- Annual Report (10-K)

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, 2011

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:

Title of each class	Name of each exchange on which registered
Common Stock, par value $1 per share	New York Stock Exchange

Securities Registered Pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes R No £

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 R

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 R No £

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 R No £

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of 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. R

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. (Check one): Large accelerated filer R Accelerated filer £ Non-accelerated filer £ Smaller reporting company £

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Yes £ No R

The aggregate market value of the Common Stock held by non-affiliates of the Registrant as of June 30, 2011 was $4.65 billion (based on the closing sales price of Common Stock on the New York Stock Exchange on June 30, 2011). For purposes of this calculation, shares held by non-affiliates exclude only those shares beneficially owned by executive officers, directors and stockholders of more than 10% of the Common Stock of the Company.

The number of shares of the registrant's Common Stock outstanding on February 17, 2012 was 124,854,997.

DOCUMENTS INCORPORATED BY REFERENCE

Certain information required by Part III (Items 10, 11,12, 13 and 14) of this Annual Report on Form 10-K will be filed with the Securities and Exchange Commission within 120 days of the end of the Registrant’s year ended December 31, 2011.

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

FORM 10-K

DECEMBER 31, 2011

Table of Contents

		Page
Glossary.	PART I	1
ITEM 1.	Business.	2
ITEM 1A.	Risk Factors.	16
ITEM 1B.	Unresolved Staff Comments.	32
ITEM 2.	Properties.	32
ITEM 3.	Legal Proceedings.	33
ITEM 4.	Mine Safety Disclosures.	33
	PART II
ITEM 5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.	33
ITEM 6.	Selected Financial Data.	36
ITEM 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations .	37
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk.	61
ITEM 8.	Financial Statements and Supplementary Data.	63
ITEM 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.	63
ITEM 9A.	Controls and Procedures.	63
ITEM 9B.	Other Information.	64
	PART III
ITEM 10.	Directors, Executive Officers and Corporate Governance.	64
ITEM 11.	Executive Compensation.	65
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	65
ITEM 13.	Certain Relationships and Related Transactions, and Director Independence.	65
ITEM 14.	Principal Accounting Fees and Services.	65
	PART IV
ITEM 15.	Exhibits, Financial Statement Schedules.	65
Signatures.		71
Index to the Consolidated Financial Statements.		F-1

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GLOSSARY

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

AFUDC Allowance for funds used during construction

ARO Asset retirement obligation

Bcf Billion cubic feet

Bcf/d Billion cubic feet per day

Btu British thermal units

CCE Holdings CCE Holdings, LLC

CEO Chief executive officer

CFO Chief financial officer

Citrus Citrus Corp.

Company Southern Union and its subsidiaries

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

EPS Earnings per share

ETE Energy Transfer Equity, L.P.

ETP Energy Transfer Partners, L.P., a subsidiary of ETE

Exchange Act Securities Exchange Act of 1934

FASB Financial Accounting Standards Board

FDOT/FTE Florida Department of Transportation/ Florida’s Turnpike Enterprise

FERC Federal Energy Regulatory Commission

Florida Gas Florida Gas Transmission Company, LLC, a wholly-owned subsidiary of Citrus

GAAP Accounting principles generally accepted in the United States of America

Gallons/d Gallons per day

Grey Ranch Grey Ranch Plant, LP

HCAs High consequence areas

IRS Internal Revenue Service

KDHE Kansas Department of Health and Environment

LNG Liquified 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

MMBtu/d Million British thermal units per day

MMcf Million cubic feet

MMcf/d Million cubic feet per day

MPSC Missouri Public Service Commission

NGL Natural gas liquids

NMED New Mexico Environment Department

NYMEX New York Mercantile Exchange

Panhandle Panhandle Eastern Pipe Line Company, LP and its subsidiaries

PCBs Polychlorinated biphenyls

PEPL Panhandle Eastern Pipe Line Company, LP

RFP Request for proposal

PRPs Potentially responsible parties

RCRA Resource Conservation and Recovery Act

RIDEM Rhode Island Department of Environmental Management

SARs Stock appreciation rights

Sea Robin Sea Robin Pipeline Company, LLC

SEC U.S. Securities and Exchange Commission

Sigma Sigma Acquisition Corporation

Southern Union Southern Union Company

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

SPCC Spill Prevention, Control and Countermeasure

SUGS Southern Union Gas Services

TBtu Trillion British thermal units

TCEQ Texas Commission on Environmental Quality

Trunkline Trunkline Gas Company, LLC

Trunkline LNG Trunkline LNG Company, LLC

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PART I

ITEM 1. Business.

OUR BUSINESS

Introduction

In addition, ETE and ETP are parties to an 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) ( Citrus Merger Agreement ). The Citrus Merger Agreement provides that Southern Union, CrossCountry Energy, LLC ( CrossCountry ), PEPL Holdings, LLC ( PEPL Holdings ) and Citrus ETP Acquisition, L.L.C. ( Citrus ETP ) will become parties by joinder at a time immediately prior to the closing of the Merger. Upon becoming a party to the Citrus Merger Agreement, Southern Union will assume the obligations and rights of ETE. Under the Citrus Merger Agreement, CrossCountry, a wholly-owned subsidiary of Southern Union that indirectly owns a 50 percent interest in Citrus, will be merged with and into Citrus ETP with CrossCountry surviving as a wholly-owned subsidiary of ETP ( Citrus Merger ).

See Item 8. Financial Statements and Supplementary Data, Note 3 – ETE Merger for information related to Southern Union’s intent to merge with ETE.

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 and its 50 percent equity ownership interest in Florida Gas through Citrus.

·	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.

·	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.

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.

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For information about the revenues, EBIT, earnings from unconsolidated investments, operating income, 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 Item 8. Financial Statements and Supplementary Data, Note 18 – Reportable Segments .

The Company also provides various corporate services to support its operating businesses, including executive management, accounting, communications, human resources, information technology, insurance, internal audit, investor relations, environmental, legal, payroll, purchasing, insurance, tax and treasury.

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, Southwest and Florida markets and related storage, and also provides LNG terminalling and regasification services. The Transportation and Storage segment’s operations are conducted through Panhandle and Citrus.

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, 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.

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 and EBIT 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 89 percent of total segment revenues and 27 percent of consolidated revenues in 2011.

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Florida Gas. Florida Gas is an open-access interstate pipeline system with a mainline capacity of 3.1 Bcf/d and approximately 5,500 miles of pipelines extending from south Texas through the Gulf Coast region of the United States to south Florida. Florida Gas’ pipeline system primarily receives natural gas from natural gas producing basins along the Louisiana and Texas Gulf Coast, Mobile Bay and offshore Gulf of Mexico. Florida Gas is the principal transporter of natural gas to the Florida energy market, delivering over 63 percent of the natural gas consumed in the state. In addition, Florida Gas’ pipeline system operates and maintains over 66 interconnects with major interstate and intrastate natural gas pipelines, which provide Florida Gas’ customers access to diverse natural gas producing regions.

