the consolidated balance sheet related to the fixed-rate interest rate swaps on $525 million of the $600 million Junior Subordinated Notes due 2066.

At December 31, 2012, a 100 basis point change in the annual interest rate on all outstanding floating-rate debt would correspondingly change the Company’s interest payments by $7 million annually.  If interest rates change significantly, the Company may take actions to manage its exposure to the change.

The change in exposure to loss in earnings and cash flow related to interest rate risk for the year ended December 31, 2012 was not material to the Company.

See Note 11 and Note 8 to our consolidated financial statements.

Commodity Price Risk

Gathering and Processing Segment.  The Company markets natural gas and NGL in its Gathering and Processing segment and manages associated commodity price risks using both economic and accounting hedge derivative financial instruments.  These instruments involve not only the risk of transacting with counterparties and their ability to meet the terms of the contracts, but

38

also the risks associated with unmatched positions and market fluctuations.  The Company is required to record its commodity derivative financial instruments at fair value, which is affected by commodity exchange prices, over-the-counter quotes, volatility, time value, credit and counterparty credit risk and the potential impact on market prices of liquidating positions in an orderly manner over a reasonable period of time under current market conditions.

To manage its commodity price risk related to natural gas and NGL, the Company may use a combination of (i) natural gas puts, price swaps and basis swaps, (ii) NGL price swaps, (iii) NGL processing spread puts and swaps, and (iv) other exchange-traded futures and options.  These derivative financial instruments allow the Company to preserve value and protect margins.

The Company realizes NGL, NGL processing spread and/or natural gas volumes from the contractual arrangements associated with the natural gas treating and processing services it provides.  Forecasted NGL, NGL processing spread and/or natural gas volumes compared to the actual volumes sold and the effectiveness of the associated economic hedges utilized by the Company can be unfavorably impacted by:

• processing plant outages;

• limitations on treating capacity;

• higher than anticipated fuel, flare and unaccounted-for natural gas levels;

• impact of commodity prices in general;

• decline in drilling and/or connections of new supply;

• limitations in available natural gas and NGL take-away capacity;

• reduction in NGL available from wellhead supply;

• lower than expected recovery of NGL from the inlet natural gas stream;

• lower than expected receipt of natural gas volumes to be processed;

• limitations on NGL fractionation capacity;

• renegotiation of existing contracts;

• change in contracting practices vis-à-vis type(s) of processing contracts;

• competition for new wellhead supplies; and

• changes to environmental or other laws and regulations.

The following table summarizes SUGS’ principal commodity derivative instruments as of December 31, 2012 (all instruments are settled monthly), based upon historical and projected operating conditions and processable volumes.

Instrument Type	Index	Average Fixed Price (per MMBtu)		2013 Volumes (MMBtu/d) (2)		Fair Value of Assets (Liabilities)
				(in millions)
Natural Gas - Cash Flow Hedges:   (1)
Receive-fixed swap	NYMEX Swap	$	3.24	28		$	(3	)
Pay-fixed swap	NYMEX Swap	$	3.93	(15	)	(2		)
		Total		13		$	(5	)

⁽¹⁾  The Company’s natural gas swap arrangements have been designated as cash flow hedges.  The effective portion of changes in the fair value of the cash flow hedges is recorded in accumulated other comprehensive loss until the related hedged items impact earnings.  Any ineffective portion of a cash flow hedge is reported in current-period earnings.

⁽²⁾  All volumes are applicable to the period January 1, 2013 to December 31, 2013, with 72% of the volumes settled against Gas Daily - El Paso Permian and 28% of the volumes settled against Gas Daily – Waha.

At December 31, 2012, excluding the effects of hedging and assuming normal operating conditions, the Company estimates that a change in price of $0.01 per gallon of NGL and $1.00 per MMBtu of natural gas would impact annual gross margin by approximately $1 million and $14 million, respectively.  Such commodity price risk estimates do not include any effect on demand for the Company’s services that may be caused by, or arise in conjunction with, price changes.  For example, a change in the gross processing spread may cause some ethane to be sold in the natural gas stream, impacting gathering and processing margins, natural gas deliveries and NGL volumes shipped.

Transportation and Storage Segment.  The Company is exposed to some commodity price risk with respect to natural gas used in operations by its interstate pipelines.  Specifically, the pipelines receive natural gas from customers for use in generating

39

compression to move the customers’ natural gas.  Additionally, the pipelines may have to settle system imbalances when customers’ actual receipts and deliveries do not match.  When the amount of natural gas utilized in operations by the pipelines differs from the amounts provided by customers, the pipelines may use natural gas from inventory or may have to buy or sell natural gas to cover these or other operational needs, resulting in commodity price risk exposure to the Company.  In addition, there is other indirect exposure to the extent commodity price changes affect customer demand for and utilization of transportation and storage services provided by the Company.  At December 31, 2012, there were no hedges in place with respect to natural gas price risk associated with the Company’s interstate pipeline operations.

Distribution Segment Economic Hedging Activities.  The Company enters into financial instruments to mitigate price volatility of purchased natural gas passed through to customers in its Distribution segment. The cost of the derivative products and the settlement of the respective obligations are recorded through the natural gas purchase adjustment clause as authorized by the applicable regulatory authority and therefore do not impact earnings. The fair values of the contracts are recorded as an adjustment to a regulatory asset or liability in the consolidated balance sheets.  As of December 31, 2012, the fair values of the contracts, which expire at various times through December 2013, were included in the consolidated balance sheet as liabilities held-for-sale, with matching adjustments to deferred cost of natural gas of $8 million.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING

AND FINANCIAL DISCLOSURE

None.

ITEM 9A.  CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

An evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rules 13a–15(e) and 15d–15(e) of the Exchange Act) as of the end of the period covered by this report. Based upon that evaluation, management, including the Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures were adequate and effective as of December 31, 2012.

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. Internal control over financial reporting is defined in Exchange Act Rule 13a-15(f) as a process designed by, or under the supervision of, the Company’s principal executive officer and principal financial officers, or persons performing similar functions, and effected by the Company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP, and includes those policies and procedures that:

• Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company;

• Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company; and

• Provide reasonable assurance regarding the prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

Exchange Act Rules 13a-15(c) and 15d-15(c) and Section 404 of the Sarbanes-Oxley Act of 2002 require management of the Company to conduct an annual evaluation of the Company’s internal control over financial reporting and to provide a report on management’s assessment, including a statement as to whether or not internal control over financial reporting is effective. Pursuant to the rules of the SEC, Management’s attestation report regarding internal control over financial reporting was not subject to attestation by the Company’s independent registered public accountant. As such, this Form 10-K does not contain an attestation report of the Company’s independent registered public accountant regarding internal control over financial reporting.

40

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management’s evaluation of the effectiveness of the Company’s internal control over financial reporting was based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under that framework and applicable SEC rules, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2012.

Changes In Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting (as defined in Rules 13a–15(f) or Rule 15d–15(f)) that occurred in the three months ended December 31, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B.  OTHER INFORMATION.

None.

PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

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

ITEM 11.  EXECUTIVE COMPENSATION.

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

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

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

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

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

41

ITEM 14.  PRINCIPAL ACCOUNTING FEES AND SERVICES.

The Audit Committee of the Board of Directors of ETE appointed Grant Thornton LLP as our principal accountant to conduct the audit of our financial statements for the year ended December 31, 2012 on April 16, 2012.  PricewaterhouseCoopers LLC served as our independent registered public accountant for the year ended December 31, 2011.  The approval of Grant Thornton LLP occurred subsequent to the ETE merger but prior to the Holdco Transaction. 

The following table sets forth fees billed by Grant Thornton LLP and PricewaterhouseCoopers LLC for the audits of our annual financial statements and other services rendered:

	Grant Thornton LLP		Pricewaterhouse-Coopers LLC
	2012		2011
Audit fees (1)	$	1,475,000	$	2,965,000
Audit related fees (2)	25,000		—
Total	$	1,500,000	$	2,965,000

⁽¹⁾  Includes fees for audits of annual financial statements of our companies, reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC and services related to the audit of our internal controls over financial reporting.

⁽²⁾  Represents fees related to the service organization control report on the Company’s centralized data center.

Subsequent to the Holdco Transaction, the ETP Audit Committee is responsible for the oversight of our accounting, reporting and financial practices, pursuant to the charter of the ETP Audit Committee. The ETP Audit Committee has the responsibility to select, appoint, engage, oversee, retain, evaluate and terminate our external auditors; pre-approve all audit and non-audit services to be provided, consistent with all applicable laws, to us by our external auditors; and establish the fees and other compensation to be paid to our external auditors. The ETP Audit Committee also oversees and directs our internal auditing program and reviews our internal controls.

The ETP Audit Committee has adopted a policy for the pre-approval of audit and permitted non-audit services provided by our principal independent accountants. The policy requires that all services provided by Grant Thornton LLP including audit services, audit-related services, tax services and other services, must be pre-approved by the ETP Audit Committee.

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

• the auditors’ internal quality-control procedures;

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

• the independence of the external auditors;

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

• the rotation of the lead partner.

PART IV

ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

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.

42

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		SOUTHERN UNION COMPANY
		(Registrant)
Date:	March 1, 2013	By:	/s/   Martin Salinas, Jr.
			Martin Salinas, Jr.
			Chief Financial Officer (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 in the capacities and on the dates indicated:

Signature	Title	Date
/s/ Kelcy L. Warren      Kelcy L. Warren	Chief Executive Officer (principal executive officer)	March 1, 2013
/s/ Martin Salinas, Jr.      Martin Salinas, Jr.	Chief Financial Officer (principal financial officer)	March 1, 2013
/s/ Marshall S. McCrea, III      Marshall S. McCrea, III	President, Chief Operating Officer and Director	March 1, 2013
/s/ John W. McReynolds      John W. McReynolds	Director	March 1, 2013
/s/ John D. Harkey, Jr.      John D. Harkey, Jr.	Director	March 1, 2013
/s/ Kyle Kutch      Kyle Kutch	Director	March 1, 2013

43

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 No.
2(a)	Purchase and Sale Agreement dated as of December 14, 2012 among Southern Union Company, Plaza Missouri Acquisition, Inc. and for certain limited purposes The Laclede Group, Inc. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on December 17, 2012 and incorporated herein by reference.)
2(b)	Purchase and Sale Agreement dated as of December 14, 2012 among Southern Union Company, Plaza Massachusetts Acquisition, Inc. and for certain limited purposes The Laclede Group, Inc. (Filed as Exhibit 10.2 to Southern Union’s Current Report on Form 8-K filed on December 17, 2012 and incorporated herein by reference.)
2(c)	Agreement and Plan of Merger, dated as of June 15, 2011, as amended and restated as of July 4, 2011 and July 19, 2011, by and among Southern Union Company, Energy Transfer Equity, L.P. and Sigma Acquisition Corporation. (Filed as Exhibit 2.1 to Southern Union’s Current Report on Form 8-K filed on July 20, 2011 and incorporated herein by reference.)
2(d)	Amendment No. 1, dated as of September 14, 2011, to the Second Amended and Restated Agreement and Plan of Merger dated July 19, 2011, by and among Southern Union Company, Energy Transfer Equity, L.P. and Sigma Acquisition Corporation. (Filed as Exhibit 2.1 to Southern Union’s Current Report on Form 8-K filed on September 15, 2011 and incorporated herein by reference.)
2(e)	Agreement and Plan of Merger, dated as of July 4, 2011, as amended and restated on July 19, 2011, between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. (Filed as an exhibit to Exhibit 2.1 to Southern Union’s Current Report on Form 8-K filed on July 20, 2011 and incorporated herein by reference.)
2(f)	Amendment No. 1, dated as of September 14, 2011, to the Amended and Restated Agreement and Plan of Merger, dated as of July 19, 2011, between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on September 15, 2011 and incorporated herein by reference.)
3(a)	Amended and Restated Certificate of Incorporation of Southern Union Company. (Filed as Exhibit 3.1 to Southern Union’s Current Report on Form 8-K filed on March 27, 2012 and incorporated herein by reference.)
3(b)	By-Laws of Southern Union Company, as amended.  (Filed as Exhibit 3.2 to Southern Union’s Current Report on Form 8-K filed on March 27, 2012 and incorporated herein by reference.)
4(a)	Senior Debt Securities Indenture between Southern Union and The Chase Manhattan Bank (National Association), which changed its name to JP Morgan Chase Bank and then to JP Morgan Chase Bank, N.A., which was then succeeded to by The Bank of New York Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company N.A., as Trustee (Filed as Exhibit 4.1 to Southern Union’s Current Report on Form 8-K dated February 15, 1994 and incorporated here-in by reference.)
4(b)	Officers' Certificate dated January 31, 1994 setting forth the terms of the 7.60% Senior Debt Securities due 2024.  (Filed as Exhibit 4.2 to Southern Union's Current Report on Form 8-K dated February 15, 1994 and incorporated herein by reference.)
4(c)	Officer's Certificate of Southern Union Company dated November 3, 1999 with respect to 8.25% Senior Notes due 2029.  (Filed as Exhibit 99.1 to Southern Union's Current Report on Form 8-K filed on November 19, 1999 and incorporated herein by reference.)
4(d)	Form of Supplemental Indenture No. 1, dated June 11, 2003, between Southern Union Company and JP Morgan Chase Bank, which changed its name to JP Morgan Chase Bank, N.A., the predecessor to The Bank of New York Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A. (Filed as Exhibit 4.5 to Southern Union’s Form 8-A/A dated June 20, 2003 and incorporated herein by reference.)
4(e)	Supplemental Indenture No. 2, dated February 11, 2005, between Southern Union Company and JP Morgan Chase Bank, N.A., the predecessor to The Bank of New York Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A. (Filed as Exhibit 4.4 to Southern Union’s Form 8-A/A dated February 22, 2005 and incorporated herein by reference.)
4(f)	Subordinated Debt Securities Indenture between Southern Union and The Chase Manhattan Bank (National Association), which changed its name to JP Morgan Chase Bank and then to JP Morgan Chase Bank, N.A., which was then succeeded to by The Bank of New York 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-G to Southern Union’s Registration Statement on Form S-3 (No. 33-58297) and incorporated herein by reference.)

E-1

Exhibit No.
4(g)	Second Supplemental Indenture, dated October 23, 2006, between Southern Union Company and The Bank of New York Trust Company, N.A., now known as The Bank of New York Mellon Trust Company, N.A. (Filed as Exhibit 4.1 to Southern Union’s Form 8-K/A dated October 24, 2006 and incorporated herein by reference.)
4(h)	2006 Series A Junior Subordinated Notes Due November 1, 2066 dated October 23, 2006. (Filed as Exhibit 4.2 to Southern Unions Current Report on Form 8-K/A filed on October 24, 2006 and incorporated herein by reference.)
4(i)	Replacement Capital Covenant, dated as of October 23, 2006 by Southern Union Company, a Delaware corporation with its successors and assigns, in favor of and for the benefit of each Covered Debtor (as defined in the Covenant). (Filed as Exhibit 4.3 to Southern Union’s Current Report on Form 8-K/A filed on October 24, 2006 and incorporated herein by reference.)
4(j)	Southern Union is a party to other debt instruments, none of which authorizes the issuance of debt securities in an amount which exceeds 10% of the total assets of Southern Union.  Southern Union hereby agrees to furnish a copy of any of these instruments to the Commission upon request.
10(a)	Eighth Amended and Restated Revolving Credit Agreement, dated as of March 26, 2012, among the Company, as borrower, and the lenders party thereto. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on March 27, 2012 and incorporated herein by reference.)
10(b)	First Amendment to Eighth Amended and Restated Revolving Credit Agreement dated March 26, 2012, among the Company as borrower, and the lenders party thereto (Filed as Exhibit 10.1 to Southern Union's Current Report on Form 8-K filed on August 16, 2012 and incorporated herein by reference.)
10(c)	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.
10(d)	Support Agreement, dated as of March 26, 2012, among PEPL Holdings, LLC, Energy Transfer Partners, L.P. and Citrus ETP Finance, LLC (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on March 26, 2012 and incorporated herein by reference.)
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

E-2

INDEX TO FINANCIAL STATEMENTS

Southern Union Company and Subsidiaries

Financial Statements and Supplementary Data:	Page:
Reports of Independent Registered Public Accounting Firms	F-2
Consolidated Balance Sheets - December 31, 2012 and 2011	F-4
Consolidated Statements of Operations - Period from Acquisition (March 26, 2012) to December 31, 2012, the Period from January 1, 2012 to March 25, 2012, and the Years Ended December 31, 2011 and 2010	F-7
Consolidated Statements of Comprehensive Income - Period from Acquisition (March 26, 2012) to December 31, 2012, the Period from January 1, 2012 to March 25, 2012, and the Years Ended December 31, 2011 and 2010	F-8
Consolidated Statements of Stockholders’ Equity - Period from Acquisition (March 26, 2012) to December 31, 2012, the Period from January 1, 2012 to March 25, 2012, and the Years Ended December 31, 2011 and 2010	F-9
Consolidated Statements of Cash Flows - Period from Acquisition (March 26, 2012) to December 31, 2012, the Period from January 1, 2012 to March 25, 2012, and the Years Ended December 31, 2011 and 2010	F-10
Notes to Consolidated Financial Statements	F-11

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors

of Southern Union Company:

We have audited the accompanying consolidatedbalance sheet of Southern Union Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2012, and the related consolidated statements of operations, comprehensive income, stockholders’ equity, and cash flows for the period from March 26, 2012 to December 31, 2012 and for the period from January 1, 2012 to March 25, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit 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. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit 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 Company’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 audit provides 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 Southern Union Company and subsidiariesas of December 31, 2012, and the results of their operations and their cash flows for the period from March 26, 2012 to December 31, 2012 and for the period from January 1, 2012 to March 25, 2012 in conformity with accounting principles generally accepted in the United States of America.