Florida Gas earns the majority of its revenue through firm transportation contracts. Florida Gas also earns variable revenue from charges assessed on each unit of transportation provided.

Demand for natural gas transmission service on the Florida Gas pipeline system is somewhat seasonal, with the highest throughput and related net earnings occurring in the traditional summer cooling season during the second and third calendar quarters, primarily due to increased natural gas-fired electric generation loads. The Company’s share of net earnings of Florida Gas is reported in Earnings from unconsolidated investments in the Consolidated Statement of Operations.

Financial and Operating Data

For the years ended December 31, 2011, 2010 and 2009, the Transportation and Storage segment’s operating revenues were $803.7 million, $769.5 million and $749.2 million, respectively. Earnings from unconsolidated investments related to Citrus were $97.6 million, $99.8 million and $75 million for the years ended December 31, 2011, 2010 and 2009, respectively.

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

	Years Ended December 31,
	2011		2010		2009

Panhandle:
PEPL transportation		564		563		676
Trunkline transportation		743		664		683
Sea Robin transportation		113		172		132
Trunkline LNG terminal usage		2		43		33

Florida Gas (1)		864		835		821

___________________________

(1)	Represents 100 percent of Florida Gas versus the Company’s effective equity ownership interest of 50 percent.

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

	December 31, 2011

Panhandle:
Approximate Miles of Pipelines
PEPL		6,000
Trunkline		3,700
Sea Robin		400
Peak Day Delivery Capacity (Bcf/d)
PEPL		2.8
Trunkline		1.7
Sea Robin		1.0
Trunkline LNG		2.1
Trunkline LNG Sustainable Send Out Capacity (Bcf/d)		1.8
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		6.2
Trunkline		9.3
Sea Robin (2)		N/A
Weighted Average Remaining Life in Years of Firm Storage Contracts (1)
PEPL		9.2
Trunkline		1.6

Florida Gas: (3)
Approximate Miles of Pipelines		5,500
Peak Day Delivery Capacity (Bcf/d)		3.1
Approximate Average Number of Transportation Customers		170
Weighted Average Remaining Life in Years of Firm Transportation Contracts		13.2

________________________

(1)	Weighted by firm capacity volumes.

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

(3)	Represents 100 percent of Florida Gas versus the Company’s effective equity ownership of 50 percent.

Recent System Enhancements – Completed or Under Construction

Florida Gas Phase VIII Expansion . Florida Gas’ Phase VIII Expansion project was placed in-service on April 1, 2011, at an approximate cost of $2.5 billion, including capitalized equity and debt costs. To date, Florida Gas has entered into long-term firm transportation service agreements with shippers for 25-year terms accounting for approximately 74 percent of the available expansion capacity.

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Significant Customers

The following table provides the percentage of Transportation and Storage segment Operating revenues and related weighted average contract lives of Panhandle’s significant customers for the period presented.

	Percent of
	Segment Revenues			Weighted Average Life of
	For Year Ended			Contracts
Company	December 31, 2011 (1)			at December 31, 2011

BG LNG Services		30	%	18.3 years (LNG, transportation)
ProLiance		13		13.2 years (transportation), 14.1 years (storage)
Other top 10 customers		21			N/A
Remaining customers		36			N/A
Total percentage		100	%

__________________________

(1)	Panhandle has no single customer, or group of customers under common control, that accounted for ten percent or more of the Company’s total consolidated operating revenues.

Panhandle’s customers are subject to change during the year as a result of capacity release provisions that allow customers to release all or part of their capacity, which generally occurs for a limited time period. Under the terms of Panhandle’s tariffs, a temporary capacity release does not relieve the original customer from its payment obligations if the replacement customer fails to pay.

The following table provides information related to Florida Gas’ significant customers for the period presented.

	Percent of
	Total Operating			Weighted Average Life
	Revenues For Year Ended			of Contracts at
Company	December 31, 2011			December 31, 2011

NextEra Energy, Inc. (1)		46	%	26.1 Years
TECO Energy (2)		13		23.8 Years
Other top 10 customers		28			N/A
Remaining customers		13			N/A
Total percentage		100	%

____________________________

(1) Formerly referred to as Florida Power & Light Company

(2) Formerly referred to as Tampa Electric and Peoples Gas

Regulation and Rates

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

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

FERC has authority to regulate rates and charges for transportation and storage of natural gas in interstate commerce. FERC also has authority over the construction and operation of pipeline and related facilities utilized in the transportation and sale of natural gas in interstate commerce, including the extension, enlargement or abandonment of service using such facilities. PEPL, Trunkline, Sea Robin, Trunkline LNG, Southwest Gas and Florida 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.

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The following table summarizes the status of rate proceedings applicable to the Transportation and Storage segment.

	Date of Last
Company	Rate Filing	Rate Proceedings Status

PEPL	May 1992	Settlement effective April 1997
Trunkline	January 1996	Settlement effective May 2001
Sea Robin	June 2007	Settlement effective December 2008 (1)
Trunkline LNG	June 2001	Settlement effective January 2002 (2)
Southwest Gas Storage	August 2007	Settlement effective February 2008
Florida Gas	October 2009	Settlement effective April 2011 (3)

________________________

(1)	Settlement requires another rate case to be filed by January 2014.

(2)	Settlement provides for a rate moratorium through 2015. Current fixed rates apply through 2015 covering all facilities, except the IEP expansion facilities placed in service in March 2010, which have a negotiated rate through March 2030.

(3)	Settlement provides for a rate moratorium until January 1, 2013 and requires another rate case to be filed by November 2014.

Panhandle and Florida Gas are 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 and Florida Gas’ regulation and rates, see Item 1A. Risk Factors – Risks That Relate to the Company’s Transportation and Storage Segment and Item 8. Financial Statements and Supplementary Data, Note 6 – Unconsolidated Investments – Contingent Matters Potentially Impacting Southern Union Through the Company’s Investment in Citrus – Florida Gas Rate Filing and Note 19 – Regulation and Rates – Panhandle.

Competition

The interstate pipeline systems of Panhandle and Florida Gas 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 and Florida Gas. In order to meet these challenges, Panhandle and Florida Gas 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.

Panhandle’s current direct competitors include Alliance Pipeline LP, ANR Pipeline Company, Natural Gas Pipeline Company of America, ONEOK Partners, Texas Gas Transmission Corporation, Northern Natural Gas Company, Vector Pipeline, Columbia Gulf Transmission, Rockies Express Pipeline and Midwestern Gas Transmission.

Florida Gas competes in peninsular Florida with Gulfstream Natural Gas System, L.L.C., a joint venture of Spectra Energy Corporation and The Williams Companies. Florida Gas also serves the Florida panhandle, where it competes with Gulf South Pipeline Company, LP and the natural gas transportation business of Southern Natural Gas. Florida Gas faces competition, to a lesser degree, from alternate fuels, including residual fuel oil, in the Florida market, as well as from proposed LNG regasification facilities.