We have also audited the adjustments to the 2011 and 2010 financial statements to report the LDC Disposal Group’s results of operations as discontinued operations in the consolidated statements of operations, as described in Note 1 to the financial statements. In our opinion, such adjustments are appropriate and have been properly applied. We were not engaged to audit, review, or apply any procedures to the 2011 or 2010 financial statements of the Company other than with respect to such adjustments and, accordingly, we do not express an opinion or any other form of assurance on the 2011 or 2010 financial statements taken as a whole.

/s/ GRANT THORNTON LLP

Houston, Texas

March 1, 2013

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and Board of Directors

of Southern Union Company:

In our opinion, the consolidated balance sheet as of December 31, 2011 and the related consolidated statements of operations, of comprehensive income, of stockholder's equity and of cash flows for each of the two years ended December 31, 2011, before the effects of the adjustments to retrospectively reflect the discontinued operations described in Note 3, present fairly, in all material respects, the financial position of Southern Union Company and its subsidiaries (the "Company") at December 31, 2011, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America (the 2011 and 2010 financial statements before the effects of the adjustments discussed in Note 3 are not presented herein). These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits, before the effects of the adjustments described above, of these statements 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. An audit 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, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

We were not engaged to audit, review, or apply any procedures to the adjustments to retrospectively reflect the discontinued operations described in Note 3 and accordingly, we do not express an opinion or any other form of assurance about whether such adjustments are appropriate and have properly applied. Those adjustments were audited by other auditors.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 24, 2012

F-3

FINANCIAL STATEMENTS

The Company’s March 26, 2012 merger transaction with ETE was accounted for by ETE using business combination accounting.  Under this method, the purchase price paid by the acquirer is allocated to the assets acquired and liabilities assumed as of the acquisition date based on their fair value.  By the application of “push-down” accounting, Southern Union’s assets, liabilities and equity were accordingly adjusted to fair value on March 26, 2012.  Determining the fair value of certain assets and liabilities assumed is judgmental in nature and often involves the use of significant estimates and assumptions.  See Note 3 to our consolidated financial statements for a discussion of the estimated fair values of assets and liabilities recorded in connection with the ETE Merger.

Due to the application of “push-down” accounting, the Company’s financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting.  Periods prior to March 26, 2012 are identified herein as “Predecessor,” while periods subsequent to the ETE Merger are identified as “Successor.”

F-4

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

	Successor			Predecessor
	December 31, 2012			December 31, 2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	49		$	24
Accounts receivable net of allowances of nil and $2, respectively	155			271
Accounts receivable from related companies	72			10
Inventories	163			204
Deferred natural gas purchases	—			51
Natural gas imbalances — receivable	11			55
Current assets held for sale	184			—
Prepayments and other assets	120			43
Total current assets	754			658
PROPERTY, PLANT AND EQUIPMENT:
Plant in service	5,491			7,196
Construction work in progress	272			104
	5,763			7,300
Accumulated depreciation and amortization	(105		)	(1,573		)
Net property, plant and equipment	5,658			5,727
NON-CURRENT ASSETS HELD FOR SALE	985			—
DEFERRED CHARGES:
Regulatory assets	—			57
Other deferred charges	65			60
Total deferred charges	65			117
UNCONSOLIDATED INVESTMENTS	115			1,633
GOODWILL	2,364			89
OTHER NON-CURRENT ASSETS	52			47
Total assets	$	9,993		$	8,271

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

F-5

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars and shares in millions, except par value)

	Successor			Predecessor
	December 31, 2012			December 31, 2011
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current portion of long–term debt	$	259		$	343
Notes payable	—			200
Accounts payable and accrued liabilities	118			194
Accounts payable to related companies	110			—
Federal, state and local taxes payable	16			37
Accrued interest	32			34
Natural gas imbalances — payable	133			145
Derivative instruments	18			59
Current liabilities held for sale	85			—
Other	108			112
Total current liabilities	879			1,124
LONG-TERM DEBT, less current maturities	3,024			3,160
DEFERRED CREDITS	330			302
DEFERRED INCOME TAXES	1,590			1,045
NON-CURRENT LIABILITIES HELD FOR SALE	142			—
COMMITMENTS AND CONTINGENCIES (Note 14)
STOCKHOLDERS’ EQUITY:
Common stock, $0.01 and $1 par value; nil and 200 shares authorized; nil and 126 shares issued, respectively	—			126
Premium on capital stock	4,079			1,934
Less: Treasury stock, nil and 1 shares, respectively, at cost	—			(33		)
Less: Common stock held in trust, nil and 1 shares, respectively	—			(11		)
Deferred compensation plans	—			11
Accumulated other comprehensive loss	(25		)	(119		)
Retained earnings (accumulated deficit)	(26		)	732
Total stockholders’ equity	4,028			2,640
Total liabilities and stockholders’ equity	$	9,993		$	8,271

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

F-6

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in millions)

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Years Ended December 31,
							2011			2010
OPERATING REVENUES	$	1,263		$	443		$	1,997		$	1,789
OPERATING EXPENSES:
Cost of natural gas and other energy	521			197			965			818
Operating, maintenance and general	340			105			373			345
Depreciation and amortization	179			49			204			196
Taxes, other than on income and revenues	37			11			42			43
Total operating expenses	1,077			362			1,584			1,402
OPERATING INCOME	186			81			413			387
OTHER INCOME (EXPENSE):
Interest expense	(131		)	(50		)	(218		)	(216		)
Earnings (losses) from unconsolidated investments	(7		)	16			99			105
Other, net	2			(2		)	—			2
Total other expenses, net	(136		)	(36		)	(119		)	(109		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	50			45			294			278
Income tax expense from continuing operations	39			12			80			80
INCOME FROM CONTINUING OPERATIONS	11			33			214			198
Income from discontinued operations	28			17			41			27
NET INCOME	$	39		$	50		$	255		$	225

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

F-7

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in millions)

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Years Ended December 31,
							2011			2010
Net income	$	39		$	50		$	255		$	225
Other comprehensive income (loss), net of tax:
Change in fair value of interest rate hedges	—			4			(46		)	(8		)
Reclassification of unrealized loss on interest rate hedges into earnings	—			5			13			13
Change in fair value of commodity hedges	(4		)	3			5			25
Reclassification of unrealized (gain) loss on commodity hedges into earnings	1			(1		)	(15		)	(12		)
Actuarial loss relating to pension and other postretirement benefits	(22		)	—			(39		)	(5		)
Reclassification of net actuarial loss and prior service credit relating to pension and other postretirement benefits into earnings	—			1			3			3
	(25		)	12			(79		)	16
Comprehensive income	$	14		$	62		$	176		$	241

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

F-8

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Dollars in millions)

	Common Stock		Premium on Capital Stock		Treasury Stock, at cost			Common Stock Held In Trust			Other			AOCI			Retained Earnings  (Accumulated Deficit)			Total Stockholders’ Equity
Predecessor
Balance, December 31, 2009	$	126	$	1,905	$	(29	)	$	(12	)	$	127		$	(56	)	$	410		$	2,471
Other comprehensive income, net of tax	—		—		—			—			—			16			—			16
Preferred stock dividends	—		—		—			—			—			—			(5		)	(5		)
Dividends paid on common stock	—		—		—			—			—			—			(75		)	(75		)
Share–based compensation	—		9		—			—			—			—			—			9
Restricted stock issuances	—		1		(2		)	—			—			—			—			(1		)
Exercise of stock options	—		2		—			—			—			—			—			2
Redemption of preferred stock	—		4		—			—			(115		)	—			(4		)	(115		)
Contributions to Trust	—		—		—			(1		)	1			—			—			—
Disbursements from Trust	—		—		—			2			(2		)	—			—			—
Net income	—		—		—			—			—			—			225			225
Balance, December 31, 2010	126		1,921		(31		)	(11		)	11			(40		)	551			2,527
Other comprehensive loss, net of tax	—		—		—			—			—			(79		)	—			(79		)
Dividends paid on common stock	—		—		—			—			—			—			(74		)	(74		)
Share–based compensation	—		10		—			—			—			—			—			10
Restricted stock issuances	—		1		(2		)	—			—			—			—			(1		)
Exercise of stock options	—		2		—			—			—			—			—			2
Contributions to Trust	—		—		—			(1		)	1			—			—			—
Disbursements from Trust	—		—		—			1			(1		)	—			—			—
Net income	—		—		—			—			—			—			255			255
Balance, December 31, 2011	126		1,934		(33		)	(11		)	11			(119		)	732			2,640
Other comprehensive income, net of tax	—		—		—			—			—			12			—			12
Share–based compensation	—		2		—			—			—			—			—			2
Restricted stock issuances	—		—		(3		)	—			—			—			—			(3		)
Contributions to Trust	—		—		—			(1		)	1			—			—			—
Disbursements from Trust	—		—		—			1			(1		)	—			—			—
Purchase of treasury stock	—		—		(1,450		)	—			—			—			—			(1,450		)
Net income	—		—		—			—			—			—			50			50
Balance, March 25, 2012	$	126	$	1,936	$	(1,486	)	$	(11	)	$	11		$	(107	)	$	782		$	1,251
Successor
Balance, March 26, 2012	$	—	$	3,913	$	—		$	—		$	—		$	—		$	—		$	3,913
Other comprehensive loss, net of tax	—		—		—			—			—			(25		)	—			(25		)
Capital contribution	—		166		—			—			—			—			—			166
Dividends paid on common stock	—		—		—			—			—			—			(65		)	(65		)
Net income	—		—		—			—			—			—			39			39
Balance, December 31, 2012	$	—	$	4,079	$	—		$	—		$	—		$	(25	)	$	(26	)	$	4,028

The Company’s common stock is $1 par value in the predecessor period. Therefore, the change in Common Stock, $1 par value, was equivalent to the change in the number of shares of common stock issued.

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

F-9

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Years Ended December 31,
							2011			2010
CASH FLOWS FROM OPERATING ACTIVITES:
Net income	$	39		$	50		$	255		$	225
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization (including discontinued operations)	206			57			238			229
Deferred income taxes	90			23			104			107
Provision for bad debts	3			1			8			9
Amortization of costs charged to interest	(25		)	1			—			—
Net gain on curtailment of OPEB plans	(15		)	—			—			—
Unrealized loss on derivatives	12			—			—			19
Loss on asset sales or dispositions	—			—			2			2
Share–based compensation expense	—			2			10			9
(Earnings) losses from unconsolidated investments, net of cash distributions	7			(16		)	(96		)	(102		)
Changes in operating assets and liabilities, net of Merger impact	(165		)	79			10			(73		)
Net cash flows provided by operating activities	152			197			531			425
CASH FLOWS FROM INVESTING ACTIVITES:
Additions to property, plant and equipment	(238		)	(60		)	(290		)	(293		)
Contributions to unconsolidated investments	—			—			—			(100		)
Loan to unconsolidated investments	—			—			(72		)	—
Loan repayment from unconsolidated investments	—			37			35			—
Distributions from unconsolidated affiliates in excess of cumulative earnings	6			—			—			—
Proceeds from Citrus Merger	—			1,895			—			—
Plant retirements and other	(1		)	(2		)	(1		)	1
Net cash flows provided by (used in) investing activities	(233		)	1,870			(328		)	(392		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of long-term debt	—			455			—			101
Capital contribution from ETE	166			—			—			—
Dividends paid on common stock	(65		)	(19		)	(74		)	(75		)
Note payable - related party	55			—			—			—
Payments on note payable - related party	(55		)	—			—			—
Dividends paid on preferred stock	—			—			—			(7		)
Extinguishment of preferred stock	—			—			—			(115		)
Repayment of long-term debt	—			(1,048		)	(19		)	(141		)
Net change in revolving credit facilities	(2		)	12			(97		)	217
Purchase of treasury stock	—			(1,453		)	—			—
Other	(6		)	(1		)	8			(21		)
Net cash flows provided by (used in) financing activities	93			(2,054		)	(182		)	(41		)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	12			13			21			(8		)
CASH AND CASH EQUIVALENTS, beginning of period	37			24			3			11
CASH AND CASH EQUIVALENTS, end of period	$	49		$	37		$	24		$	3

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

F-10

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Tabular dollar amounts are in millions)

1. OPERATIONS AND ORGANIZATION:

The Company was incorporated under the laws of the State of Delaware in 1932. Southern Union owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the gathering, treating, processing, transportation, storage and distribution of natural gas in the United States.  The Company operates in three reportable segments as follows:  

• Transportation and Storage — The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas, and also provides LNG terminalling and regasification services.  Through Panhandle, the Company owns and operates approximately 10,000 miles of interstate pipelines that transport up to 6.4 Bcf/d of natural gas from the Gulf of Mexico, South Texas and the Panhandle regions of Texas and Oklahoma to major U.S. markets in the Midwest and Great Lakes regions.  Panhandle also owns and operates an LNG import terminal located on Louisiana’s Gulf Coast.

• Gathering and Processing — The Gathering and Processing segment is primarily engaged in connecting wells of natural gas producers to its gathering system, treating natural gas to remove impurities to meet pipeline quality specifications, processing natural gas for the removal of NGL, and redelivering natural gas and NGL to a variety of markets.  Through SUGS, the Company owns approximately 5,700 miles of natural gas and NGL pipelines, 6 processing plants with a combined capacity of 510 MMcf/d and 7 natural gas treating plants with combined capacities of 630 MMcf/d. As discussed in Note 3, on February 27, 2013, Southern Union expects to contribute SUGS and its parent company to Regency during the second quarter of 2013.

• Distribution — The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts.  Through Southern Union’s regulated utility operations, Missouri Gas Energy and New England Gas Company, the Company serves natural gas end-user customers in Missouri and Massachusetts, respectively.  On December 17, 2012, Southern Union and The Laclede Group, Inc. entered into definitive purchase and sale agreements dated December 14, 2012 with Laclede Missouri and Laclede Massachusetts, both of which are subsidiaries of Laclede Gas Company, Inc., pursuant to which Laclede Missouri has agreed to acquire the assets of Southern Union’s Missouri Gas Energy division, and Laclede Massachusetts has agreed to acquire the assets of Southern Union’s New England Gas Company division (together, the LDC Disposal Group) for approximately $1.035 billion, subject to customary closing adjustments.  On February 11, 2013, The Laclede Group, Inc. announced that it had entered into an agreement with Algonquin Power & Utilities Corp (APUC) that will allow a subsidiary of APUC to assume the rights of The Laclede Group, Inc. to purchase the assets of New England Gas Company, subject to certain approvals.  It is expected that the transactions contemplated by the purchase and sale agreements will close by the end of the third quarter of 2013.  For the periods from March 26, 2012 to December 31, 2012 and January 1, 2012 to March 25, 2012, and for the years ended December 31, 2011 and 2010, the results of continuing operations of the LDC Disposal Group have been reclassified to income from discontinued operations and the prior period amounts have been restated to present the LDC Disposal Group’s operations as discontinued operations in the consolidated statements of operations.  The LDC Disposal Group’s assets and liabilities have been reclassified and reported as assets and liabilities held for sale as of December 31, 2012.

See Note 3 for information related to the Company’s merger with ETE and the completion of the Holdco Transaction.

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.

Principles of Consolidation.  The consolidated financial statements include the accounts of Southern Union and its wholly-owned subsidiaries.  Investments in which the Company has significant influence over the operations of the investee are accounted for using the equity method.  All significant intercompany accounts and transactions are eliminated in consolidation.

Business Combination Accounting. The Company’s March 26, 2012 merger transaction with ETE was accounted for by ETE using business combination accounting.  Under this method, the purchase price paid by the acquirer is allocated to the assets acquired and liabilities assumed as of the acquisition date based on their fair value.  By the application of “push-down” accounting, Southern Union’s assets, liabilities and equity were accordingly adjusted to fair value on March 26,

F-11

2012.  Determining the fair value of certain assets and liabilities assumed is judgmental in nature and often involves the use of significant estimates and assumptions.  See Note 3 for a discussion of the estimated fair values of assets and liabilities recorded in connection with the ETE Merger.

Due to the application of “push-down” accounting, the Company’s financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting.  Periods prior to March 26, 2012 are identified herein as “Predecessor,” while periods subsequent to the ETE Merger are identified as “Successor.”

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.

Property, Plant and Equipment. 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 (more fully described below in the Interest Cost Capitalized accounting policies disclosure) 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.

When ordinary retirements of property, plant and equipment occur within the Company’s regulated Transportation and Storage and Distribution segments, 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.

When property, plant and equipment is retired within the Company’s Gathering and Processing segment, or within its other non-regulated operations, the original cost less salvage value and accumulated depreciation and amortization balances are removed, with any resulting gain or loss recorded in earnings.

Depreciation.  The Company computes depreciation expense using the straight-line method.  Depreciation rates for the Company’s Distribution segment are approved by the applicable regulatory commissions.

Interest Cost Capitalized.  The Company capitalizes interest on certain qualifying assets that are undergoing activities to prepare them for their intended use.  Interest costs incurred during the construction period are capitalized and amortized over the life of the assets. 

For additional information, see Note 13.

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 not amortized, but instead is tested for impairment at the Company’s reporting unit level at least annually as of November 30 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.  No goodwill impairments were recorded for the periods presented in these consolidated financial statements.

Cash and Cash Equivalents and Supplemental Cash Flow Information.  Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have original maturities of three months or less.

Under the Company’s cash management system, checks issued but not presented to banks frequently result in book overdraft balances for accounting purposes and are classified in accounts payable in the consolidated balance sheets.  At December 31, 2012 and 2011, such book overdraft balances classified in accounts payable were approximately$28 million and $21 million, respectively.

F-12

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

	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011			2010
SUPPLEMENTAL CASH FLOW INFORMATION:
Accrued capital expenditures	$	101	$	9	$	23		$	10
Cash paid for interest, net of interest capitalized	132		39		214			212
Cash received for income taxes	—		—		(11		)	(20		)

Related Party Transactions. Related party receivables and payables primarily include payments for payroll funding and other various administrative and operating costs paid on behalf of or by affiliates.  See Note 5 for additional information on related party transactions.

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.

Segment Reporting.  The Company reports its operations under three reportable segments: the Transportation and Storage segment, the Gathering and Processing segment and the Distribution segment.  See Note 18 for additional related information.

Transportation and Storage Segment Revenues.  Revenues from transportation and storage of natural gas and LNG terminalling 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 Panhandle 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.

Gathering and Processing Segment Revenues and Cost of Sales Recognition.  The business operations of the Gathering and Processing segment consist of connecting wells of natural gas producers to the Company’s gathering system, treating natural gas to remove impurities, processing natural gas for the removal of NGL and then redelivering or marketing the treated natural gas and/or processed NGL to third parties.  The terms and conditions of purchase arrangements with producers, including those limited arrangements with the same counterparty, offer various alternatives with respect to taking title to the purchased natural gas and/or NGL.  These arrangements include (i) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing in the Company’s plant facilities and (ii) making other direct purchase of natural gas and/or NGL at specified delivery points to meet operational or marketing obligations.  Cost of sales primarily includes the cost of purchased natural gas and/or NGL to which the Company has taken title.  Operating revenues derived from the sale of natural gas and/or NGL are recognized in the period in which the physical product is delivered to the customer and title is transferred.  Operating revenues derived from fees charged to producers are recognized in the period in which the service is provided.  Operating revenues and cost of sales within the Gathering and Processing segment are reported on a gross basis.

Natural Gas Distribution Segment Revenues and Natural Gas Purchase Costs.   In the Distribution segment, natural gas utility customers are billed on a monthly-cycle basis.  The related cost of natural gas and revenue taxes are matched with cycle-billed revenues through utilization of purchased natural gas adjustment provisions in tariffs approved by the regulatory agencies having jurisdiction.  Revenues from natural gas delivered but not yet billed are accrued, along with the related natural gas purchase costs and revenue-related taxes.

F-13

Accounts Receivable and Allowance for Doubtful Accounts. The Company manages trade credit risks to minimize exposure to uncollectible trade receivables.  In the Transportation and Storage and Gathering and Processing segments, prospective and existing customers are reviewed for creditworthiness based upon pre-established standards.  Customers that do not meet minimum standards are required to provide additional credit support.  In the Distribution segment, concentrations of credit risk in trade receivables are limited due to the large customer base with relatively small individual account balances.  Additionally, the Company requires a deposit from customers in the Distribution segment who lack a credit history or whose credit rating is substandard. The Company utilizes the allowance method for recording its allowance for uncollectible accounts, which is primarily based on the application of historical bad debt percentages applied against its aged accounts receivable.  Increases in the allowance are recorded as a component of operating expenses; reductions in the allowance are recorded when receivables are subsequently collected or written off.  Past due receivable balances are written-off when the Company’s efforts have been unsuccessful in collecting the amount due.

The following table presents the balance in the allowance for doubtful accounts and activity for the periods presented.

	Years Ended December 31,
	2011			2010
Beginning balance	$	3		$	2
Additions: charged to cost and expenses	8			9
Deductions: write-off of uncollectible accounts	(11		)	(8		)
Other	2			—
Ending balance	$	2		$	3

Amounts related to the allowance for doubtful accounts were not material as of and during the year ended December 31, 2012.

Accumulated Other Comprehensive Loss.  The main components of comprehensive loss that relate to the Company are net earnings, unrealized gain (loss) on hedging activities and unrealized actuarial gain (loss) and prior service credits (cost) on pension and other postretirement benefit plans.  For more information, see Note 7.

Stock-Based Compensation. The Company measures all employee stock-based compensation using a fair value method and records the related expense in the consolidated statement of operations. For more information, see Note 15.

Inventories.  In the Transportation and Storage segment, inventories 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 12 months is reflected in non-current assets.

In the Gathering and Processing segment, inventories consist of non-fractionated Y-grade NGL and materials and supplies, both of which are stated at the lower of weighted average cost or market.  Materials and supplies are primarily comprised of compressor components and parts.

In the Distribution segment, inventories consist of natural gas in underground storage and materials and supplies.  The natural gas in underground storage inventory carrying value is stated at weighted average cost and is not adjusted to a lower market value because, pursuant to purchased natural gas adjustment clauses, actual natural gas costs are recovered in customers’ rates.  Materials and supplies inventory is also stated at weighted average cost.

F-14

The following table sets forth the components of inventory at the dates indicated.

	Transportation & Storage		Gathering & Processing		Distribution (3)		Total
December 31, 2012
Current
Natural gas (1)	$	124	$	—	$	—	$	124
Materials and supplies	20		9		—		29
NGL (2)	—		10		—		10
	$	144	$	19	$	—	$	163
December 31, 2011
Current
Natural gas (1)	$	96	$	—	$	62	$	158
Materials and Supplies	19		12		5		36
NGL (2)	—		10		—		10
Total Current	115		22		67		204
Non-Current
Natural gas (1)	3		—		—		3
	$	118	$	22	$	67	$	207

⁽¹⁾  Natural gas volumes held for operations in the Transportation and Storage segment at December 31, 2012 and 2011 were 34,891,000 MMBtu and 29,718,000 MMBtu, respectively.  Natural gas volumes held for operations in the Distribution segment, with the LDC Disposal Group, at December 31, 2012 and 2011 were 12,875,000 MMBtu and 14,191,000 MMBtu, respectively.

⁽²⁾  NGL volumes at December 31, 2012 and 2011 were 15,882,000 gallons and 12,061,000 gallons, respectively.

⁽³⁾  Inventory held by the Distribution segment has been included in current assets held for sale at December 31, 2012. See Note 3 for further information.

Unconsolidated Investments.  Unconsolidated Investments over which the Company may exercise significant influence, generally 20% to 50% ownership interests, 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. See Note 6 for further information.

Regulatory Assets and Liabilities.  The Company is subject to regulation by certain state and federal authorities.  In its Distribution segment, the Company’s accounting policies are in accordance with the accounting requirements and ratemaking practices of the applicable regulatory authorities.  These accounting policies allow the Company to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statements of operations by an unregulated company.  These deferred assets and liabilities then flow through the results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers.  Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders.  If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheets and included in the consolidated statements of operations for the period in which the discontinuance of regulatory accounting treatment occurs.  See Note 4.

F-15

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’s Level 1 instruments primarily consist of trading securities related to a non-qualified deferred compensation plan that are valued based on active market quotes.  The Company’s Level 2 instruments include commodity derivative instruments, such as natural gas and NGL processing spread swap derivatives, fixed-price forward sales contracts and certain natural gas basis swaps, and interest-rate swap derivatives that are valued based on pricing models where significant inputs are observable.  The Company did not have any Level 3 instruments at December 31, 2012 and 2011.

See Notes 12 and 9 for additional information regarding the assets and liabilities of the Company measured on a recurring and nonrecurring basis, respectively.

Natural Gas Imbalances.  In the Transportation and Storage and Gathering and Processing segments, natural gas imbalances occur as a result of differences in volumes of natural gas received and delivered. In the Transportation and Storage segment, 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.

In the Gathering and Processing segment, the Company records natural gas imbalances as receivables and payables in which imbalances due from a pipeline are recorded at the lower of cost or market and imbalances due to a pipeline are recorded at market.  Market prices are based upon Gas Daily indexes.

Fuel Tracker.  The fuel tracker applicable to the Company’s Transportation and Storage segment 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 Panhandle 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.

F-16

Derivative Instruments and Hedging Activities.  All derivatives are recognized on the consolidated balance sheets 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 loss 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.  See Note 11 and Note 12 for additional related information.

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.

For more information, see Note 17.

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.

Upon completion of the Holdco transaction on October 5, 2012 (See Note 3), the Company became a member of a new federal consolidated tax return filing group of which Holdco is the parent company. Generally, the Company's tax liability is equal to the liability the Company would have incurred if the Company were a taxpayer filing separately from Holdco. However, the Company will realize a current benefit attributable to a net operating loss or credit that may be utilized in the Holdco consolidated tax returns that otherwise would not have been realized by the Company filing separate from Holdco.

The Company will enter into a tax sharing agreement with Holdco pursuant to which the Company will be required to make payments to Holdco in order to reimburse Holdco for federal and state taxes that it pays on the Company's income, or to receive payments from Holdco to the extent that tax losses or credits generated by the Company are utilized by Holdco.

See Note 3 for a description of the Holdco transaction.

Pensions and Other Postretirement Benefit Plans. 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

F-17

and each underfunded plan is recognized as a liability.   Employers must recognize the change in the funded status of the plan in the year in which the change occurs through accumulated other comprehensive loss in stockholders’ equity.

See Note 9 for additional related information.

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.  For further discussion of the Company’s commitments and contingencies, see Note 14.

3. ETE MERGER AND OTHER TRANSACTIONS:

Description of Merger

On March 26, 2012, the Company, ETE, and Sigma Acquisition Corporation, a wholly-owned subsidiary of ETE (Merger Sub), completed their previously announced merger transaction.  Pursuant to the Second Amended and Restated Agreement and Plan of Merger, dated as of July 19, 2011, as amended by Amendment No. 1 thereto dated as of September 14, 2011 (as amended, the Merger Agreement), among the Company, ETE and Merger Sub, Merger Sub was merged with and into the Company, with the Company continuing as the surviving corporation as an indirect, wholly-owned subsidiary of ETE (the Merger).  The Merger became effective on March 26, 2012 at 12:59 p.m., Eastern Time (the Effective Time).

At the Effective Time, each share of the Company’s common stock, par value $1.00 per share issued and outstanding (Southern Union Common Stock), immediately prior to the Effective Time (other than shares of Southern Union Common Stock held by stockholders properly exercising appraisal rights available under Section 262 of the DGCL or shares of Southern Union Common Stock held directly or indirectly by the Company or any of its wholly-owned subsidiaries immediately prior to the Effective Time) was converted into the right to receive, as consideration for the Merger (the Merger Consideration), at the election of the holder of such share, either (i) $44.25 in cash (the Cash Consideration) or (ii) 1.00x ETE common unit (the Equity Consideration).

Under the terms of the Merger Agreement, Southern Union stockholders made an election to exchange each outstanding share of Southern Union Common Stock for $44.25 of cash or 1.00x ETE common unit, with no more than 60% of the aggregate Merger Consideration payable in cash and no more than 50% of the aggregate Merger Consideration payable in ETE common units.  Based on the final election results, the Merger Consideration was paid as follows:

• Holders of approximately 54% of outstanding Southern Union Common Stock, or 67,985,929 Southern Union shares, elected and received cash.

• Holders of approximately 46% of outstanding Southern Union Common Stock, or 56,981,860 Southern Union shares, received ETE common units.  This amount is comprised of 38,872,598 Southern Union shares for which holders elected to receive ETE common units and 18,109,262 Southern Union shares for which holders either did not make an election (other than dissenting shares), did not deliver a valid election form prior to the election deadline or did not properly deliver shares of Southern Union Common Stock for which elections were made pursuant to the notice of guaranteed delivery procedure and, therefore, were deemed to have elected to receive ETE common units.

In connection with the consummation of the Merger, on March 27, 2012, the New York Stock Exchange (NYSE) filed a notification of removal from listing with the SEC to delist the Southern Union Common Stock from the NYSE.  In addition, the Company filed with the SEC a certification and notice of termination requesting that the Southern Union Common Stock be deregistered under Section 12(b) of the Securities Exchange Act of 1934, as amended.

Pursuant to the Third Amended and Restated Company 2003 Stock and Incentive Plan (Equity Plan), individual award agreements thereunder and the terms of the Merger Agreement, all awards of stock options and stock appreciation rights outstanding immediately, to the extent not already vested, became vested and exercisable prior to the Effective Time, in accordance with the terms of the Equity Plan.  All unexercised options and stock appreciation rights, including those for which vesting was accelerated, outstanding immediately prior to the Effective Time were cancelled and terminated at the Effective Time.  In consideration of such cancellation and termination, each stock option and stock appreciation right so cancelled and terminated was converted into the right to receive an amount in cash equal to $44.25 less (i) the applicable exercise price and (ii) any applicable deductions and withholdings required by law.

Additionally, shares of restricted stock for which restrictions have not otherwise lapsed or expired and were outstanding prior to the Effective Time had their associated restrictions automatically and without an action by the holder lapse/expire prior to the Effective Time, and each share of Southern Union Common Stock subject to such restricted stock grant was issued and

F-18

converted into the right to receive Merger Consideration (in the form of Cash Consideration or Equity Consideration at the election of the holder of such restricted stock grant), less all deductions and withholdings required by law.  Each holder of the outstanding restricted stock grant made an election of Equity Consideration and the applicable deduction was made by reducing the number of ETE common units otherwise payable as part of the consideration for such restricted stock (with the ETE common units valued at the closing price of ETE on the day prior to the closing of the Merger for this purpose).

Restrictions on each awards of cash restricted stock units (RSU) outstanding immediately prior to the Effective Time expired and each RSU was converted into the right to receive a lump sum cash payment equal to (i) $44.25 multiplied by the total number of shares of Southern Union Common Stock underlying such RSU, less (ii) any applicable deductions and withholdings required by law.

The vesting of the equity-based awards, as described above, occurred as required under the change in control provisions of the Equity Plan.  The total remaining unrecognized compensation costs of $25 million associated with such vested awards was not recorded in either of the predecessor or successor periods reflected herein. The total of $137 million and 178,851 ETE Common Units issued to the holders of the awards in connection with the vesting was accounted for as consideration transferred in the Merger.

In connection with, and immediately prior to the Effective Time of the Merger, CrossCountry Energy, an indirect wholly-owned subsidiary of the Company, ETP, ETP Merger Sub, Citrus ETP Finance LLC, ETE, PEPL Holdings, a newly created indirect wholly-owned subsidiary of the Company, and the Company consummated the transactions contemplated by the Citrus Merger Agreement that certain Amended and Restated Agreement and Plan of Merger, dated as of July 19, 2011, as amended by Amendment No. 1 thereto dated as of September 14, 2011 and Amendment No. 2 thereto dated as of March 23, 2012 (as amended, the Citrus Merger Agreement) by and among ETP, ETP Merger Sub and Citrus ETP Finance LLC, on the one hand, and ETE, CrossCountry Energy, PEPL Holdings and the Company, on the other hand.

Immediately prior to the Effective Time, the Company, CrossCountry Energy and PEPL Holdings became parties to the Citrus Merger Agreement by joinder to, and the Company assumed the obligations and rights of ETE thereunder.  The Company made certain customary representations, warranties, covenants and indemnities in the Citrus Merger Agreement.  Pursuant to the Citrus Merger Agreement, ETP Merger Sub was merged with and into CrossCountry Energy (the Citrus Merger), with CrossCountry Energy continuing as the surviving entity in the Citrus Merger as a wholly-owned subsidiary of ETP and, as a result thereof, ETP, through its subsidiaries, indirectly owns 50% of the outstanding capital stock of Citrus.  As consideration for the Citrus Merger, Southern Union received from ETP $2.0 billion, consisting of $1.90 billion in cash and $105 million of common units representing limited partner interests in ETP.

Immediately prior to the Effective Time, $1.45 billion of the total cash consideration received in respect of the Citrus Merger was contributed to Merger Sub in exchange for an equity interest in Merger Sub.  In connection with the Merger, at the Effective Time, such equity interest in Merger Sub held by CCE Holdings, LLC (CCE Holdings) was cancelled and retired.

Pursuant to the Citrus Merger Agreement, immediately prior to the Effective Time, (i) the Company contributed its ownership interests in Panhandle Eastern Pipe Line Company, LP and Southern Union Panhandle, LLC to PEPL Holdings (the Panhandle Contribution); and (ii) following the Panhandle Contribution, the Company entered into a contingent residual support agreement with ETP and Citrus ETP Finance LLC, pursuant to which the Company agreed to provide 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.