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Gathering and Processing Segment

Services

SUGS’ operations consist of a network of natural gas and NGL pipelines, five cryogenic processing plants and five 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 ( E&P ) 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 E&P 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 petrochemicals. 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 E&P 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 Item 8. Financial Statements and Supplementary Data, Note 11 – Derivative Instruments and Hedging Activities – Commodity Contracts – Gathering and Processing Segment and Item 7A. Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk – Gathering and Processing Segment.

Financial and Operating Data

For the years ended December 31, 2011, 2010 and 2009, SUGS’ gross margin ( Operating revenues net of Cost of natural gas and other energy) was $219.1 million, $193.3 million and $107.5 million, respectively.

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

	December 31, 2011

Approximate Miles of Pipelines		5,600
Plant capacity (MMcf/d):
Cryogenic processing		475
Natural gas treating		585
Approximate Average Number of Customers		217

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.

Significant Customers

The following table provides the percentage of Gathering and Processing segment Operating revenues and related weighted average contract lives of SUGS’ significant customers for the period presented.

	Percent of
	Segment
	Revenues For			Weighted Average Life
	Year Ended			of Contracts at
Company	December 31, 2011 (1)			December 31, 2011

Conoco Phillips Company		62	%	2 years (natural gas), 3 years (NGL)
Lone Star NGL Product Services, LLC		12		3.8 years (2)
Other top 10 customers		20			N/A
Remaining customers		6			N/A
Total percentage		100	%

_____________________

(1)	Conoco Phillips Company ( Conoco ) accounted for 27 percent of the Company’s total consolidated operating revenues. SUGS had no other single customer or group of customers under common control that accounted for ten percent or more of the Company’s total consolidated operating revenues.

(2)	The weighted average contract life excludes evergreen arrangements.

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 fee-based, percent-of-proceeds, and margin sharing contracts (conditioning fee and wellhead purchase contracts) which, as of December 31, 2011, comprised 10 percent, 73 percent and 17 percent 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:

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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.

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.

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 percent 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.

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 Item 8. Financial Statements and Supplementary Data, Note 11 – Derivative Instruments and Hedging Activities – Gathering and Processing Segment.

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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. SUGS’ direct competitors include Targa Resources Partners LP, DCP Midstream Partners, LP, Enterprise Texas Field Services, Anadarko Petroleum, Atlas Pipeline Partners, LP and Regency Gas Services LP. 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.

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 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. On February 10, 2010, the MPSC issued an order approving continued use of a distribution rate structure that eliminates the impact of weather and conservation for Missouri Gas Energy’s residential margin revenues and related earnings and approving expanded use of that distribution rate structure for Missouri Gas Energy’s small general service customers, effective February 28, 2010. Together, Missouri Gas Energy’s residential and small general service customers comprised 99 percent of its total customers and approximately 91 percent of its net operating revenues as of February 28, 2010. For additional information related to rates, see Item 8. Financial Statements and Supplementary Data, Note 19 – Regulation and Rates – Missouri Gas Energy.

Financial and Operating Data

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

	December 31, 2011

Approximate Miles of Pipelines
Mains		9,184
Service lines		5,943
Transmission lines		46

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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.

	Years Ended December 31,
	2011			2010			2009

Average number of customers:
Residential		480,356			484,014			485,136
Commercial		62,659			62,945			64,584
Industrial		97			94			95
		543,112			547,053			549,815
Transportation		1,821			1,733			1,698
Total customers		544,933			548,786			551,513

Natural gas sales (MMcf):
Residential		38,897			39,908			39,649
Commercial		17,553			16,412			16,249
Industrial		393			371			486
Natural gas sales billed		56,843			56,691			56,384
Net change in unbilled natural gas sales		(1,720	)		(169	)		395
Total natural gas sales		55,123			56,522			56,779
Natural gas transported		24,119			27,218			26,212
Total natural gas sales and gas transported		79,242			83,740			82,991

Natural gas sales revenues (in thousands):
Residential	$	473,725		$	475,418		$	488,112
Commercial		176,718			184,327			183,593
Industrial		6,454			8,668			9,109
Natural gas revenues billed		656,897			668,413			680,814
Net change in unbilled natural gas sales revenues		(19,353	)		4,021			(13,056	)
Total natural gas sales revenues		637,544			672,434			667,758
Natural gas transportation revenues		16,201			15,524			14,133
Other revenues		12,905			10,555			11,013
Total operating revenues	$	666,650		$	698,513		$	692,904

Weather:
Missouri Utility Operations:
Degree days (1)		5,183			5,033			4,985
Percent of 10-year measure (2)		100	%		97	%		96	%
Percent of 30-year measure (2)		100	%		97	%		96	%

Massachusetts Utility Operations:
Degree days (1)		5,162			5,288			5,633
Percent of 10-year measure (2)		85	%		86	%		92	%
Percent of 30-year measure (2)		84	%		87	%		91	%

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(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.

(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.

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Significant Customers

The Distribution segment has no single customer, or group of customers under common control, that accounted for ten percent or more of the Company’s Distribution segment or the Company’s total consolidated operating revenues for the years ended December 31, 2011, 2010 and 2009.

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, 2011, 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 twenty-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 2012 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 Item 8. Financial Statements and Supplementary Data, Note 19 – Regulation and Rates.

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 permits 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 five percent.

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.

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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.

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.

The following table summarizes the rate proceedings applicable to the Distribution segment:

Company	Date of Last Rate Filing	Rate Proceedings Status (1)

Missouri	April 2009	MPSC rate order effective February 28, 2010

Massachusetts	September 2010	MDPU rate order effective April 1, 2011

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(1)	For more information related to these rate filings, see Item 8. Financial Statements and Supplementary Data, Note 19 – Regulation and Rates .

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 evolving laws and regulations may require expenditures over a long period of time to control environmental impacts. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures. These procedures are designed to achieve compliance with such laws and regulations. For additional information concerning the impact of environmental regulation on the Company, see Item 1A. Risk Factors and Item 8. Financial Statements and Supplementary Data, Note 15 – Commitments and Contingencies.

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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 percent 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.

Employees

As of December 31, 2011, the Company had 2,437 employees, of whom 1,540 are paid on an hourly basis and 897 are paid on a salary basis. Unions represent 765 of the 1,540 hourly paid employees. The table below sets forth the number of employees represented by unions for each division, as well as the expiration dates of the current contracts with the respective bargaining units.

		Number of Employees
		Represented by Unions	Expiration of Current Contract

PEPL:
	USW Local 348	219	May 27, 2012

Missouri Gas Energy:
	Gas Workers 781	212	April 30, 2014
	IBEW Local 53	93	April 30, 2014
	USW Local 11-267	25	April 30, 2014
	USW Local 12561, 14228	147	April 30, 2014

New England Gas Company:
	UWUA Local 431	69	April 30, 2013

As of December 31, 2011, the number of persons employed by each segment was as follows: Transportation and Storage segment – 1,189 persons; Gathering and Processing segment – 323 persons; Distribution segment – 808 persons; All Other subsidiary operations – 13 persons. In addition, the corporate employees of Southern Union totaled 104 persons.