Expenses Related to the Merger

Merger-related expenses were $77 million and $19 million in the successor and predecessor periods in 2012, respectively.  Such expenses include legal and other outside service costs, charges resulting from employment agreements with certain executives that provided for compensation when their employment was terminated and severance costs associated with administrative headcount reductions.  These expenses were included in operating, maintenance, and general expenses in the consolidated statement of operations.

F-19

Allocation of Consideration Transferred

The Merger was accounted for using business combination accounting under applicable accounting principles.  Business combination accounting requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date.  The table below represents the allocation of the total consideration to Southern Union’s tangible and intangible assets and liabilities as of March 26, 2012 based upon management’s estimate of their respective fair values.  Certain amounts included in the purchase price allocation as of December 31, 2012 have been changed from amounts previously reflected based on management’s review of the valuation.

Cash and cash equivalents	$	37
Other current assets	519
Property and equipment	6,242
Goodwill	2,497
Identified intangibles (1)	55
Other noncurrent assets	290
Long-term debt, including current portion	(3,334		)
Deferred income taxes	(1,419		)
Other liabilities	(974		)
Total purchase price	$	3,913

⁽¹⁾ Identified intangibles will be amortized over an estimated life of approximately 17.5 years and are included in deferred charges in the consolidated balance sheet.

The goodwill resulting from the Merger was primarily due to expected commercial and operational synergies and is not deductible for tax purposes.  Goodwill was allocated by reportable business segment as presented in the table below.

Transportation & Storage	$	1,785
Gathering & Processing	338
Distribution	133
Corporate & Other	241
Total Goodwill	$	2,497

Holdco Transaction

On October 5, 2012, ETE and ETP completed the Holdco Transaction, immediately following the closing of ETP’s acquisition of Sunoco whereby, (i) ETE contributed its interest in Southern Union into an ETP-controlled entity, in exchange for a 60% equity interest in the new entity, Holdco, and (ii) ETP contributed its interest in Sunoco to Holdco and retained a 40% equity interest in Holdco.  Pursuant to a stockholders agreement between ETE and ETP, ETP controls Holdco.  This transaction did not result in a new basis of accounting for Southern Union.

SUGS Contribution

On February 27, 2013, the Company entered into a definitive contribution agreement to contribute to Regency all of the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS. The consideration to be paid by Regency in connection with this transaction will consist of (i) the issuance of 31,372,419 Regency common units to the Company, (ii) the issuance of 6,274,483 Regency Class F units to the Company, (iii) the distribution of $570 million in cash to the Company, and (iv) the payment of $30 million in cash to a subsidiary of ETP. The Regency Class F units will have the same rights, terms and conditions as the Regency common units, except that Southern Union will not receive distributions on the Regency Class F units for the first eight consecutive quarters following the closing, and the Regency Class F units will thereafter automatically convert into Regency common units on a one-for-one basis. The transaction is expected to close in the second quarter of 2013. The Company has not presented SUGS as discontinued operations due to the expected continuing involvement with SUGS through affiliate relationships, as well as the direct investment in Regency that will be received as consideration.

F-20

Discontinued Operations

In December 2012, we entered into a purchase and sale agreement with the Laclede Entities, pursuant to which Laclede Missouri has agreed to acquire the assets of the Missouri Gas Energy division and Laclede Massachusetts has agreed to acquire the assets of the New England Gas Company division (together, the LDC Disposal Group) for approximately $1.035 billion, subject to customary closing adjustments.  On February 11, 2013, The Laclede Group, Inc. announced that it had entered into an agreement with Algonquin Power & Utilities Corp (APUC) that will allow a subsidiary of APUC to assume the rights of The Laclede Group, Inc. to purchase the assets of New England Gas Company, subject to certain approvals.  It is expected that the transactions contemplated by the purchase and sale agreements will close by the end of the third quarter of 2013.  All periods reflected herein have been restated to present the LDC Disposal Group’s operations as discontinued operations in the consolidated statements of operations.  The LDC Disposal Group’s assets and liabilities have been reclassified and reported as assets and liabilities held for sale as of December 31, 2012.

Summarized financial information for Southern Union’s LDC Disposal Group is as follows:

	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011		2010
Revenue from discontinued operations	$	324	$	190	$	669	$	701
Net income of discontinued operations, excluding effect of taxes and overhead allocations	43		27		64		72

The goodwill allocated to the LDC Disposal Group was $133 million at December 31, 2012.

Additionally, the Company recorded a loss from discontinued operations of $18 million in 2010 related to the First Circuit Court of Appeals’ decision on the Mercury Release litigation with New England Gas Company.  See further discussion at Note 14.

4. REGULATORY ASSETS:

The Company records regulatory assets with respect to its Distribution segment operations, which have been classified as discontinued operations as of December 31, 2012. See Note 3.  Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply regulatory accounting policies in accounting for its operations.  In 1999, prior to its acquisition by Southern Union, Panhandle discontinued the application of regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.

At December 31, 2012, the Company had $123 million of regulatory assets included in the consolidate balance sheet as non-current assets held for sale. At December 31, 2011, the company had $57 million in regulatory assets, $37 million of which are being recovered through current rates.

F-21

5. RELATED PARTY TRANSACTIONS:

The following table provides a summary of the related party balances included in our consolidated balance sheets at the dates indicated:

	Successor		Predecessor
	December 31, 2012		December 31, 2011
Investment in ETP (1)	$	99	$	—
Accounts receivable from related companies	72		10
Accounts payable from related companies	110		—

⁽¹⁾ The Company received $6 million in distributions related to our investment in ETP during 2012.

Accounts receivable from related companies reflected above are primarily related to payroll funding and various administrative and operating costs paid by the Company on behalf of affiliates. Accounts payable from related companies are primarily related to various administrative and operating costs paid by affiliates on behalf of the Company.

The following table provides a summary of the related party activity included in our consolidated statements of operations. Prior period amounts were not included as they were immaterial.

	Successor
	Period from Acquisition (March 26, 2012) to December 31, 2012
Operating revenues — ETE	$	29
Cost of natural gas and other energy	21
Operating, maintenance and general	125
Interest expense	3
Losses from unconsolidated investments	(7		)

6. UNCONSOLIDATED INVESTMENTS:

As discussed in Note 3, the Company received $105 million of ETP common units as consideration for the Citrus Merger. Other unconsolidated investments are not significant in the successor period. Therefore, no amounts have been presented below for 2012.

Unconsolidated investments at December 31, 2011 and 2010 included the Company’s 50% investment in Citrus, which investment was merged into a subsidiary of ETP on March 26, 2012, as described in Note 3. Unconsolidated investments also include investments in other entities. The Company accounted for these investments using the equity method.  The Company’s share of net earnings or loss from these equity investments was recorded in earnings from unconsolidated investments in the consolidated statement of operations.

The following table summarizes the Company’s unconsolidated equity investments at the dates indicated.

	December 31, 2011
Citrus (1)	$	1,608
Other	25
	$	1,633

(1)See Note 3 for information regarding the Citrus Merger, pursuant to which CrossCountry Energy, a subsidiary of the Company that indirectly owns a 50% interest in Citrus, became a wholly-owned subsidiary of ETP.

F-22

The following tables set forth the summarized financial information for the Company’s equity investments for the periods presented.

	December 31, 2011
	Citrus		Other Equity Investments
Balance Sheet Data:
Current assets	$	261	$	8
Non-current assets	5,815		43
Current liabilities (1)	848		1
Non-current liabilities	3,310		—

⁽¹⁾  The current portion of Citrus long-term debt at December 31, 2011 was $687 million.

	Years Ended December 31,
	2011				2010
	Citrus		Other Equity Investments		Citrus		Other Equity Investments
Statement of Operations Data:
Revenues	$	694	$	10	$	517	$	22
Operating income	392		3		270		12
Net earnings	185		3		181		12

Citrus

Dividends.  Citrus did not pay dividends to the Company during the years ended December 31, 2011 and 2010.  Retained earnings at December 31, 2011 and 2010 included undistributed earnings from Citrus of $279 million and $181 million, respectively.

Citrus Excess Net Investment.  The Company’s equity investment balances included amounts in excess of the Company’s share of the underlying equity of the investee of $650 million and $649 million as of December 31, 2011 and 2010, respectively.  These amounts related to the Company’s 50% equity ownership interest in Citrus.  The following table sets forth the excess net investment of the Company’s 50% share of the underlying Citrus equity as of December 31, 2011.

	Excess Purchase Costs			Amortization Period
Property, plant and equipment	$	3		40 years
Capitalized software	1			5 years
Long-term debt (1)	(80		)	4-20 years
Deferred taxes (1)	(7		)	40 years
Goodwill (2)	665			N/A
Sub-total	582
Accumulated, net accretion to equity earnings	68
Net investment in excess of underlying equity	$	650

⁽¹⁾  Accretion of this amount increases equity earnings and accumulated net accretion.

⁽²⁾  The Company’s tax basis in the investment in Citrus includes equity goodwill.

F-23

Other Equity Investments

The Company has other investments in Grey Ranch, the Lee 8 partnership and PEI Power, which are also accounted for under the equity method.  Grey Ranch operates a 200 MMcf/d carbon dioxide treatment facility.  The Lee 8 partnership operates a 3.0 Bcf natural gas storage facility in Michigan.  PEI Power II owns a 45-megawatt natural gas-fired electric generation plant operated through a joint venture with Cayuga Energy in Pennsylvania.

We recorded an impairment of $8 million related to our investment in Grey Ranch during the period from March 26, 2012 to December 31, 2012.

7. COMPREHENSIVE INCOME (LOSS):

The tables below set forth the tax amounts included in the respective components of other comprehensive income (loss) for the periods presented:

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Years Ended December 31,
							2011			2010
Income taxes included in other comprehensive income (loss):
Change in fair value of interest rate hedges	$	—		$	2		$	(28	)	$	(5	)
Reclassification of unrealized loss on interest rate hedges into earnings	—			3			9			9
Change in fair value of commodity hedges	(2		)	2			3			14
Reclassification of unrealized gain on commodity hedges into earnings	—			(1		)	(9		)	(7		)
Actuarial loss relating to pension and other postretirement benefits	(13		)	—			(24		)	(4		)
Reclassification of net actuarial loss and prior service credit relating to pension and other postretirement benefits into earnings	—			1			2			2
Total	$	(15	)	$	7		$	(47	)	$	9

The table below presents the components in accumulated other comprehensive income (loss), net of tax, as of the dates indicated:

	Successor			Predecessor
	December 31, 2012			December 31, 2011
Interest rate hedges	$	—		$	(50	)
Commodity hedges	(3		)	—
Benefit plans:
Net actuarial loss and prior service costs — pensions	(11		)	(52		)
Net actuarial gain and prior service credit — OPEB	(11		)	(14		)
Equity investments	—			(3		)
Total accumulated other comprehensive loss, net of tax	$	(25	)	$	(119	)

F-24

8. DEBT OBLIGATIONS:

The following table sets forth the debt obligations of Southern Union and Panhandle at the dates indicated:

	Successor		Predecessor
	December 31, 2012		December 31, 2011
Southern Union Credit Facility	$	210	$	200
Southern Union:
7.60% Senior Notes due 2024	360		360
8.25% Senior Notes due 2029	300		300
7.24% to 9.44% First Mortgage Bonds due 2020 to 2027	—		20
7.20% Junior Subordinated Notes due 2066 (1)	600		600
Term Loan due 2013	—		250
Note Payable	7		7
Unamortized fair value adjustments	49		—
	1,316		1,537
Panhandle:
6.05% Senior Notes due 2013	250		250
6.20% Senior Notes due 2017	300		300
8.125% Senior Notes due 2019	150		150
7.00% Senior Notes due 2029	66		66
7.00% Senior Notes due 2018	400		400
Term Loan due 2012	—		797
Term Loan due 2015	455		—
Net premiums on long-term debt	—		3
Unamortized fair value adjustments	136		—
	1,757		1,966
Total consolidated debt obligations	3,283		3,703
Less: Current portion of long term debt	259		343
Less: Short-term debt (2)	—		200
Total long-term debt	$	3,024	$	3,160

⁽¹⁾  Effective November 1, 2011, the interest rate on the Junior Subordinated Notes changed to a variable rate based upon the three-month LIBOR rate plus 3.0175%, reset quarterly.  See “Interest Rate Swaps” below for more information regarding the interest rate on these notes.

⁽²⁾  The Southern Union Credit Facility was included in short-term debt as of December 31, 2011, but not as of December 31, 2012. See discussion in “Credit Facilities” below.

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, 2012 and December 31, 2011 was $3.39 billion and $3.96 billion, respectively. As of December 31, 2012 and December 31, 2011, the aggregate carrying amount of the Company’s consolidated debt obligations was $3.28 billion and $3.70 billion, respectively. The fair value of the Company’s consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

F-25

Long-Term Debt. Southern Union had approximately $3.28 billion of long-term debt at December 31, 2012, of which $259 million was current.

As of December 31, 2012, the Company had scheduled long-term debt principal payments as follows:

	2013		2014		2015		2016		2017		2018 and thereafter
Southern Union Company	$	1	$	1	$	1	$	211	$	1	$	1,262
Panhandle	250		—		455		—		300		616
Total	$	251	$	1	$	456	$	211	$	301	$	1,878

Each note or bond is an obligation of Southern Union or a unit of Panhandle, as noted above. Panhandle’s debt is non-recourse to Southern Union. All debts that are listed as debt of Southern Union are direct obligations of Southern Union. None of the Company’s long-term debt is cross-collateralized and most of its long-term debt obligations contain cross-default provisions.

Credit Facilities.  In March 2012, the Company entered into the Eighth Amended and Restated Revolving Credit Agreement with certain banks in the amount of $700 million (Southern Union Credit Facility).  The Southern Union Credit Facility is an amendment, restatement and refinancing of the Company’s $550 million Seventh Amended and Restated Revolving Credit Agreement and is scheduled to mature on May 20, 2016.  The Company entered into the Southern Union Credit Facility in order to (i) obtain consent to the transactions contemplated by the Merger Agreement, the Citrus Merger Agreement and the Support Agreement; (ii) to increase the amount of the facility from $550 million to $700 million; and (iii) to modify certain covenants.  Borrowings under the Southern Union Credit Facility are available for the Company’s working capital, other general corporate purposes and letter of credit requirements.  The interest rate and commitment fee under the Southern Union Credit Facility are calculated using a pricing grid, which is based upon the credit rating for the Company’s senior unsecured notes.  The annualized interest rate for the Southern Union Credit Facility was 1.84% at December 31, 2012.

On August 10, 2012, Southern Union entered into a First Amendment of the Southern Union Credit Facility. The Amendment provides for, among other things, (i) a revision to the change of control definition to permit equity ownership of Southern Union by ETP or any direct or indirect subsidiaries of ETP in addition to ETE or any direct or indirect subsidiary of ETE; and (ii) a waiver of any potential default that may result from the Holdco Transaction.

The Company previously classified borrowings under the Southern Union Credit Facility as short-term debt as the individual borrowings are generally for periods of 15 to 180 days. Such borrowings have been classified as non-current based on the Company’s expectation that such borrowings will be refinanced upon maturity. Therefore, the Southern Union Credit Facility was classified in the table above and in the consolidated balance sheets as short-term debt as of December 31, 2011 and as long-term debt as of December 31, 2012.

Term Loans.  In March 2012, the Company retired the $250 million term loan due August 2013 and the $465 million term loan of its indirect wholly owned subsidiary, LNG Holdings, due June 2012 ($342 million of which was outstanding) utilizing a combination of the merger consideration received in connection with the Citrus Merger and drawdowns from its 2012 Revolver.

In February 2012, the Company refinanced LNG Holdings’ $455 million term loan due March 2012 with an unsecured three-year term loan facility due February 2015, with LNG Holdings as borrower and PEPL and Trunkline LNG as guarantors and a floating interest rate tied to LIBOR plus a margin based on the rating of PEPL’s senior unsecured debt. The effective interest rate of this term loan was 1.84% at December 31, 2012.

Restrictive Covenants. 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. Financial covenants exist in certain of the Company’s debt agreements. 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.

The Company’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of the

F-26

Company’s debt and other financial obligations and that of its subsidiaries. Under the current credit agreements, the financial covenants are as follows:

• Under the Southern Union Credit Facility, the ratio of consolidated funded debt to consolidated earnings before interest, taxes, depreciation and amortization, as defined therein, cannot exceed 5.25 times through December 31, 2012 and 5.00 times thereafter;

• Under the Southern Union Credit Facility, in the event Southern Union's credit rating falls below investment grade, the ratio of consolidated earnings before interest, taxes, depreciation and amortization to consolidated interest expense, as defined therein, cannot be less than 2.00 times;

• Under LNG Holding's $455 million term loan, the ratio of consolidated funded debt to consolidated earnings before interest, taxes, depreciation and amortization, as defined therein, for Panhandle cannot exceed 5.00 times.

In addition to the above financial covenants, the Company and/or its subsidiaries are subject to certain additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in the Company’s cash management program; and limitations on the Company’s ability to prepay debt. As of December 31, 2012, the Company is in compliance with these covenants.