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The employees of Florida Gas are not employees of Southern Union and, therefore, were not considered in the employee statistics noted above. As of December 31, 2011, Florida Gas had 334 non-union employees.

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, 2011, 2010 or 2009.

Available Information

Southern Union files annual, quarterly and special reports, proxy statements and other information with the SEC as required. Any document that Southern Union files with the SEC may be read or copied at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for information on the public reference room. Southern Union’s SEC filings are also available at the SEC’s website at http://www.sec.gov and through Southern Union’s website at http://www.sug.com. The information on Southern Union’s website is not incorporated by reference into and is not made a part of this report.

The Company, by and through the Audit Committee of its Board of Directors ( Board ), has adopted a Code of Ethics and Business Conduct ( Code ) designed to reflect requirements of the Sarbanes-Oxley Act of 2002, New York Stock Exchange rules and other applicable laws, rules and regulations. The Code applies to all of the Company’s directors, officers and employees. Any amendment to the Code will be posted promptly on Southern Union’s website at http://www.sug.com.

Southern Union, by and through the Corporate Governance Committee of the Board, also has adopted Corporate Governance Guidelines ( Guidelines ). The Guidelines set forth, among other things, the responsibilities and standards under which the directors, the Board, its major committees and management shall function. The Code, the Guidelines and the charters of the Audit, Corporate Governance, Compensation, Finance and Investment committees are posted on the Corporate Governance section of Southern Union’s website under “Governance Documents” at http://www.sug.com.

ITEM 1A. Risk Factors.

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

RISKS THAT RELATE TO THE MERGER

Southern Union’s ability to complete the Merger is subject to the satisfaction of certain closing conditions and the receipt of consents from governmental entities which may impose restrictions or conditions that could adversely affect Southern Union and/or ETE. Any of the foregoing could cause the Merger to be delayed or abandoned.

The Merger is subject to certain closing conditions, the absence of injunctions or other legal restrictions and that no material adverse effect shall have occurred on either company. In addition, in order to complete the Merger, approvals from various governmental entities must be obtained. These governmental entities, such as the MPSC, may impose certain restrictions or obligations as conditions for their approval. Such restrictions or conditions may be imposed on the business and operations of Southern Union and/or ETE in connection with the completion of the Merger. These restrictions or conditions also could have the effect of delaying completion of the Merger or imposing additional costs on or limiting the revenues of the combined company and/or cause either ETE or Southern Union to abandon the Merger. Southern Union can provide no assurance that the various closing conditions and required approvals will be met or obtained.

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If the Merger Agreement is terminated, Southern Union may be obligated to reimburse ETE for costs incurred related to the Merger and, under certain circumstances, pay a breakup fee to ETE. These costs could require Southern Union to seek loans or use Southern Union’s available cash that would have otherwise been available for operations, dividends or other general corporate purposes.

In certain circumstances, upon termination of the Merger Agreement, Southern Union would be responsible for reimbursing ETE for up to $54 million in expenses related to the transaction and may be obligated to pay a breakup fee to ETE of $181.3 million.

If the Merger Agreement is terminated, the expense reimbursements and the breakup fee required to be paid, if any, by Southern Union under the Merger Agreement may require Southern Union to seek loans or borrow amounts to enable it to pay these amounts to ETE. In either case, payment of these amounts would reduce the cash Southern Union has available for operations, dividends or other general corporate purposes.

The failure to successfully combine the businesses of ETE and Southern Union in the expected time frame may adversely affect ETE’s future results, which may adversely affect the value of the ETE common units that Southern Union stockholders would receive in the Merger.

The success of the Merger will depend, in part, on the ability of ETE to realize the anticipated benefits from combining the businesses of ETE and Southern Union. To realize these anticipated benefits, ETE’s and Southern Union’s businesses must be successfully combined. If the combined company is not able to achieve these objectives, the anticipated benefits of the Merger may not be realized fully or at all or may take longer to realize than expected. In addition, the actual integration may result in additional and unforeseen expenses, which could reduce the anticipated benefits of the Merger.

ETE and Southern Union, including their respective subsidiaries, have operated and, until the completion of the Merger, will continue to operate independently. It is possible that the integration process could result in the loss of key employees, as well as the disruption of each company’s ongoing businesses or inconsistencies in their standards, controls, procedures and policies. Any or all of those occurrences could adversely affect the combined company’s ability to maintain relationships with customers and employees after the Merger or to achieve the anticipated benefits of the Merger. Integration efforts between the two companies will also divert management attention and resources. These integration matters could have an adverse effect on each of ETE and Southern Union.

The pendency of the Merger could materially adversely affect the future business and operations of Southern Union or result in a loss of Southern Union employees.

In connection with the pending Merger, it is possible that some customers, suppliers and other persons with whom Southern Union has a business relationship may delay or defer certain business decisions or might decide to seek to terminate, change or renegotiate their relationship with Southern Union as a result of the Merger, which could negatively impact revenues, earnings and cash flows of Southern Union, as well as the market price of shares of Southern Union common stock, regardless of whether the Merger is completed. Similarly, current and prospective employees of Southern Union may experience uncertainty about their future roles with ETE and Southern Union following completion of the Merger, which may materially adversely affect the ability of Southern Union to attract and retain key employees. Additionally, under the Merger Agreement, the Company is subject to certain restrictions on the conduct of its business prior to completing the Merger, which may adversely affect its ability to execute certain of its business strategies.

Failure to complete the Merger could negatively impact the stock price of Southern Union and its future businesses and financial results.

If the Merger is not completed, the ongoing business of Southern Union may be adversely affected and Southern Union will be subject to several risks and consequences, including the following:

·	under the Merger Agreement, Southern Union may be required, under certain circumstances, to pay ETE a breakup fee of $181.3 million and up to $54 million of ETE’s expenses;

·	Southern Union will be required to pay certain costs relating to the Merger, whether or not the Merger is completed, such as legal, accounting, financial advisor and printing fees;

·	Southern Union would not realize the expected benefits of the Merger;

·	under the Merger Agreement, Southern Union is subject to certain restrictions on the conduct of its business prior to completing the Merger which may adversely affect its ability to execute certain of its business strategies; and

·	matters relating to the Merger may require substantial commitments of time and resources by Southern Union management, which could otherwise have been devoted to other opportunities that may have been beneficial to Southern Union as an independent company.

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In addition, if the Merger is not completed, Southern Union may experience negative reactions from the financial markets and from its customers and employees. Southern Union also could be subject to litigation related to any failure to complete the Merger or to enforcement proceedings commenced against Southern Union to attempt to force it to perform its obligations under the Merger Agreement.

Pending litigation against ETE and Southern Union could result in the payment of damages in the event the Merger is completed and/or may adversely affect the combined company’s business, financial condition or results of operations following the Merger.

In connection with the Merger, purported stockholders of Southern Union have filed several stockholder class action lawsuits against Southern Union, Merger Sub, ETE and the Southern Union Board in the District Courts of Harris County, Texas and in the Delaware Courts of Chancery. If a final settlement is not reached, or if a dismissal is not obtained, these lawsuits could result in substantial costs to ETE and Southern Union, including any costs associated with the indemnification of directors. Additional lawsuits may be filed against Southern Union related to the Merger. The defense or settlement of any lawsuit or claim that remains unresolved at the time the Merger is completed may adversely affect the combined company’s business, financial condition or results of the operations.