Note Payable – ETE.  On March 26, 2012, the Company received $221 million from ETE to pay certain expenses in connection with the Merger, including (i) payments made to employees related to outstanding awards of stock options, stock appreciation rights and RSUs; and (ii) payments to certain executives under applicable employment or change in control agreements, which provided for compensation when their employment was terminated in connection with a change in control.  In connection with the receipt of the $221 million from ETE, on March 26, 2012, the Company entered into an interest-bearing promissory note payable on or before March 25, 2013.  The interest rate under the promissory note is 3.75% and accrued interest is payable monthly in arrears. A payment of $55 million to ETE was made in May 2012, and the outstanding balance of $166 million was recorded as a capital contribution from ETE as of December 31, 2012, as the note was assumed by Holdco.

Panhandle 6.05% Senior Notes due 2013. Panhandle has $250 million principal amount of senior notes which mature on August 15, 2013.  Panhandle currently expects to refinance all or a portion of the debt upon maturity or, alternatively, to retire all or a portion of the debt with proceeds from repayment of the note receivable from Southern Union.

Interest Rate Swaps.  The Company has interest rate swap agreements that effectively fix the interest rate applicable to the floating rate on a portion of the $600 million Junior Subordinated Notes due 2066. See Note 11for more information regarding these swap agreements.

9. RETIREMENT BENEFITS:

Pension and Other Postretirement Benefit Plans

The Company has funded non-contributory defined benefit pension plans that cover substantially all Distribution segment employees.  Normal retirement age is 65, but certain plan provisions allow for earlier retirement.  Pension benefits are calculated under formulas principally based on average earnings and length of service for salaried and non-union employees and average earnings and length of service or negotiated non-wage based formulas for union employees.

The 2012 postretirement benefits expense reflects the impact of curtailment accounting as postretirement benefits for all active participants who did not meet certain criteria were eliminated.  The Company previously had postretirement health care and life insurance plans that covered substantially all Distribution and Transportation and Storage segment employees as well as all Corporate employees.  The health care plans generally provide for cost sharing between the Company and its retirees in the form of retiree contributions, deductibles, coinsurance, and a fixed cost cap on the amount the Company pays annually to provide future retiree health care coverage under certain of these plans.

Obligations and Funded Status

Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services.  

F-27

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

	Pension Benefits									Other Postretirement Benefits
	Successor			Predecessor						Successor			Predecessor
	December 31, 2012			March 25, 2012			December 31, 2011			December 31, 2012			March 25, 2012			December 31, 2011
Change in benefit obligation:
Benefit obligation at beginning of period	$	228		$	225		$	194		$	141		$	135		$	110
Service cost	3			1			4			1			1			3
Interest cost	7			2			10			2			1			6
Amendments	—			—			—			17			—			—
Benefits paid, net	(9		)	(3		)	(11		)	(3		)	(1		)	(2		)
Curtailments	—			—			—			(80		)	—			—
Actuarial loss and other	14			3			28			6			5			18
Benefit obligation at end of period	$	243		$	228		$	225		$	84		$	141		$	135
Change in plan assets:
Fair value of plan assets at beginning of period	$	144		$	133		$	127		$	119		$	110		$	102
Return on plan assets and other	6			11			—			4			8			—
Employer contributions	14			3			17			9			2			10
Benefits paid, net	(9		)	(3		)	(11		)	(3		)	(1		)	(2		)
Fair value of plan assets at end of period	$	155		$	144		$	133		$	129		$	119		$	110
Amount underfunded (overfunded) at end of period	$	88		$	84		$	92		$	(45	)	$	22		$	25
Amounts recognized in the consolidated balance sheets consist of:
Noncurrent assets	$	—		$	—		$	—		$	57		$	6		$	4
Noncurrent liabilities	(88		)	(84		)	(92		)	(12		)	(28		)	(29		)
	$	(88	)	$	(84	)	$	(92	)	$	45		$	(22	)	$	(25	)
Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:
Net actuarial loss	$	17		$	74		$	83		$	2		$	23		$	25
Prior service cost	—			2			2			16			3			3
	$	17		$	76		$	85		$	18		$	26		$	28

F-28

The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets.

	Pension Benefits				Other Postretirement Benefits
	Successor		Predecessor		Successor		Predecessor
	December 31, 2012		December 31, 2011		December 31, 2012		December 31, 2011
Projected benefit obligation	$	243	$	225	N/A		N/A
Accumulated benefit obligation	228		212		$	13	$	104
Fair value of plan assets	155		133		—		76

Components of Net Periodic Benefit Cost

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

	Pension Benefits
	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Years Ended December 31,
							2011			2010
Net Periodic Benefit Cost:
Service cost	$	3		$	1		$	4		$	3
Interest cost	7			2			10			10
Expected return on plan assets	(9		)	(2		)	(11		)	(9		)
Prior service cost amortization	—			—			1			1
Actuarial loss amortization	—			2			8			8
	1			3			12			13
Regulatory adjustment (2)	9			—			1			—
Net periodic benefit cost	$	10		$	3		$	13		$	13

F-29

	Other Postretirement Benefits
	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Years Ended December 31,
							2011			2010
Net Periodic Benefit Cost:
Service cost	$	1		$	1		$	3		$	3
Interest cost	2			1			6			6
Expected return on plan assets	(5		)	(1		)	(6		)	(5		)
Prior service credit amortization	—			(1		)	(2		)	(2		)
Actuarial gain amortization	—			—			(1		)	(2		)
Curtailment recognition (1)	(15		)	—			—			—
	(17		)	—			—			—
Regulatory adjustment (2)	2			1			3			3
Net periodic benefit cost (credit)	$	(15	)	$	1		$	3		$	3

⁽¹⁾  Subsequent to the Merger, the Company amended certain of its other postretirement employee benefit plans, which prospectively restrict participation in the plans for the impacted active employees.  The plan amendments resulted in the plans becoming currently over-funded and, accordingly, the Company recorded a pre-tax curtailment gain of $75 million.  Such gain was offset by establishment of a non-current refund liability in the amount of $60 million.  As such, the net curtailment gain recognition was $15 million.

⁽²⁾  In the Distribution segment, the Company recovers certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers.  Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines.  The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.

The estimated net actuarial loss (gain) and prior service cost (credit) for pension plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost during 2013 are $2 million and zero, respectively.  The estimated net actuarial loss (gain) and prior service cost (credit) for other postretirement plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost during 2013 are $1 million and $1 million, respectively.

Assumptions

The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below.

	Pension Benefits						Other Postretirement Benefits
	Successor		Predecessor				Successor		Predecessor
	December 31, 2012		March 25, 2012		December 31, 2011		December 31, 2012		March 25, 2012		December 31, 2011
Discount rate	3.67	%	4.10	%	4.14	%	3.37	%	4.09	%	4.14	%
Rate of compensation increase	3.17	%	3.02	%	3.02	%	N/A		N/A		N/A

F-30

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

	Pension Benefits								Other Postretirement Benefits
	Successor		Predecessor						Successor		Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,				Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011		2010						2011		2010
Discount rate	4.10	%	4.14	%	5.35	%	5.82	%	3.05	%	4.14	%	5.36	%	5.85	%
Expected return on assets:
Tax exempt accounts	8.25	%	8.25	%	8.25	%	8.25	%	7.00	%	7.00	%	7.00	%	7.00	%
Taxable accounts	N/A		N/A		N/A		N/A		4.50	%	4.50	%	4.50	%	5.00	%
Rate of compensation increase	3.02	%	3.02	%	3.02	%	3.24	%	N/A		N/A		N/A		N/A

The Company employs a building block approach in determining the expected long-term rate of return on the plans’ assets, with proper consideration of 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 ensure reasonableness and appropriateness.

The assumed health care cost trend rates used to measure the expected cost of benefits covered by the Company’s other postretirement benefit plans are shown in the table below.

	Successor		Predecessor
	December 31, 2012		March 25, 2012		December 31, 2011
Health care cost trend rate assumed for next year	8.77	%	8.00	%	8.50	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.69	%	4.75	%	4.75	%
Year that the rate reaches the ultimate trend rate	2020		2019		2019

Assumed health care cost trend rates have a significant effect on the amounts reported for healthcare plans.  A 1% change in assumed health care cost trend rates would have the following effects:

	One Percentage Point Increase		One Percentage Point Decrease
Effect on total of service and interest cost	$	—	$	—
Effect on accumulated postretirement benefit obligation	5		(4		)

Plan Assets

The Company’s overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification.  To achieve diversity within its pension plan asset portfolio, the Company has targeted the following asset allocations: equity of 25% to 70%, fixed income of 15% to 35%, alternative assets of 10% to 35% and cash of 0% to 10%.  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 0% to 10%.  These target allocations

F-31

are monitored by the Investment Committee of the Board 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 pension plan assets by asset category at the dates indicated is as follows:

	Fair Value as of		Fair Value Measurements at December 31, 2012 Using Fair Value Hierarchy
	December 31, 2012		Level 1		Level 2		Level 3
Asset Category:
Cash and cash equivalents	$	17	$	17	$	—	$	—
Mutual fund (1)	127		—		127		—
Multi-strategy hedge funds (2)	11		—		11		—
Total	$	155	$	17	$	138	$	—

	Fair Value as of		Fair Value Measurements at December 31, 2011 Using Fair Value Hierarchy
	December 31, 2011		Level 1		Level 2		Level 3
Asset Category:
Cash and cash equivalents	$	12	$	12	$	—	$	—
Mutual fund (1)	111		—		111		—
Multi-strategy hedge funds (2)	10		—		10		—
Total	$	133	$	12	$	121	$	—

⁽¹⁾  This commingled fund invests primarily in a diversified portfolio of equity and fixed income funds.  As of December 31, 2012, the fund was primarily comprised of approximately 34% large-cap U.S. equities, 7% small-cap U.S. equities, 22% international equities, 28% fixed income securities, and 9% in other investments.  As of December 31, 2011, the fund was primarily comprised of approximately 36% large-cap U.S. equities, 6% small-cap U.S. equities, 20% international equities, 30% fixed income securities, and 8% in other investments.  These investments are generally redeemable on a daily basis at the net asset value per share of the investment.

⁽²⁾  Primarily includes hedge funds that invest in multiple strategies, including relative value, opportunistic/macro, long/short equities, merger arbitrage/event driven, credit, and short selling strategies, to generate long-term capital appreciation through a portfolio having a diversified risk profile with relatively low volatility and a low correlation with traditional equity and fixed-income markets.  These investments can generally be redeemed effective as of the last day of a calendar quarter at the net asset value per share of the investment with approximately 65 days prior written notice.

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

	Fair Value as of		Fair Value Measurements at December 31, 2012 Using Fair Value Hierarchy
	December 31, 2012		Level 1		Level 2		Level 3
Asset Category:
Cash and Cash Equivalents	$	3	$	3	$	—	$	—
Mutual fund (1)	126		126		—		—
Total	$	129	$	129	$	—	$	—

F-32

	Fair Value as of		Fair Value Measurements at December 31, 2011 Using Fair Value Hierarchy
	December 31, 2011		Level 1		Level 2		Level 3
Asset Category:
Cash and Cash Equivalents	$	2	$	2	$	—	$	—
Mutual fund (1)	108		108		—		—
Total	$	110	$	110	$	—	$	—

⁽¹⁾  This fund of funds primarily invests in a combination of equity, fixed income and short-term mutual funds.  As of December 31, 2012, the fund was primarily comprised of approximately 17% large-cap U.S. equities, 3% small-cap U.S. equities, 10% international equities, 53% fixed income securities, 10% cash, and 7% in other investments.  As of December 31, 2011, the fund was primarily comprised of approximately 19% large-cap U.S. equities, 2% small-cap U.S. equities, 10% international equities, 55% fixed income securities, 8% cash, and 6% in other investments.

The Level 1 plan assets are valued based on active market quotes.  The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was determined by the Company to be calculated consistent with authoritative accounting guidelines.  See Note 2for information related to the framework used by the Company to measure the fair value of its pension and other postretirement plan assets.

Contributions

The Company expects to contribute approximately $18 million to its pension plans and approximately $8 million to its other postretirement plans in 2013.  The Company funds the cost of the plans in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.

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	Benefits		Other Postretirement Benefits (Gross, Before Medicare Part D)		Other Postretirement Benefits (Medicare Part D Subsidy Receipts)
2013	$	12	$	7	$	1
2014	12		6		1
2015	12		6		1
2016	12		6		1
2017	12		6		1
2018 - 2021	67		30		4

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 care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.

Defined Contribution Plan

The Company sponsors a defined contribution savings plan (Savings Plan) that is available to all employees.  The Company provided maximum matching contributions based upon certain Savings Plan provisions during 2010 through 2012 ranging from 2% to 6.25% of the participant’s compensation paid into the Savings Plan.  Company contributions are 100% vested after five years of continuous service for all plans other than plans for Missouri Gas Energy union employees and employees of the Fall River operation, as to which contributions are 100% vested after six years of continuous service.  Company contributions to the Savings Plan during the period from Acquisition (March 26, 2012) to December 31, 2012, the period from January 1, 2012 to March 25, 2012, and the years ended December 31, 2011 and 2010 were $6 million, $2 million, $8 million and $7 million, respectively.

F-33

In addition, the Company makes employer contributions to separate accounts, referred to as Retirement Power Accounts, within the defined contribution plan.  The contribution amounts are determined as a percentage of compensation and range from 3.5% to 12%.  Company contributions are generally 100% vested after five years of continuous service.  Company contributions to Retirement Power Accounts during the period from Acquisition (March 26, 2012) to December 31, 2012, the period from January 1, 2012 to March 25, 2012, and the years ended December 31, 2011 and 2010 were $2 million, $3 million, $8 million and $8 million, respectively.

10. TAXES ON INCOME:

The following tables provide a summary of the current and deferred components of income tax expense (benefit) from continuing operations for the periods presented:

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Years Ended December 31,
							2011			2010
Current expense (benefit):
Federal	$	(43	)	$	—		$	2		$	(11	)
State	3			(1		)	(7		)	(3		)
Total	(40		)	(1		)	(5		)	(14		)
Deferred expense (benefit):
Federal	81			10			76			82
State	(2		)	3			9			12
Total	79			13			85			94
Total income tax expense from continuing operations	$	39		$	12		$	80		$	80
Effective tax rate	78		%	27		%	27		%	29		%

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

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Years Ended December 31,
							2011			2010
Computed statutory income tax expense at 35%	$	17		$	16		$	103		$	97
Changes in income taxes resulting from:
Earnings from unconsolidated investments related to anticipated receipt of dividends	5			(5		)	(27		)	(27		)
Nondeductible executive compensation	18			—			—			—
State income taxes, net of federal income tax benefit	1			1			1			6
Other	(2		)	—			3			4
Actual income tax expense from continuing operations	$	39		$	12		$	80		$	80

F-34

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:

	Successor			Predecessor
	December 31, 2012			December 31, 2011
Deferred income tax assets:
Alternative minimum tax credit	$	37		$	38
Pension and other postretirement benefits	24			54
Derivative financial instruments (interest rates)	31			32
Long-term debt	78			—
Net operating loss	70			25
Other	34			35
Total deferred income tax assets	274			184
Deferred income tax liabilities:
Property, plant and equipment	(1,423		)	(1,139		)
Unconsolidated investments	(280		)	(29		)
Other	(56		)	(48		)
Total deferred income tax liabilities	(1,759		)	(1,216		)
Net deferred income tax liability	(1,485		)	(1,032		)
Less: current income tax assets	105			13
Accumulated deferred income taxes	$	(1,590	)	$	(1,045	)

The Company has federal net operating loss (NOL) carryforwards of $184 million, of which $18 million will expire in 2030, $40 million will expire in 2031, and $126 million will expire in 2032.  The Company has state NOL carryforward benefits of $7 million, expiring between 2013 and 2032.

A reconciliation of the changes in unrecognized tax benefits for the periods presented is as follows:

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
						2011		2010
Beginning balance	$	19		$	19	$	16	$	13
Additions:
Tax positions taken in prior years	—			—		—		—
Tax positions taken in current year	—			—		3		3
Reductions:
Lapse of statute	(3		)	—		—		—
Ending balance	$	16		$	19	$	19	$	16

As of December 31, 2012, the Company has unrecognized tax benefits for capitalization policies and state filing positions of $2 million and $14 million, respectively. However, only the $14 million ($9 million, net of federal tax) unrecognized tax benefits for certain state filing positions would impact the Company’s EITR if recognized. The Company believes it is reasonably possible that its unrecognized tax benefits may be reduced by $4 million ($2 million, net of federal tax) within the next twelve months due to settlement of certain state filing positions.

F-35

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 statements of operations, which is consistent with the recognition of these items in prior reporting periods.

During 2012, the Company recognized interest and penalties of less than $1 million. At December 31, 2012, the Company has interest and penalties accrued of $2 million ($2 million, net of tax).

The Company is no longer subject to U.S. federal, state or local examinations for the tax years prior to 2004.

The Company is under examination for the tax years 2004 through 2009. As of December 31, 2012, the IRS has proposed only one adjustment for the years under examination. For the 2006 tax year, the IRS is challenging $545 million of the $690 million of deferred gain associated with a like-kind exchange involving certain assets of the Distribution segment and the Gathering and Processing segment. The Company will vigorously defend and believes it will prevail against this challenge by the IRS. Accordingly, no unrecognized tax benefit has been recorded with respect to this tax position.

11. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES:

The Company is exposed to certain risks in its ongoing business operations.  The primary risks managed by using derivative instruments are interest rate risk and commodity price risk.  Interest rate swaps and treasury rate locks are the principal derivative instruments used by the Company to manage interest rate risk associated with its long-term borrowings, although other interest rate derivative contracts may also be used from time to time.  Natural gas and NGL price swaps and NGL processing spread swaps are the principal derivative instruments used by the Company to manage commodity price risk associated with purchases and/or sales of natural gas and/or NGL, although other commodity derivative contracts may also be used from time to time.  The Company recognizes all derivative instruments as assets or liabilities at fair value in the consolidated balance sheets.

Interest Rate Contracts

The Company may enter into interest rate swaps to manage its exposure to changes in interest payments on long-term debt attributable to movements in market interest rates, and may enter into treasury rate locks to manage its exposure to changes in future interest payments attributable to changes in treasury rates prior to the issuance of new long-term debt instruments.

Interest Rate Swaps.  In 2011, the Company entered into interest rate swap agreements to hedge the $600 million Junior Subordinated Notes due 2066 with an aggregate notional amount of $525 million, of which $450 million were for ten-year periods and $75 million were for five-year periods.  These interest rate swaps became effective on November 1, 2011.  The Company pays interest on the Junior Subordinated Notes at the floating rate of three-month LIBOR plus a credit spread of 3.0175% beginning November 1, 2011.  The interest rate swaps effectively fix the interest rate applicable to the floating rate on a portion of the Junior Subordinated Notes and are accounted for as cash flow hedges, with the effective portion of their settled value recorded in accumulated other comprehensive income and reclassified into interest expense in the same periods during which the related interest payments on long-term debt impact earnings.  The floating rate LIBOR-based portion of the interest payments was exchanged for weighted average fixed rate interest payments of 3.63%.  In conjunction with the Merger, the Company discontinued hedge accounting treatment on these interest rate swaps.  Therefore, future changes in fair value will be recognized in earnings.

The Company also had outstanding pay-fixed interest rate swaps with a total notional amount of $455 million to hedge the LNG Holdings $455 million term loan, which was refinanced in February 2012.  These interest rate swaps were accounted for as cash flow hedges, with the effective portion of changes in their fair value recorded in accumulated other comprehensive income and reclassified intointerest expense in the same periods during which the related interest payments on long-term debt impacted earnings.  These swaps terminated in the first quarter of 2012.

For the predecessor period in 2012 during which hedge accounting treatment was applied, there was no swap ineffectiveness.

Treasury Rate Locks.  As of December 31, 2012, the Company had no outstanding treasury rate locks.  However, certain of its treasury rate locks that settled in prior periods were associated with interest payments on outstanding long-term debt.  During the predecessor periods, these treasury rate locks were accounted for as cash flow hedges, with the effective portion of their settled value recorded in accumulated other comprehensive income and reclassified into interest expense in the same periods during which the related interest payments on long-term debt impact earnings.

F-36

Commodity Contracts – Gathering and Processing Segment

The Company primarily enters into natural gas and NGL price swaps and NGL processing spread swaps to manage its exposure to changes in margin on forecasted sales of natural gas and NGL volumes resulting from movements in market commodity prices.

Natural Gas Price Swaps.  As of December 31, 2012, the Company had outstanding receive-fixed natural gas price swaps with a total notional amount of 4,562,500 MMBtu for 2013.  These natural gas price swaps are accounted for as cash flow hedges, with the effective portion of changes in their fair value recorded in accumulated other comprehensive income and reclassified into operating revenues in the same periods during which the forecasted natural gas sales impact earnings.  As of December 31, 2012, approximately $3 million of net after-tax losses in accumulated other comprehensive income related to these natural gas price swaps are expected to be recognized in operating revenues during the next 12 months.  Any ineffective portion of the cash flow hedge is reported in current-period earnings.

Commodity Contracts - Distribution Segment

Through the Distribution segment, included in the LDC Disposal Group at December 31, 2012, the Company enters into natural gas commodity financial instruments to manage the exposure to changes in the cost of natural gas passed through to utility customers that result from movements in market commodity prices.  The cost of the derivative instruments and settlement of the respective obligations are recovered from utility customers through the purchased natural gas adjustment clause as authorized by the applicable regulatory authority and therefore do not impact earnings.

Natural Gas Price Swaps.  As of December 31, 2012, the Company had outstanding pay-fixed natural gas price swaps with total notional amounts of 2,600,000 MMBtu, 16,350,000 MMBtu and 6,540,000 MMBtu for 2012, 2013 and 2014, respectively.  These natural gas price swaps are accounted for as economic hedges, with changes in their fair value recorded to deferred natural gas purchases.

F-37

Summary Financial Statement Information

The following table summarizes the fair value amounts of the Company’s asset and liability derivative instruments and their location reported in the consolidated balance sheets at the dates indicated. The asset and liability derivative instruments belonging to the Distribution segment have been included in current asset and liabilities held for sale at December 31, 2012.

	Fair Value
	Asset Derivatives				Liability Derivatives
	Successor		Predecessor		Successor		Predecessor
Balance Sheet Location	December 31, 2012		December 31, 2011		December 31, 2012		December 31, 2011
Cash Flow Hedges:
Interest rate contracts
Derivative instruments — liabilities	$	—	$	—	$	—	$	20
Deferred credits	—		—		—		60
Commodity contracts — Gathering and Processing:
Natural gas price swaps
Prepayments and other assets	—		6		—		—
Accounts payable to related companies	—		—		5		—
NGL price swaps
Prepayments and other assets	—		—		—		2
Derivative instruments — liabilities	—		—		—		4
	—		6		5		86
Economic Hedges:
Interest rate contracts
Derivative instruments — liabilities	—		—		18		—
Deferred credits	—		—		59		—
Commodity contracts — Distribution:
Natural gas price swaps
Non-current assets held for sale	1		—		—		—
Current liabilities held for sale	—		—		8		—
Derivative instruments — liabilities	—		—		—		35
Deferred credits	—		—		—		6
	1		—		85		41
Total	$	1	$	6	$	90	$	127

The Company has master netting arrangements with certain of its counterparties, which permit applicable obligations of the parties to be settled on a net versus gross basis.  If a right of offset exists, the fair value amounts for the derivative instruments are reported in the consolidated balance sheets on a net basis and disclosed herein on a gross basis.

F-38

The following tables summarize the location and amount (excluding income tax effects) of derivative instrument gains and losses reported in the Company’s consolidated financial statements for the periods presented:

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Years Ended December 31,
							2011			2010
Cash Flow Hedges:
Interest rate contracts:
Change in fair value - increase in accumulated other comprehensive income	$	—		$	6		$	74		$	13
Reclassification of unrealized loss from accumulated other comprehensive income - increase of interest expense	—			8			22			22
Commodity contracts - Gathering and Processing:
Change in fair value - increase (decrease) in accumulated other comprehensive income	(6		)	5			(7		)	(39		)
Reclassification of unrealized gain from accumulated other comprehensive income	1			2			24			19
Economic Hedges:
Interest rate contracts:
Change in fair value - increase in interest expense	12			—			—			—
Commodity contracts - Gathering and Processing:
Change in fair value of other hedges - decrease in operating revenues	—			—			30			31
Commodity contracts - Distribution:
Change in fair value - increase (decrease) in deferred natural gas purchases	(32		)	(2		)	3			(6		)

Derivative Instrument Contingent Features

Certain of the Company’s derivative instruments contain provisions that require the Company’s debt to be maintained at an investment grade credit rating from each of the major credit rating agencies.  If the Company’s debt were to fall below investment grade, the Company would be in violation of these provisions, and the counterparties to the derivative instruments could potentially require the Company to post collateral for certain of the derivative instruments.  The aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a net liability position at December 31, 2012 was $4 million, all of which were included in the disposal group held for sale at December 31, 2012.

F-39

12. FAIR VALUE MEASUREMENT:

The following table sets forth the Company’s assets and liabilities that are measured at fair value on a recurring basis at the date indicated:

	Fair Value as of		Fair Value Measurements at December 31, 2012 Using Fair Value Hierarchy
	December 31, 2012		Level 1		Level 2		Level 3
Assets:
Commodity derivatives	$	1	$	—	$	1	$	—
Total	$	1	$	—	$	1	$	—
Liabilities:
Commodity derivatives	$	13	$	—	$	13	$	—
Interest-rate swap derivatives	77		—		77		—
Total	$	90	$	—	$	90	$	—

	Fair Value as of		Fair Value Measurements at December 31, 2011 Using Fair Value Hierarchy
	December 31, 2011		Level 1		Level 2		Level 3
Assets:
Commodity derivatives	$	4	$	—	$	4	$	—
Long-term investments	1		1		—		—
Total	$	5	$	1	$	4	$	—
Liabilities:
Commodity derivatives	$	44	$	—	$	44	$	—
Interest-rate swap derivatives	80		—		80		—
Total	$	124	$	—	$	124	$	—

The Company’s Level 1 instruments primarily consisted of trading securities related to a non-qualified deferred compensation plan that are valued based on active market quotes. The Company’s Level 2 instruments primarily include natural gas and NGL price swaps and NGL processing spread swap derivatives and interest-rate swap derivatives that are valued using pricing models based on an income approach that discounts future cash flows to a present value amount.  The significant pricing model inputs for natural gas and NGL price swaps and NGL processing spread swap derivatives include published NYMEX forward index prices for delivery of natural gas at Henry Hub, Permian Basin and Waha, and NGL at Mont Belvieu.  The significant pricing model inputs for interest-rate swaps include published rates for U.S. Dollar LIBOR interest rate swaps.  The pricing models also adjust for nonperformance risk associated with the counterparty or Company, as applicable, through the use of credit risk adjusted discount rates based on published default rates.  The Company did not have any Level 3 instruments measured at fair value at December 31, 2012 or December 31, 2011 and there were no transfers between hierarchy levels.

The approximate fair value of the Company’s cash and cash equivalents, accounts receivable and accounts payable is equal to book value, due to their short-term nature.

F-40

13. PROPERTY, PLANT AND EQUIPMENT:

The following table provides a summary of property, plant and equipment at the dates indicated.

		Successor		Predecessor
	Lives in Years	December 31, 2012		December 31, 2011
Regulated Operations:
Distribution plant	9-60	$	—	$	1,043
Gathering and processing plant	26	163		167
Transmission plant	5-46	2,580		2,321
General - LNG	5-40	966		1,119
Underground storage plant	5-46	306		322
General plant and other	3-40	110		304
Construction work in progress		45		48
		4,170		5,324
Less accumulated depreciation and amortization		58		1,219
		4,112		4,105
Non-regulated Operations:
Distribution plant	5-40	60		60
Gathering and processing plant	3-50	1,296		1,840
General plant and other	3-29	10		20
Construction work in progress		227		56
		1,593		1,976
Less accumulated depreciation and amortization		47		354
		1,546		1,622
Property, plant and equipment, net		$	5,658	$	5,727

As of December 31, 2011, property, plant and equipment included capitalized computer software costs of $51 million, net of accumulated amortization of $89 million. Amortization expense of capitalized computer software costs for the years ended December 31, 2011 and 2010 was $11 million and $11 million, respectively.

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

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.

Environmental Remediation

Transportation and Storage Segment

Panhandle 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

F-41

containing PCBs; and the prior use of wastewater collection facilities and other on-site disposal areas. Panhandle has implemented a program to remediate such contamination.  The primary remaining remediation activity on the Panhandle 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, Panhandle could potentially be held responsible for contamination caused by other parties. In some instances, Panhandle may share liability associated with contamination with other PRPs.  Panhandle may also benefit from contractual indemnities that cover some or all of the cleanup costs. These sites are generally managed in the normal course of business or operations.

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

Gathering and Processing Segment

SUGS is responsible for environmental remediation at certain sites on its gathering and processing systems, resulting primarily from releases of hydrocarbons.  SUGS has a program to remediate such contamination.  The 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 and complexity.  The ultimate liability and total costs associated with these sites will depend upon many factors. These sites are generally managed in the normal course of business or operations.

Distribution Segment

The Company is allowed to recover environmental remediation expenditures through rates in certain jurisdictions within its Distribution segment.  Significant charges to earnings could be required prior to rate recovery for jurisdictions that do not have rate recovery mechanisms.

The Company is responsible for environmental remediation at various contaminated sites that are primarily associated with former MGPs and sites associated with the operation and disposal activities of former MGPs that produced a fuel known as “town gas.” Some byproducts of the historic manufactured gas process may be regulated substances under various federal and state environmental laws. To the extent these byproducts are present in soil or groundwater at concentrations in excess of applicable standards, investigation and remediation may be required.  The sites include properties that are part of the Company’s ongoing operations, sites formerly owned or used by the Company and sites owned by third parties. Remediation typically involves the management of contaminated soils and may involve removal of old MGP structures and remediation of groundwater. Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements, complexity and sharing of responsibility; some contamination may be unrelated to former MGPs. 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 PRPs and may also benefit from insurance policies or contractual indemnities that cover some or all of the cleanup costs. These sites are generally managed in the normal course of business or operations.

North Attleboro MGP Site in Massachusetts (North Attleboro Site).  In November 2003, the MADEP issued a Notice of Responsibility to New England Gas Company, acknowledging receipt of prior notifications and investigative reports submitted by New England Gas Company, following the discovery of suspected coal tar material at the North Attleboro Site.  Subsequent sampling in the adjacent river channel revealed sediment impacts necessitating the investigation of off-site properties.  Assessment activities have recently been completed and it is estimated that the Company will spend approximately$11 million over the next several years to complete remediation activities at the North Attleboro Site, as well as maintain the engineered barrier constructed in 2008 at the upland portion of the site.  As New England Gas Company is allowed to recover environmental remediation expenditures through rates associated with its Massachusetts operations, the estimated costs associated with the North Attleboro Site have been included in regulatory assets in the consolidated balance sheets.

F-42

Environmental Remediation Liabilities

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.  Except for matters discussed above, the Company does not have any material environmental remediation matters assessed as reasonably possible that would require disclosure in the financial statements.

	Successor		Predecessor
	December 31, 2012		December 31, 2011
Current	$	7	$	9
Noncurrent	26		12
Total environmental liabilities	$	33	$	21

During the period from Acquisition (March 26, 2012) to December 31, 2012, the period from January 1, 2012 to March 25, 2012, and the years ended December 31, 2011 and 2010, the Company had $3 million, $1 million, $3 million and $4 million, respectively, of expenditures related to environmental cleanup programs.

Litigation and Other Claims

Will Price.  Will Price, an individual, filed actions in the U.S. District Court for the District of Kansas for damages against a number of companies, including Panhandle, alleging mis-measurement of natural gas volumes and Btu content, resulting in lower royalties to mineral interest owners.  On September 19, 2009, the Court denied plaintiffs’ request for class certification.  Plaintiffs have filed a motion for reconsideration, which the Court denied on March 31, 2010.  Panhandle believes that its measurement practices conformed to the terms of its FERC natural gas tariffs, which were filed with and approved by the FERC.  As a result, the Company believes that it has meritorious defenses to the Will Price lawsuit (including FERC-related affirmative defenses, such as the filed rate/tariff doctrine, the primary/exclusive jurisdiction of the FERC, and the defense that Panhandle complied with the terms of its tariffs).  In the event that Plaintiffs refuse Panhandle’s pending request for voluntary dismissal, Panhandle will continue to vigorously defend the case.  The Company believes it has no liability associated with this proceeding.

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 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 the Company’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, the Company’s former Vice Chairman, President and Chief Operating Officer, joined the Company’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 the Company’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.  The Company 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 the Company’s motion to dismiss.  The AG’s motion to be reimbursed expert and consultant costs by the Company of up to $150,000 was granted.  The hearing officer has stayed discovery until resolution of a separate matter concerning the applicability of attorney-client privilege to legal billing invoices.  The Company 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. Additionally, New England Gas Company’s assets and liabilities have been included in discontinued operations at December 31, 2012.

Air Quality Control.  SUGS is currently negotiating settlements to certain enforcement actions by the NMED and the TCEQ.

Compliance Orders from the New Mexico Environmental Department

SUGS has been in discussions with the NMED concerning allegations of violations of New Mexico air regulations related to the Jal #3 and Jal #4 facilities.  The NMED has issued amended compliance orders and proposed penalties for alleged violations at Jal #4 in the amount of $1 million and at Jal #3 in the amount of $7 million.  Hearings on the compliance orders were

F-43

delayed until May 2013 to allow the parties to pursue substantive settlement discussions.  SUGS has meritorious defenses to the NMED claims and can offer significant mitigating factors to the claimed violations.  The Company has recorded an accrued liability and will continue to assess its potential exposure to the allegations as the matter progresses.