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, 2011, consolidated debt on the Consolidated Balance Sheet totaled $3.5 billion outstanding, compared to total capitalization (long- and short-term debt plus stockholders' equity) of $6.14 billion.

Some of the Company’s debt obligations contain financial covenants concerning debt-to-capital ratios and interest coverage ratios. The Company’s failure to comply with any of these covenants could result in an event of default which, if not cured or waived, could result in the acceleration of outstanding debt obligations or render it unable to borrow under certain credit agreements. 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, because of the need for certain state regulatory approvals in order to incur long-term debt and issue capital stock, the Company may not be able to access the capital markets on a timely basis. 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.

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

As of December 31, 2011, both Southern Union’s and Panhandle’s debt were rated BBB- by Fitch Ratings, Baa3 by Moody's Investor Services, Inc. and BBB- by Standard & Poor's. Due to the merger activities involving the Company, Standard and Poor’s has placed Southern Union and Panhandle on Credit Watch with developing implications, Moody’s has revised its outlook on Southern Union’s debt from stable to negative, and Fitch has placed Southern Union and Panhandle on Rating Watch Negative. 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 are downgraded below investment grade or if there are times when it is placed on "credit watch," the Company could be negatively impacted as follows:

·	Borrowing costs associated with existing debt obligations could increase annually up to approximately $6.6 million 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 being placed on credit watch or 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 the recent disruptions in the financial markets and other 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 and joint ventures 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.

The Company owns 50 percent of Citrus, the holding company for Florida Gas. As such, the Company cannot control or guarantee the receipt of distributions from Florida Gas through Citrus.

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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.

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. To the extent it issues shares of capital stock or other rights to purchase capital stock, including options or other rights, existing stockholders may be diluted and earnings per share may decrease. 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.

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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 and Florida Gas. 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.

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 and Florida Gas 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, Florida Gas 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.

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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.

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, Florida Gas 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 and Florida Gas, which generally have 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.

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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.

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

As of December 31, 2011, approximately 765 of the Company’s 2,437 employees were represented by collective bargaining units under collective bargaining agreements. In the coming months, the Company anticipates participating in discussions with United Steel Workers Local 348 with respect to the renewal of a collective bargaining agreement that expires on May 27, 2012. This collective bargaining unit currently includes approximately 219 PEPL employees. The Company cannot predict the results of any such collective bargaining negotiations or whether any such negotiations will result in a work stoppage. 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.

A 2009 EPA determination that emissions of carbon dioxide and other “greenhouse gases” present an endangerment to public health could result in regulatory initiatives that increase the Company’s costs of doing business and the costs of its services.

On April 17, 2009, the EPA issued a notice of its proposed finding and determination that emissions of carbon dioxide, methane, and other GHGs presented an endangerment to human health and the environment because emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. Once finalized, EPA’s finding and determination would allow the agency to begin regulating GHG emissions under existing provisions of the Clean Air Act. In late September 2009, EPA announced two sets of proposed regulations in anticipation of finalizing its findings and determination, one rule to reduce emissions of GHGs from motor vehicles and the other to control emissions of GHGs from stationary sources. The motor vehicle rule was adopted in March 2010, and the stationary source permitting rule was promulgated in May 2010. It may take the EPA several years to impose regulations limiting emissions of GHGs from existing stationary sources due to legal challenges on the stationary rule. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including the Company’s processing plants and many compressor stations, beginning in 2011 for emissions occurring in 2010. Any limitation imposed by the EPA on GHG emissions from the Company’s natural gas–fired compressor stations and processing facilities or from the combustion of natural gas or natural gas liquids that it produces could increase its costs of doing business and/or increase the cost and reduce demand for its services.

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The adoption of climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the products and services the Company provides.

The Kyoto Protocol was adopted in 1997 by the United Nations to address global climate change by reducing emissions of carbon dioxide and other greenhouse gases. The treaty went into effect on February 16, 2005. The United States has not adopted the Kyoto Protocol. However, on June 26, 2009, the United States House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” ( ACESA ), which would establish an economy-wide cap-and-trade program in the United States to reduce emissions of GHGs, including carbon dioxide and methane that may be contributing to warming of the Earth’s atmosphere and other climatic changes. ACESA would require an overall reduction in GHG emissions of 17 percent (from 2005 levels) by 2020, and by over 80 percent by 2050. Under ACESA, covered sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet ACESA’s overall emission reduction goals. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The net effect of ACESA would be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, natural gas and NGLs.

The United States Senate attempted to pass its own legislation for controlling and reducing emissions of GHGs in the United States. The Senate failed to adopt GHG legislation in the last Congress. It is not possible to predict if the current or a future Congress will propose or pass climate change legislation as robust as the 2009 ACESA. President Obama has indicated that he continues to support the adoption of legislation to control and reduce emissions of GHGs through an emission allowance permitting system that results in fewer allowances being issued each year but that allows parties to buy, sell and trade allowances as needed to fulfill their GHG emission obligations. Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require the Company to incur increased costs. Further, current or future rate structures or shipper or producer contracts and prevailing market conditions might not allow the Company to recover the additional costs incurred to comply with such laws and/or regulations and may affect the Company’s ability to provide services. While the Company may be able to include some or all of such increased costs in its rate structures or shipper or producer contracts, such recovery of costs is uncertain and may depend on events beyond the Company’s control. Such matters could have a material adverse effect on demand for the Company’s gathering, treating, processing, distribution or transportation services.

Even if such legislation is not adopted at the national level, more than one-third of the states have begun taking actions to control and/or reduce emissions of GHGs, with most of the state-level initiatives focused on large sources of GHG emissions, such as coal-fired electric plants. It is possible that smaller sources of emissions could become subject to GHG emission limitations or allowance purchase requirements in the future. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on the Company’s business, financial condition, results of operations and cash flows.

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.

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The Company’s businesses require the retention and recruitment of a skilled workforce and the loss of employees could result in the failure to implement its business plans.

The Company’s businesses require the retention and recruitment of a skilled workforce including engineers and other technical personnel. If the Company is unable to retain its current employees (many of whom are retirement eligible) or recruit new employees of comparable knowledge and experience, the Company’s business could be negatively impacted.

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 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.

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RISKS 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 and Florida Gas 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.

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 the Company’s Southwest Gas Storage Company. If FERC were to initiate a Section 5 proceeding against the Company and find that the Company’s rates at that time were not just and reasonable due to a lower rate base, reduced or disallowed operating costs, or other factors, the applicable maximum rates the Company is allowed to charge customers could be reduced and the reduction could potentially have a material adverse effect on the Company’s business, financial condition, results of operations or cash flows. 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 Florida Gas or 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.

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The pipeline businesses are subject to competition.

The interstate pipeline businesses of Panhandle and Florida Gas 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 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 and Florida Gas.

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 and Florida Gas 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 percent of its 2011 revenue. Florida Gas’ top two customers accounted for 59 percent of its 2011 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.

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.

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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 Item 8. Financial Statements and Supplementary Data – Note 11 Derivative Instruments and Hedging Activities – Gathering and Processing Segment .

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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 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, 2011 accounted for approximately 29 percent 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 year ended December 31, 2011, Conoco accounted for approximately 27 percent and 62 percent of the Company’s and SUGS’ operating revenues, respectively.

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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 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 EBIT 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, 2011, the Company’s regulatory assets recorded in its Consolidated Balance Sheet totaled $57.4 million. 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. For additional information related to management’s assessment of the probability of recovery or pass through of regulatory asset costs to its customers, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Other Matters – Critical Accounting Policies – Effects of Regulation .

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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;

·	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;

the likelihood and timing of the completion of the proposed merger with ETE, the terms and conditions of any required regulatory approvals of the proposed merger, the impact of the proposed merger on Southern Union’s employees and potential diversion of the management’s time and attention from ongoing business during this time period; 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.

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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.

N/A

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.

The Company’s other businesses primarily consist of PEI Power Corporation, a wholly-owned subsidiary of the Company, which has ownership interests in four electric power plants that share a site in Archbald, Pennsylvania. PEI Power Corporation wholly owns a 25 megawatt electric cogeneration facility fueled by a combination of natural gas and methane, and owns two 4.6 megawatt electric generation facilities fueled by methane. PEI Power Corporation also owns 49.9 percent of a 45 megawatt natural gas-fired electric generation facility, through a joint venture with Cayuga Energy.

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ITEM 3. Legal Proceedings.

The Company and certain of its affiliates are occasionally parties to lawsuits and administrative proceedings incidental to their businesses involving, for example, claims for personal injury and property damage, contractual matters, various tax matters, and rates and licensing. The Company and its affiliates are also subject to various federal, state and local laws and regulations relating to the environment, as described in Item 1. Business . 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 Item 8, Financial Statements and Supplementary Data, Note 19 – Regulation and Rates and Note 15 – Commitments and Contingencies. Also see Item 1A. Risk Factors – Cautionary Notes Regarding Forward-Looking Statements .

ITEM 4 . Mine Safety Disclosures.

N/A

PART II

ITEM 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

MARKET INFORMATION

Southern Union’s common stock is traded on the New York Stock Exchange under the symbol “SUG.” The high and low sales prices for shares of Southern Union common stock and the cash dividends per share declared in each quarter since January 1, 2010 are set forth below.

	Dollars per share
	High		Low		Dividends

December 31, 2011	$	42.91	$	38.43	$	0.15
September 30, 2011		44.65		38.41		0.15
June 30, 2011		41.68		27.18		0.15
March 31, 2011		29.24		24.18		0.15

December 31, 2010	$	25.96	$	23.60	$	0.15
September 30, 2010		24.83		21.12		0.15
June 30, 2010		26.68		20.00		0.15
March 31, 2010		26.03		21.64		0.15

Provisions in certain of Southern Union’s long-term debt and bank credit facilities limit the issuance of dividends on capital stock. Under the most restrictive provisions in effect, Southern Union may not declare or issue any dividends on its common stock or acquire or retire any of Southern Union’s common stock, unless no event of default exists and the Company meets certain financial ratio requirements, which presently are met. Southern Union’s ability to pay cash dividends may be limited by certain debt restrictions at Panhandle and Citrus that could limit Southern Union’s access to funds from Panhandle and Citrus for debt service or dividends. For additional related information, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Financing Activities – Dividend Restrictions and Item 8. Financial Statements and Supplementary Data, Note 16 – Stockholders’ Equity and Note 8 – Debt Obligations .

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COMMON STOCK PERFORMANCE GRAPH

The following performance graph compares the performance of Southern Union’s common stock to the Standard & Poor’s 500 Stock Index (“S&P 500 Index”) and the Bloomberg U.S. Pipeline Index. The comparison assumes $100 was invested on December 31, 2006, in Southern Union common stock, the S&P 500 Index and the Bloomberg U.S. Pipeline Index. Each case assumes the reinvestment of dividends.

	2006		2007		2008		2009		2010		2011
Southern Union		100		107		49		88		95		170
S&P 500 Index		100		105		67		84		97		99
Bloomberg U.S. Pipeline Index		100		118		72		103		126		174

The following companies are included in the Bloomberg U.S. Pipeline Index used in the graph: El Paso Corp., Enbridge, Inc., Oneok, Inc., Spectra Energy Corp., TransCanada Corp., and The Williams Companies, Inc.

HOLDERS

As of February 17, 2012, there were 5,299 holders of record of Southern Union’s common stock, and 124,854,997 shares of Southern Union’s common stock were issued and outstanding. The holders of record do not include persons whose shares are held of record by a bank, brokerage house or clearing agency, but do include any such bank, brokerage house or clearing agency that is a holder of record.

EQUITY COMPENSATION PLANS

Equity compensation plans approved by stockholders include the Southern Union Company Third Amended and Restated 2003 Stock and Incentive Plan and the 1992 Long-Term Stock Incentive Plan ( 1992 Plan ). While Southern Union options are still outstanding under the 1992 Plan, the 1992 Plan expired on July 1, 2002 and no shares are outstanding or available for future grant thereunder. Under both plans, stock options and SARs are issued having an exercise price equal to the fair market value of the Company’s common stock on the date of grant. Stock options typically vest ratably over three, four or five years and SARs vest over three years.

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The following table sets forth information regarding the Company’s equity compensation plans approved by security holders as of December 31, 2011.

	Number of Securities
	to Be Issued Upon	Weighted Average		Number of Securities
	Exercise of	Exercise Price of		Remaining Available for
	Outstanding	Outstanding		Future Issuance Under
	Options/SARs	Options/SARs		Equity Compensation Plans


Plans approved by stockholders	4,442,886 (1), (2)	$	21.40	3,637,271

______________

(1) Excludes 185,851 shares of restricted stock that were outstanding at December 31, 2011.

(2) Assumes the number of securities issued from the exercise of SARs outstanding equals the appreciation from the award's grant date to December 31, 2011.

For additional information related to the Company’s equity compensation plans, see Item 8. Financial Statements and Supplementary Data, Note 14 – Stock-Based Compensation .

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table presents information with respect to purchases during the three months ended December 31, 2011 made by Southern Union or any “affiliated purchaser” of Southern Union (as defined in Rule 10b-18(a)(3)) of equity securities that are registered pursuant to Section 12 of the Exchange Act.

	Total Number		Average
	of Shares		Price Paid
	Purchased (1)		per Share

Month Ended October 31, 2011		2,136	$	40.84
Month Ended November 30, 2011		17		41.68
Month Ended December 31, 2011		65,130		41.90
Total		67,283	$	41.87

______________

(1) The total number of shares purchased includes: (i) the surrender to the Company of 57,794 shares of common stock to satisfy tax withholding obligations in connection with the vesting of restricted stock awards and exercise of stock appreciation rights and (ii) 9,489 shares of common stock purchased in open-market transactions and held in various Company employee benefit plan trusts by the trustees using cash amounts deferred by the participants in such plans (and quarterly cash dividends issued by the Company on shares held in such plans).