Litigation Relating to the Merger With ETE

In June 2011, several putative class action lawsuits were filed in the Judicial District Court of Harris County, Texas naming as defendants the members of the Southern Union Board, as well as Southern Union and ETE. The lawsuits were styled Jaroslawicz v. Southern Union Company, et al., Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas and Magda v. Southern Union Company, et al., Cause No. 2011-37134, in the 11th Judicial District Court of Harris County, Texas. The lawsuits were consolidated into an action styled In re: Southern Union Company; Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas. Plaintiffs allege that the Southern Union directors breached their fiduciary duties to Southern Union's stockholders in connection with the Merger and that Southern Union and ETE aided and abetted the alleged breaches of fiduciary duty. The amended petitions allege that the Merger involves an unfair price and an inadequate sales process, that Southern Union's directors entered into the Merger to benefit themselves personally, including through consulting and noncompete agreements, and that defendants have failed to disclose all material information related to the Merger to Southern Union stockholders. The amended petitions seek injunctive relief, including an injunction of the Merger, and an award of attorneys' and other fees and costs, in addition to other relief. On October 21, 2011, the court denied ETE's October 13, 2011, motion to stay the Texas proceeding in favor of cases pending in the Delaware Court of Chancery.

Also in June 2011, several putative class action lawsuits were filed in the Delaware Court of Chancery naming as defendants the members of the Southern Union Board, as well as Southern Union and ETE. Three of the lawsuits also named Merger Sub as a defendant. These lawsuits are styled: Southeastern Pennsylvania Transportation Authority, et al. v. Southern Union Company, et al., C.A. No. 6615-CS; KBC Asset Management NV v. Southern Union Company, et al., C.A. No. 6622-CS; LBBW Asset Management Investment GmbH v. Southern Union Company, et al., C.A. No. 6627-CS; and Memo v. Southern Union Company, et al., C.A. No. 6639-CS. These cases were consolidated with the following style: In re Southern Union Co. Shareholder Litigation, C.A. No. 6615-CS, in the Delaware Court of Chancery. The consolidated complaint asserts similar claims and allegations as the Texas state-court consolidated action. On July 25, 2012, the Delaware plaintiffs filed a notice of voluntary dismissal of all claims without prejudice. In the notice, plaintiffs stated their claims were being dismissed to avoid duplicative litigation and indicated their intent to join the Texas case.

The Texas case remains pending, and discovery is ongoing.

In November 2011, a derivative lawsuit was filed in the Judicial District Court of Harris County, Texas naming as defendants ETP, ETP GP, ETP LLC, the boards of directors of ETP LLC (collectively with ETP GP and ETP LLC, the “ETP Defendants”), certain members of management for ETP and ETE, ETE, and Southern Union. The lawsuit is styled W. J. Garrett Trust v. Bill W. Byrne, et al., Cause No. 2011-71702, in the 157th Judicial District Court of Harris County, Texas. Plaintiffs assert claims for breaches of fiduciary duty, breaches of contractual duties, and acts of bad faith against each of the ETP Defendants and the individual defendants. Plaintiffs also assert claims for aiding and abetting and tortious interference with contract against Southern Union. On October 5, 2012, certain defendants filed a motion for summary judgment with respect to the primary allegations in this action. On December 13, 2012, Plaintiffs filed their opposition to the motion for summary judgment. Defendants filed a reply on December 19, 2012. On December 20, 2012, the court conducted an oral hearing on the motion. Plaintiffs filed a post-hearing sur-reply on January 7, 2013. On January 16, 2013, the Court granted defendants' motion for summary judgment. The deadline for the remaining defendants to file an answer or otherwise respond is March 1, 2013. Trial in this action is not currently set.

Mercury Release

In October 2004, New England Gas Company discovered that one of its facilities, formerly associated with discontinued operations which were sold in 2006, had been broken into and that mercury had been released both inside a building and in the immediate vicinity, including a parking lot in a neighborhood several blocks away. Mercury from the parking lot was apparently tracked into nearby apartment units, as well as other buildings. Cleanup was completed at the property and nearby apartment units. The vandals who broke into the facility were arrested and convicted. In October 2007, the U.S. Attorney in Rhode Island filed a three-count indictment against the Company in the U.S. District Court for the District of Rhode Island (District Court) alleging violation of permitting requirements under the federal RCRA and notification requirements under the Emergency Planning and Community Right to Know Act (EPCRA) relating to the 2004 incident. Trial commenced on September 22, 2008, and on October 15, 2008, the jury acquitted Southern Union on the EPCRA count and one of the two RCRA counts and found the Company guilty on the other RCRA count. On October 2, 2009, the District Court imposed a fine of $6 million and a payment of $12 million in community service.

F-44

On December 22, 2010, the United States Court of Appeals for the First Circuit (First Circuit) affirmed the conviction and the sentence. On February 17, 2011, the First Circuit denied the Company’s petition for en banc rehearing.  The Company, on October 31, 2011, filed a petition for a writ of certiorari review by the United States Supreme Court (Supreme Court), which review was granted and the case was heard by the Supreme Court on March 19, 2012.

On June 21, 2012, the United States Supreme Court reversed the First Circuit, holding that the sentence imposed on the Company was unconstitutional, and remanded the case back to the District Court for further proceeding consistent with that holding.

On July 17, 2012, the Government moved for “clarification” of the First Circuit’s December 22, 2010 decision urging the First Circuit to find that, in addition to resolving whether (i) the alternative fine statute increases the maximum fine that may be imposed on the Company from $50,000 to $500,000; (ii) the $12 million community service obligation is a fine or restitution; and (iii) a new jury should be empanelled to hear evidence regarding the number of days RCRA was violated.

On July 26, 2012, the First Circuit vacated the fine imposed by the District Court and remanded the matter to the District Court for resentencing consistent with the Supreme Court’s opinion.  In the same order, the First Circuit denied without prejudice the Government’s motion for clarification, holding that the issues raised by the Government in its July 17, 2012 motion could be addressed by the parties on remand.  Accordingly, the Government petitioned the District Court for consideration of the same issues and the hearing took place on December 3, 2012.  The District Court has not yet issued their ruling.  A ruling against the Company would likely result in a judgment of less than $1 million.  Additionally, New England Gas Company’s assets and liabilities have been included in discontinued operations at December 31, 2012.

Liabilities for Litigation and Other Claims

In addition to the matters discussed above, 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.

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, 2012 and December 31, 2011, the Company recorded litigation and other claim-related accrued liabilities of $27 million and $28 million, respectively.  Except for the matters discussed above, 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.

Lease Commitments

The Company leases certain facilities, equipment and office space under cancelable and non-cancelable operating leases. 

Future minimum lease commitments for such leases are:

Years Ending December 31:
2013	$	20
2014	16
2015	15
2016	8
2017	7
Thereafter	61

Rental expense was $16 million, $5 million, $20 million and $19 million for the period from Acquisition (March 26, 2012) to December 31, 2012, the period from January 1, 2012 to March 25, 2012, and the years ended December 31, 2011 and 2010, respectively.

Other Commitments and Contingencies

Retirement of Debt Obligations.  See Note 8for information related to the Company’s debt maturing in 2013.

2008 Hurricane Damage.  In September 2008, Hurricanes Gustav and Ike came ashore on the Louisiana and Texas coasts.  Damage from the hurricanes affected the Company’s Transportation and Storage segment.  Offshore transportation

F-45

facilities, including Sea Robin and Trunkline’s Terrebonne system, suffered damage to several platforms and gathering pipelines.  Sea Robin experienced reduced volumes until January 2010 when the remainder of the damaged facilities was placed back in service.

The capital replacement and retirement expenditure related to Hurricane Ike, which were substantially completed in 2011, totaled approximately $141 million.  As of December 31, 2012, OIL has paid a total of $65 million for claims submitted to date by the Company with respect to Hurricane Ike.  Additional reimbursements to be received in the future are dependent on several factors including the final insureds payout percentage.

Purchase Commitments.  At December 31, 2012, the Company had purchase commitments for natural gas transportation services, storage services and certain quantities of natural gas at a combination of fixed, variable and market-based prices that have an aggregate value of approximately $181 million.  The Company’s purchase commitments may be extended over several years depending upon when the required quantity is purchased.  The Company has purchased natural gas tariffs in effect for all its utility service areas that provide for recovery of its purchased natural gas costs under defined methodologies and the Company believes that all costs incurred under such commitments will be recovered through its purchased natural gas tariffs.

Missouri Safety Program.  Pursuant to a 1989 MPSC order, Missouri Gas Energy is engaged in its service territories in the Missouri Safety Program.  This program includes replacement of Company and customer-owned natural gas service and yard lines, the movement and resetting of meters, the replacement of cast iron mains and the replacement and cathodic protection of bare steel mains.  In recognition of the significant capital expenditures associated with this safety program, the MPSC initially permitted the deferral and subsequent recovery through rates of depreciation expense, property taxes and associated carrying costs over a 10-year period.  On August 28, 2003, the State of Missouri passed certain statutes that provided Missouri Gas Energy the ability to adjust rates periodically to recover depreciation expense, property taxes and carrying costs associated with the Missouri Safety Program, as well as investments in public improvement projects.  The continuation of the Missouri Safety Program will result in significant levels of future capital expenditures for Missouri Gas Energy. Missouri Gas Energy incurred capital expenditures of $9 million, $3 million, $14 million and $14 million for the period from Acquisition (March 26, 2012) to December 31, 2012, the period from January 1, 2012 to March 25, 2012, and the years ended December 31, 2011 and 2010, respectively, related to this program.  Missouri Gas Energy estimates incurring approximately $135 million over the next 10 years, after which all service lines, representing about 34% of the annual safety program investment, will have been replaced. These future expenditures do not constitute a contingency for the Company, as Missouri Gas Energy has been included in discontinued operations as of December 31, 2012.

Regulation and Rates.  See Note 19 for potential contingent matters associated with the Company’s regulated operations.

Unclaimed Property Audits.  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.

Air Quality Control

Oil and Natural Gas Sector New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants.  On April 17, 2012 the EPA issued the Oil and Natural Gas Sector New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants.  The standards revise the new source performance standards for volatile organic compounds from leaking components at onshore natural gas processing plants and new source performance standards for sulfur dioxide emissions from natural gas processing plants.  The EPA also established standards for certain oil and gas operations not covered by the existing standards.  In addition to the operations covered by the existing standards, the newly established standards regulate volatile organic compound emissions from gas wells, centrifugal compressors, reciprocating compressors, pneumatic controllers and storage vessels.  The Company is reviewing the new standards to determine the impact on its operations.

Transportation and Storage Segment.  In August 2010, the EPA finalized a rule that requires reductions in a number of pollutants, including formaldehyde and carbon monoxide, for certain engines regardless of size at Area Sources (sources that emit less than 10 tons per year of any one Hazardous Air Pollutant (HAP) or 25 tons per year of all HAPs) and engines less than 500 horsepower at Major Sources (sources that emit 10 tons per year or more of any one HAP or 25 tons per year of all HAPs).  Compliance is required by October 2013.  It is anticipated that the limits adopted in this rule will be used in a future EPA rule that is scheduled to be finalized in 2013, with compliance required in 2016.  This future rule is expected to require reductions in formaldehyde and carbon monoxide emissions from engines greater than 500 horsepower at Major Sources.

F-46

Nitrogen oxides are the primary air pollutant from natural gas-fired engines.  Nitrogen oxide emissions may form ozone in the atmosphere.  In 2008, the EPA lowered the ozone standard to 75 ppbwith compliance anticipated in 2013 to 2015.  In January 2010, the EPA proposed lowering the standard to 60 to 70 ppb in lieu of the 75 ppb standard, with compliance required in 2014 or later.  In September 2011, the EPA decided to rescind the proposed lower ozone standard and begin the process to implement the 75 ppb ozone standard established in 2008.

In January 2010, the EPA finalized a 100 ppb one-hour nitrogen dioxide standard.  The rule requires the installation of new nitrogen dioxide monitors in urban communities and roadways by 2013.  This new monitoring may result in additional nitrogen dioxide non-attainment areas.  In addition, ambient air quality modeling may be required to demonstrate compliance with the new standard.

The Company is currently reviewing the potential impacts of the August 2010 Area Source National Emissions Standards for Hazardous Air Pollutants rule, implementation of the 2008 ozone standard and the new nitrogen dioxide standard on operations in its Transportation and Storage and Gathering and Processing segments and the potential costs associated with the installation of emission control systems on its existing engines.  The ultimate costs associated with these activities cannot be estimated with any certainty at this time, but the Company believes, based on the current understanding of the current and proposed rules, such costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

The KDHE set certain contingency measures as part of the agency’s ozone maintenance plan for the Kansas City area.  Previously, it was anticipated that these measures would be revised to conform to the requirements of the EPA ozone standard discussed above.  KDHE recently indicated that the Kansas City area will be designated as attainment for the ozone standard in 2012, and will not be pursuing any emissions reductions from PEPL’s operations unless there are changes in the future regarding the status of the Kansas City area.

Gathering and Processing Segment.  The Texas Commission on Environmental Quality recently initiated a state-wide emissions inventory for the sulfur dioxide emissions from sites with reported emissions of 10 tons per year or more.  If this data demonstrates that any source or group of sources may cause or contribute to a violation of the National Ambient Air Quality Standards, they must be sufficiently controlled to ensure timely attainment of the standard.  This may potentially affect three SUGS recovery units in Texas.  It is unclear at this time how the NMED will address the sulfur dioxide standard.

15. STOCK-BASED COMPENSATION:

The fair value of each stock option and SAR award is estimated on the date of grant using a Black-Scholes option pricing model. The Company’s expected volatilities are based on historical volatility of the Company’s common stock.  To the extent that volatility of the Company’s common stock price increases in the future, the estimates of the fair value of stock options and SARs granted in the future could increase, thereby increasing stock-based compensation expense in future periods. Additionally, the expected dividend yield is considered for each grant on the date of grant.  The Company’s uses the simplified method in determining the expected term of stock options and SARs granted, which results in the use of the average midpoint between vesting of the awards and their contractual term for such estimate.  The Company utilizes the simplified method primarily because it has experienced several acquisitions and divestitures during the contractual period for the current awards outstanding, resulting in a change in the employee mix and an acceleration of certain stock option and SAR exercise activity.  Additionally, the Company has not experienced a full life cycle of exercise activity for employees associated with certain of its acquisitions.  Because of the impact of these significant structural changes in the Company’s business operations and the resulting variations in employee exercise activity, the historical patterns of such exercise activity is not believed to be indicative of future behavior.  In the future, as information regarding post-vesting termination becomes more accessible, the Company may change the method of deriving the expected term.  This change could impact the fair value of stock options and SARs granted in the future.  The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant.

All outstanding stock awards vested and were settled in 2012 in connection with the ETE Merger on March 26, 2012; therefore, no 2012 amounts have been presented in the following sections.

F-47

The following table represents the Black-Scholes estimated ranges under the Company’s plans for stock options and SARs awards granted in the periods presented:

	Years ended December 31,
	2011	2010
Expected volatility	32.83% to 35.60%	32.79% to 34.98%
Expected dividend yield	2.45%	2.45% to 2.47%
Risk-free interest rate	1.58% to 2.41%	1.78% to 2.40%
Expected life	4.75 to 6 years	4.75 to 6 years

Stock Options

The following table provides information on stock options granted, exercised, forfeited, outstanding and exercisable under the Third Amended and Restated 2003 Stock and Incentive Plan (Third Amended 2003 Plan) and the 1992 Long-Term Stock Incentive Plan (1992 Plan) for the periods presented:

	Third Amended 2003 Plan				1992 Plan
	Shares Under Option		Weighted- Average Exercise Price		Shares Under Option		Weighted- Average Exercise Price
Outstanding December 31, 2009	3,014,220		$	20.69	49,019		$	14.65
Granted	684,635		24.90		—		—
Exercised	(91,044	)	19.48		(9,860	)	14.65
Forfeited	(10,940	)	25.60		—		—
Outstanding December 31, 2010	3,596,871		21.51		39,159		$	14.65
Granted	75,271		28.49		—		—
Exercised	(77,386	)	17.22		(29,188	)	14.65
Forfeited	(510	)	24.06		(9,971	)	14.65
Outstanding December 31, 2011	3,594,246		21.75		—		$	—
Exercisable December 31, 2010	1,814,539		$	19.83	39,159		$	14.65
Exercisable December 31, 2011	2,478,000		19.86		—		—

The following table summarizes information about stock options outstanding under the Third Amended 2003 Plan at December 31, 2011.

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number of Options	Weighted-Average Remaining Contractual Life	Weighted-Average Exercise Price		Number of Options	Weighted-Average Exercise Price
Third Amended 2003 Plan:
12.55 - 15.00	792,934	6.96 years	$	12.55	792,934	$	12.55
15.01 - 20.00	205,573	4.78 years	16.90		205,573	16.90
20.01 - 25.00	1,726,790	7.00 years	23.28		1,127,284	23.04
25.01 - 28.49	868,949	6.47 years	28.23		352,209	27.85
	3,594,246	6.73 years	$	21.75	2,478,000	$	19.86

F-48

Stock Appreciation Rights

The following table provides information on SARs granted, exercised, forfeited, outstanding and exercisable under the Third Amended 2003 Plan for the periods presented.