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ITEM 6. SELECTED FINANCIAL DATA.

	Years Ended December 31,
	2011		2010			2009		2008		2007

	(In thousands, except per share amounts)

Total operating revenues	$	2,665,954	$	2,489,913		$	2,179,018	$	3,070,154	$	2,616,665
Earnings from unconsolidated
investments		98,935		105,415			80,790		75,030		100,914
Net earnings (loss):
Continuing operations		255,424		242,648			179,580		295,151		228,711
Discontinued operations (1)		-		(18,100	)		-		-		-
Available for common stockholders		255,424		216,213			170,897		279,412		211,346
Net earnings (loss) per diluted
common share: (2)
Continuing operations		2.02		1.87			1.37		2.26		1.75
Discontinued operations		-		(0.14	)		-		-		-
Available for common stockholders		2.02		1.73			1.37		2.26		1.75
Total assets		8,270,859		8,238,543			8,075,074		7,997,907		7,397,913
Stockholders’ equity		2,639,611		2,526,982			2,469,946		2,367,952		2,205,806
Current portion of long-term debt		343,254		1,083			140,500		60,623		434,680
Long-term debt, excluding current portion		3,160,372		3,520,906			3,421,236		3,257,434		2,960,326
Cash dividends declared on common
stock		74,847		74,701			74,481		74,384		53,968

___________________

(1)

On August 24, 2006, the Company completed the sales of the assets of its PG Energy natural gas distribution division to UGI Corporation and the Rhode Island operations of its New England Gas Company natural gas distribution division to National Grid USA. These dispositions were accounted for as discontinued operations in the Consolidated Statement of Operations. In 2010, the Company recorded an estimated $18.1 million charge to earnings related to the 2006 discontinued operations. See Item 8. Financial Statements and Supplementary Data, Note 23 – Discontinued Operations for more information.

(2)	Earnings per share for all periods presented were computed based on the weighted average number of shares of common stock and common stock equivalents outstanding during the period.

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ITEM 7 . Management’s Discussion and Analysis of Financial Condition and Results of Operations.

INTRODUCTION

This Management’s Discussion and Analysis of Financial Condition and Results of Operations is provided as a supplement to the accompanying consolidated financial statements and notes to help provide an understanding of the Company’s financial condition, changes in financial condition and results of operations. The following section includes an overview of the Company’s business as well as recent developments that management of the Company believes are important in understanding its results of operations, and anticipating future trends in those operations. Subsequent sections include an analysis of the Company’s results of operations on a consolidated basis and on a segment basis for each reportable segment, and information relating to the Company’s liquidity and capital resources, quantitative and qualitative disclosures about market risk and other matters.

The Company’s business purpose is to provide gathering, processing, transportation, storage and distribution of natural gas and NGL in a safe, efficient and dependable manner. The Company’s reportable business segments are determined 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.

BUSINESS STRATEGY

The Company’s strategy is focused on achieving profitable growth and enhancing stockholder value. The Company seeks to balance its entrepreneurial focus with respect to maximizing cash and capital appreciation return to stockholders with preservation of its investment grade credit ratings. The key elements of its strategy include the following:

Expanding through development of the Company’s existing businesses. The Company will continue to pursue growth opportunities through the expansion of its existing asset base, while maintaining its focus on providing safe and reliable service to its customers. In each of its business segments, the Company identifies opportunities for organic growth through incremental volumes and system enhancements to generate operating efficiencies. In its transportation and distribution businesses, the Company seeks rate increases and/or improved rate design, as appropriate, to achieve a fair return on its investment. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Investing Activities for information related to the Company’s principal capital expenditure projects. See Item 8. Financial Statements and Supplementary Data, Note 19 – Regulation and Rates for information related to ratemaking activities.

·	New initiatives. The Company regularly assesses strategies to enhance stockholder value, including diversification of earning sources through strategic acquisitions or joint ventures in the diversified natural gas industry.

·	Disciplined capital expenditures and cost containment programs. The Company will continue to focus on system optimization and cost savings while making prudent capital expenditures across its base of energy infrastructure assets.

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RESULTS OF OPERATIONS

Overview

The Company evaluates operational and financial segment performance in its Transportation and Storage, Gathering and Processing, and Distribution segments using several factors, of which the primary financial measure is EBIT, a non-GAAP measure. The Company defines EBIT as Net earnings available for common stockholders , adjusted for the following:

·	items that do not impact net earnings, such as extraordinary items, discontinued operations and the impact of changes in accounting principles;

·	income taxes;

interest;

·	dividends on preferred stock; and

·	loss on extinguishment of preferred stock.

EBIT 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 EBIT (by segment) to Net earnings available for common stockholders for the periods presented.

	Years Ended December 31,
	2011			2010		2009

	(In thousands)
EBIT:
Transportation and storage segment	$	480,775		$	458,273	$	411,935
Gathering and processing segment		50,666			41,756		(40,470	)
Distribution segment		55,364			63,692		67,302
Corporate and other activities		(8,369	)		2,621		9,513
Total EBIT		578,436			566,342		448,280
Interest expense		219,232			216,665		196,800
Earnings from continuing operations before income taxes		359,204			349,677		251,480
Federal and state income taxes		103,780			107,029		71,900
Earnings from continuing operations		255,424			242,648		179,580
Loss from discontinued operations		-			18,100		-
Preferred stock dividends		-			5,040		8,683
Loss on extinguishment of preferred stock		-			3,295		-
Net earnings available for common stockholders	$	255,424		$	216,213	$	170,897

Year ended December 31, 2011 versus the year ended December 31, 2010. The Company’s $39.2 million increase in Net earnings available for common stockholders was primarily due to:

Higher EBIT contribution of $22.5 million from the Transportation and Storage segment as Panhandle’s contribution increased $24.7 million on higher operating revenue of $34.2 million mainly due to the LNG terminal infrastructure enhancement project being placed in service in March 2010, partially offset by lower equity earnings of $2.2 million from the Company’s unconsolidated investment in Citrus;

·	A charge for discontinued operations of $18.1 million in 2010 related to the U.S. Court of Appeals for the First Circuit ( First Circuit ) affirming the Company’s conviction of a RCRA violation in an environmental permitting trial;

Higher EBIT contribution of $8.9 million from the Gathering and Processing segment largely attributable to higher net revenue margin of $19.1 million (unadjusted for the impact of hedges) driven by higher market-driven realized average NGL prices in the 2011 period and the effect of a $6.1 million net hedging loss in 2011 versus $12.7 million in 2010. These increases were partially offset by higher operating expenses of $9.5 million and lower contributions from the investment in Grey Ranch of $4.4 million;

·	Lower preferred stock dividends of $8.3 million due to the Company’s redemption of all of its outstanding shares of preferred stock in July 2010; and

·	Lower federal and state income tax expense of $3.2 million primarily due to the impact of $5.3 million of state investment tax credits recorded in 2011.