	Third Amended 2003 Plan
	SARs		Weighted-Average Exercise Price
Outstanding December 31, 2009	1,493,131		$	19.18
Granted	376,795		24.67
Exercised	(47,322	)	12.64
Forfeited	(38,648	)	19.93
Outstanding December 31, 2010	1,783,956		$	20.50
Granted	4,276		28.10
Exercised	(77,477	)	15.33
Forfeited	(47,415	)	25.33
Outstanding December 31, 2011	1,663,340		$	20.63
Exercisable December 31, 2010	900,965		$	20.53
Exercisable December 31, 2011	1,278,950		19.71

The SARs that have been awarded vest in equal installments on the first three anniversaries of the grant date.  Each SAR entitles the holder to shares of Southern Union’s common stock equal to the fair market value of Southern Union’s common stock on the applicable exercise date in excess of the grant date price for each SAR.

The following table summarizes information about SARs outstanding under the Third Amended 2003 Plan at December 31, 2011.

	SARs Outstanding				SARs Exercisable
Range of Exercise Prices	Number of SARs	Weighted-Average Remaining Contractual Life	Weighted-Average Exercise Price		Number of SARs	Weighted-Average Exercise Price
12.55 - 17.50	568,685	6.96 years	$	12.55	568,685	$	12.55
17.51 - 25.00	745,401	8.44 years	23.17		365,287	22.68
25.01 - 28.48	349,254	5.71 years	28.35		344,978	28.36
	1,663,340	7.36 years	$	20.63	1,278,950	$	19.71

The weighted-average remaining contractual life of options and SARs outstanding under the Third Amended 2003 Plan at December 31, 2011 was 6.93 years.  The weighted-average remaining contractual life of options and SARs exercisable under the Third Amended 2003 Plan at December 31, 2011 was 6.56 years.  The aggregate intrinsic value of total options and SARs outstanding and exercisable at December 31, 2011 was $109 million and $84 million, respectively.

The total fair value of options and SARs vested as of December 31, 2011 was $22 million.  Compensation expense recognized related to stock options and SARs totaled $7 million and $6 million for the years ended December 31, 2011 and 2010, respectively.  Cash received from the exercise of stock options was $2 million for the year ended December 31, 2011.

The intrinsic value of options and SARs exercised during the year ended December 31, 2011 was approximately $2 million.  The Company realized an additional tax benefit of less than $1 million for the excess amount of deductions related to stock options and SARs over the historical book compensation expense multiplied by the statutory tax rate in effect, which has been reported as an increase in financing cash flows in the consolidated statement of cash flows.

F-49

Restricted Stock Equity and Liability Units

The Company’s Third Amended 2003 Plan also provides for grants of restricted stock equity units, which are settled in shares of the Company’s common stock, and restricted stock liability units, which are settled in cash.  The restrictions associated with a grant of restricted stock equity units under the Third Amended 2003 Plan generally expire equally over a period of three years.  Restrictions on certain grants made to non-employee directors and senior executives of the Company expire over a shorter time period, in certain cases less than one year, and may be subject to accelerated expiration over a shorter term if certain criteria are met.  The restrictions associated with a grant of restricted stock liability units expire equally over a period of three years and are payable in cash at the vesting date.

The following table provides information on restricted stock equity awards granted, released and forfeited for the periods presented.

	Number of Restricted Stock Equity Units Outstanding		Weighted-Average Grant Date Fair Value
Restricted shares at December 31, 2009	378,974		$	19.14
Granted	111,457		23.71
Released	(148,218	)	17.63
Forfeited	(1,000	)	25.15
Restricted shares at December 31, 2010	341,213		$	21.27
Granted	7,000		28.04
Released	(162,362	)	17.96
Forfeited	—		—
Restricted shares at December 31, 2011	185,851		$	24.41

The following table provides information on restricted stock liability awards granted, released and forfeited for the periods presented.

	Number of Restricted Stock Liability Units Outstanding		Weighted-Average Grant Date Fair Value
Restricted units at December 31, 2009	563,650		$	18.38
Granted	175,043		24.67
Released	(237,219	)	18.82
Forfeited	(54,344	)	18.77
Restricted units at December 31, 2010	447,130		$	20.56
Granted	270,835		42.01
Released	(239,714	)	18.53
Forfeited	(17,394	)	18.86
Restricted units at December 31, 2011	460,857		$	34.29

The total fair value of restricted stock equity and liability units that were released during the year ended December 31, 2011 was $13 million. Compensation expense recognized related to restricted stock equity and liability units totaled $14 million and $9 million for the years ended December 31, 2011 and 2010, respectively.

The Company settled the restricted stock liability units released in 2011 and 2010 with cash payments of $10 million and $6 million, respectively.

F-50

16. PREFERRED SECURITIES:

On October 8, 2003, the Company issued 9,200,000 depositary shares, each representing a 1/10th interest in a share of its Preferred Stock at the public offering price of $25 per share, or $230 million in the aggregate.

On July 30, 2010, the Company redeemed the remaining approximately 460,000 shares of outstanding Preferred Stock at $25 per share, which totaled $115 million.  The Company recognized a $3 million non-cash loss adjustment charged to retained earnings related to the write-off of issuance costs that reduced net earnings available for common stockholders.

17. 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 and the natural gas gathering and processing systems 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 and the natural gas gathering and processing systems in good working order.  Therefore, although some of the individual assets may be replaced, the pipeline and the natural gas gathering and processing systems themselves will remain intact indefinitely.

As of December 31, 2012, the Company had recorded AROs related to (i) retiring natural gas storage wells, (ii) retiring offshore platforms and lines and (iii) removing asbestos.  Amounts reflected in long-lived assets related to AROs aggregated approximately $5 million and were reflected as non-current assets on our balance sheet.

As of December 31, 2012, the Company had no legally restricted funds for the purpose of settling AROs.

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

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
						2011			2010
Beginning balance	$	46		$	46	$	62		$	62
Incurred	—			—		1			30
Revisions	3			—		—			(11		)
Settled	(5		)	—		(17		)	(20		)
Accretion expense	2			—		—			1
Ending balance	$	46		$	46	$	46		$	62

In 2010, additional AROs of $29 million were established primarily for the Company’s offshore assets.  During 2010, the Company largely completed its assessment and repairs of the property damaged by Hurricane Ike in 2008, which resulted in accelerated abandonments of such property, and determined that the estimated third party abandonment costs for all of its offshore property needed to be increased.  Also in 2010, the Company recorded an $11 million downward revision to its prior ARO liability estimates, primarily for the costs of abandoning certain other specific offshore properties as a result of favorable weather conditions, changes in equipment used, and some changes in scope of the respective projects, which were primarily related to abandonments required as a results of permanent damage from Hurricane Ike.  The ARO liability associated with Hurricane Ike was further reduced by settlements of $20 million.  Such revisions and settlements were primarily associated

F-51

with AROs of $8 million and $34 million recorded in 2009 and 2008, respectively, associated with damage caused by Hurricane Ike.  During 2011, the Company recorded settlements of approximately $17 million, primarily associated with the abandonment of certain offshore properties damaged by Hurricane Ike.

18. REPORTABLE SEGMENTS:

The Company’s primary operating segments, which are individually disclosed as its reportable business segments, are:  Transportation and Storage, Gathering and Processing, and Distribution.  These operating segments are organized for segment reporting purposes based on the way internal managerial reporting presents the results of the Company’s various businesses to its chief operating decision maker for use in determining the performance of the businesses.

The Transportation and Storage segment operations are conducted through Panhandle and the Company’s investment in Citrus (through March 26, 2012, the date of the Citrus Merger).  The Gathering and Processing segment operations are conducted through SUGS.  The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts, through its Missouri Gas Energy and New England Gas Company operating divisions, respectively. See Note 1 for additional information associated with the Company’s reportable segments.

Sales of products or services between segments are billed at regulated rates or at market rates, as applicable.  There were no material intersegment revenues during the period from Acquisition (March 26, 2012) to December 31, 2012, the period from January 1, 2012 to March 25, 2012, and the fiscal year ended December 31, 2011.

The remainder of the Company’s business operations, which do not meet the quantitative threshold for segment reporting, are presented as Corporate and other activities.  Corporate and other activities consist of unallocated corporate costs, a wholly-owned subsidiary with ownership interests in electric power plants, and other miscellaneous activities.

The Company previously reported segment EBIT as a measure of segment performance.  Subsequent to the ETE Merger, the chief operating decision maker assesses performance of the Company’s business based on Segment Adjusted EBITDA.  The Company defines Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, amortization and other non-cash items, such as non-cash compensation expense, unrealized gains and losses on unhedged derivative activities, accretion expense and amortization of regulatory assets and other non-operating income or expense items.  Segment Adjusted EBITDA reflects amounts for less than wholly owned subsidiaries and unconsolidated affiliates based on the Company’s proportionate ownership.  Based on the change in its segment performance measure, the Company has recast the presentation of its segment results for the prior periods to be consistent with the current period presentation.

Segment Adjusted EBITDA may not be comparable to measures used by other companies and should be considered in conjunction with net earnings and other performance measures such as operating income or net cash flows provided by operating activities.

F-52

The following tables set forth certain selected financial information for the Company’s segments for the periods presented or at the dates indicated:

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
						2011		2010
Operating revenues from external customers:
Transportation and Storage	$	592		$	194	$	804	$	769
Gathering and Processing	663			246		1,180		1,008
Total segment operating revenues	1,255			440		1,984		1,777
Corporate and other activities	8			3		13		12
	$	1,263		$	443	$	1,997	$	1,789
Depreciation and amortization:
Transportation and Storage	$	125		$	30	$	128	$	123
Gathering and Processing	52			18		73		70
Total segment depreciation and amortization	177			48		201		193
Corporate and other activities	2			1		3		3
	$	179		$	49	$	204	$	196
Earnings from unconsolidated investments:
Transportation and Storage	$	1		$	16	$	98	$	100
Gathering and Processing	(8		)	—		—		4
Corporate and other activities	—			—		1		1
	$	(7	)	$	16	$	99	$	105

Results from the Distribution segment were included in discontinued operations and therefore were not reflected in the table above.

F-53

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012			Period from January 1, 2012 to March 25, 2012			Years Ended December 31,
							2011			2010
Segment Adjusted EBITDA:
Transportation and Storage	$	326		$	186		$	778		$	753
Gathering and Processing	40			25			125			127
Distribution	68			34			90			98
Corporate and other activities	8			(19		)	(6		)	6
Total Segment Adjusted EBITDA	442			226			987			984
Depreciation and amortization	(179		)	(49		)	(204		)	(196		)
Unrealized losses on unhedged derivative activities	—			—			—			(19		)
Net gain on curtailment of OPEB plans	15			—			—			—
Non-cash equity-based compensation, accretion expense and amortization of regulatory assets	(4		)	(1		)	(9		)	(8		)
Other, net	2			(2		)	—			2
Earnings (losses) from unconsolidated investments	(7		)	16			99			105
Adjusted EBITDA attributable to unconsolidated investments	(5		)	(61		)	(262		)	(267		)
Adjusted EBITDA attributable to discontinued operations	(83		)	(34		)	(99		)	(107		)
Interest expense	(131		)	(50		)	(218		)	(216		)
Income from continuing operations before income tax expense	$	50		$	45		$	294		$	278

	Successor		Predecessor
	December 31, 2012		December 31, 2011
Total assets:
Transportation and Storage	$	6,219	$	5,289
Gathering and Processing	1,965		1,743
Distribution	1,190		1,075
Total segment assets	9,374		8,107
Corporate and other activities	619		164
Total assets	$	9,993	$	8,271

Distribution segment assets have been reported as assets held for sale in the consolidated balance sheet at December 31, 2012.

F-54

	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011		2010
Expenditures for long-lived assets:
Transportation and Storage	$	96	$	23	$	102	$	146
Gathering and Processing	200		42		114		96
Distribution	44		9		51		41
Total segment expenditures for long-lived assets	340		74		267		283
Corporate and other activities	—		1		2		4
Total expenditures for long-lived assets	$	340	$	75	$	269	$	287

Significant Customers and Credit Risk.  The following tables provide summary information of significant customers for Panhandle and SUGS by applicable segment and on a consolidated basis for the periods presented. Consolidated revenues for the periods presented exclude the Distribution segment, which was included in discontinued operations and therefore not reflected in the tables below. Additionally, the Distribution segment had no single customer or group of customers under common control that accounted for 10% or more of the Company’s Distribution segment or consolidated operating revenues for the periods presented.

	Percent of Transportation and Storage Segment Revenues
	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011		2010
BG LNG Services	31	%	30	%	30	%	29	%
ProLiance	12		13		13		13
Other top 10 customers	20		24		21		23
Remaining customers	37		33		36		35
Total percentage	100	%	100	%	100	%	100	%

	Percent of Consolidated Company Total Operating Revenues
	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011		2010
BG LNG Services	15	%	13	%	12	%	12	%
ProLiance	6		6		5		6
Other top 10 customers	9		11		8		10
Remaining customers	17		15		14		15
Total percentage	47	%	45	%	39	%	43	%

F-55

	Percent of Gathering and Processing Segment Revenues
	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011		2010
Phillips 66 Company (1)	68	%	73	%	62	%	54	%
Andrews Oil Buyers Inc.	6		6		12		12
Other top 10 customers	16		15		20		24
Remaining customers	10		6		6		10
Total percentage	100	%	100	%	100	%	100	%

	Percent of Consolidated Company Total Operating Revenues
	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to December 31, 2012		Period from January 1, 2012 to March 25, 2012		Years Ended December 31,
					2011		2010
Phillips 66 Company (1)	35	%	41	%	37	%	30	%
Andrews Oil Buyers Inc.	3		3		7		7
Other top 10 customers	8		8		12		13
Remaining customers	5		3		4		6
Total percentage	51	%	55	%	60	%	56	%

⁽¹⁾  For the five-year period ending December 31, 2014, SUGS has contracted to sell its entire owned or controlled output of NGL equity volumes to Phillips 66.  Pricing for the NGL equity volumes sold to Conoco throughout the contract period will be OPIS pricing based at Mont Belvieu, Texas delivery points.  SUGS has an option to extend the sales agreement for an additional five-year period.

19. REGULATION AND RATES:

Panhandle.  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 completed 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 is subject to FERC approval.  Several parties have intervened, commented, or protested this filing and the Company is currently responding to the Commission’s requests for additional information on this application.

In November 2011, FERC commenced an audit of PEPL to evaluate its compliance with the Uniform System of Accounts as prescribed by FERC, annual and quarterly financial reporting to FERC, reservation charge crediting policy and record retention.  The audit is related to the period from January 1, 2010 through December 31, 2011 and is pending the issuance of a draft audit report.

New England Gas Company.  On September 15, 2008, New England Gas Company made a filing with the MDPU seeking recovery of approximately $4 million, or 50% of the amount by which its 2007 earnings fell below a return on equity of 7%.  This filing was made pursuant to New England Gas Company’s rate settlement approved by the MDPU in 2007.  On February 2, 2009, the MDPU issued its order denying the Company’s requested earnings sharing adjustments (ESA) in its entirety.  The Company appealed that decision to the Massachusetts Supreme Judicial Court (MSJC).  On November 13, 2009, New England Gas Company made a similar filing with the MDPU, also pursuant to the above-referenced settlement, to recover

F-56

approximately $2 million, representing 50% of the amount by which its 2008 earnings deficiency fell below a return on equity of 7%.  The MDPU held the 2008 ESA matter in abeyance pending judicial resolution of the issues pertaining to the 2007 ESA.  On February 11, 2011, the MSJC issued an opinion reversing the MDPU’s rejection of New England Gas Company’s 2007 ESA and remanded the matter back to the MDPU to determine the appropriate amount of the 2007 ESA and the method for recovery.  On July 13, 2011, New England Gas Company filed its motion for proceeding on remand requesting that the MDPU (i) find that $4 million is the appropriate ESA amount for recovery related to calendar year 2007 and that such amount should be recovered over a twelve month period beginning November 1, 2011; and (ii) investigate New England Gas Company’s request for recovery of an ESA amount of $2 million over a twelve-month period beginning November 1, 2012.  On January 27, 2012, the MDPU issued its order approving the 2007 ESA in its entirety and authorizing recovery of approximately $4 million over a twelve-month period beginning February 1, 2012.  On January 25, 2013, the MDPU issued its order approving the 2008 ESA for $2 million to be recovered over a twelve-month period beginning February 1, 2013, which reflected a reduction of approximately $10,000 from the initial request.

20. QUARTERLY FINANCIAL DATA (UNAUDITED):

Summarized unaudited quarterly financial data is presented below.

	Predecessor		Successor
	Period from January 1, 2012 to March 25, 2012		Period from March 26, 2012 to March 31, 2012			Quarter ended						Total  Period from March 26, 2012 to December 31, 2012
						June 30, 2012		September 30, 2012		December 31, 2012
Operating revenues	$	443	$	31		$	386	$	405	$	441	$	1,263
Operating income (loss)	81		(47		)	66		73		94		186
Income (loss) from continuing operations	33		(39		)	3		12		35		11
Income from discontinued operations	17		1			8		5		14		28
			Predecessor
			Quarter ended
			March 31, 2011			June 30, 2011		September 30, 2011		December 31, 2011		Total
Operating revenues			$	430		$	523	$	536	$	508	$	1,997
Operating income			84			112		105		112		413
Income from continuing operations			44			56		53		61		214
Income from discontinued operations			16			3		5		17		41

F-57