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These improvements in earnings were partially offset by:

·	Lower EBIT contribution of $11 million from Corporate and other activities primarily due to legal and other outside service costs related to the potential merger with ETE;

Lower EBIT contribution of $8.3 million from the Distribution segment mainly due to higher operating, maintenance and general expenses of $7 million largely attributable to higher legal, injuries and damages costs of $1.8 million, the impact of a $1.5 million favorable environmental settlement realized in 2010 and higher other operating, maintenance and general expenses of $3.7 million; and

·	Higher interest expense of $2.6 million primarily attributable to the impact of the lower level of interest costs capitalized attributable to lower average capital project balances outstanding in 2011.

Year ended December 31, 2010 versus the year ended December 31, 2009. The Company’s $45.3 million increase in Net earnings available for common stockholders was primarily due to:

Higher EBIT contribution of $82.2 million from the Gathering and Processing segment resulting from higher operating revenues of $243.9 million, excluding hedging gains and losses, attributable to higher market-driven realized average natural gas and NGL prices and the impact of a net hedging loss of $12.7 million in the 2010 period versus a net hedging loss of $44.6 million in the 2009 period, partially offset by a $189.9 million increase in the cost of gas and other energy in the 2010 period due to higher market-driven natural gas and NGL purchase costs and higher fractionation fees related to the change in fractionation provider in 2010; and

Higher EBIT contribution of $46.3 million from the Transportation and Storage segment mainly due to higher equity earnings of $24.8 million from the Company’s unconsolidated investment in Citrus largely driven by higher equity AFUDC resulting from Florida Gas’ Phase VIII Expansion project and a higher contribution from Panhandle of $21.5 million primarily due to higher operating revenue of $20.3 million mainly due to the LNG terminal infrastructure enhancement project being placed in service in March 2010, partially offset by lower parking revenues due to less favorable market conditions and lower transportation reservation revenues primarily due to lower average rates realized on short-term firm capacity on PEPL and lower average rates realized on Trunkline.

These improvements in earnings were partially offset by:

·	Higher interest expense of $19.9 million primarily attributable to the impact of the lower level of interest costs capitalized attributable to lower average capital project balances outstanding in 2010;

·	A charge for discontinued operations of $18.1 million related to the First Circuit affirming the Company’s conviction of a RCRA violation in an environmental permitting trial;

Lower EBIT contribution of $6.9 million from Corporate and other activities primarily due to the impact of $10.8 million of income in 2009 resulting from settlements with insurance companies related to certain environmental matters, partially offset by a higher net sales contribution of $4 million from PEI Power;

Lower EBIT contribution of $3.6 million from the Distribution segment mainly due to lower other income of $7.8 million primarily due to income in 2009 resulting from settlements with insurance companies related to certain environmental matters and higher operating, maintenance and general expenses of $7.5 million, partially offset by higher net operating revenues of $13.8 million largely attributable to the impact of new customer rates at Missouri Gas Energy effective February 28, 2010; and

·	Higher federal and state income tax expense of $35.1 million primarily due to higher pre-tax earnings from continuing operations of $98.2 million in 2010.

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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 and from the Gulf Coast to Florida, and LNG terminalling and regasification services. The Transportation and Storage segment’s operations, conducted through Panhandle and Florida Gas, are regulated as to rates and other matters by FERC. Demand for natural gas transmission services on Panhandle’s pipeline systems is seasonal, with the highest throughput and a higher portion of annual total operating revenues and EBIT 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.

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, 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. For additional information related to Transportation and Storage segment risk factors and the weighted average remaining lives of firm transportation and storage contracts, see Item 1A. Risk Factors – Risks that Relate to the Company’s Transportation and Storage Business and Item 1. Business – Business Segments – Transportation and Storage Segment , respectively.

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

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

	Years Ended December 31,
	2011		2010			2009

	(In thousands)

Operating revenues (1)	$	803,650	$	769,450		$	749,161

Operating, maintenance and general		258,388		252,007			265,901
Depreciation and amortization		128,011		123,009			113,648
Taxes other than on income and revenues		34,854		36,065			34,539
Total operating income		382,397		358,369			335,073
Earnings from unconsolidated investments		97,775		99,991			75,205
Other income, net		603		(87	)		1,657
EBIT	$	480,775	$	458,273		$	411,935

Panhandle natural gas volumes transported (Tbtu) (2)
PEPL		564		563			676
Trunkline		743		664			683
Sea Robin		113		172			132
Florida Gas natural gas volumes transported (3)		864		835			821

_____________

(1)	Reservation revenues comprised 89 percent, 88 percent and 83 percent in the years ended December 31, 2011, 2010, and 2009, respectively.

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

(3)	Represents 100 percent of Florida Gas natural gas volumes transported versus the Company’s effective equity ownership interest of 50 percent.

See Item 1. Business – Business Segments – Transportation and Storage Segment for additional related operational and statistical information associated with the Transportation and Storage segment.

Year ended December 31, 2011 versus the year ended December 31, 2010. The $22.5 million EBIT improvement in the year ended December 31, 2011 versus the same period in 2010 was primarily due to a higher EBIT contribution from Panhandle totaling $24.7 million, partially offset by lower equity earnings of $2.2 million, mainly from the Company’s unconsolidated investment in Citrus.

Panhandle’s $24.7 million EBIT improvement was mainly due to:

·	Higher operating revenues of $34.2 million primarily due to:

o	Higher LNG revenues of $20.6 million in 2011 versus 2010 primarily due to the LNG terminal infrastructure enhancement project placed in service in March 2010; and

o	Increased transportation and storage revenues of $12.4 million primarily attributable to:

·	Customer contract buyout revenues received by PEPL primarily in the fourth quarter of 2011 of approximately $13.9 million on four contracts with average remaining terms of approximately four years;

·	Higher transportation reservation revenues of $7.2 million primarily due to higher short-term capacity sold based on operational availability and increased Trunkline supply area capacity sold; and

·	Lower parking revenues of $7.3 million due to less favorable market conditions;

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·	Higher operating, maintenance and general expenses of $6.4 million in 2011 versus 2010 primarily attributable to:

o	Impact of a net reduction in 2010 in the repair and abandonment expenses for Hurricane Ike of $12.2 million primarily due to insurance recoveries, project scope reductions, favorable weather conditions experienced, and realized project efficiencies;

o	A $3 million increase in fuel tracker costs primarily due to a net under-recovery in 2011 versus an over-recovery in 2010;

o	A $1.8 million increase in benefit expenses primarily due to higher medical costs;

o	Higher compensation expense of $1.7 million largely due to mark-to-market adjustments for liability stock-based compensation awards (settled in cash) resulting from an increase in the Southern Union stock price impacted by the potential merger with ETE; and

o	A $13.3 million reduction in legal expenses primarily resulting from the settlement, in the second quarter of 2011, of certain litigation with several contractors related to the Company’s East End project, which settlement includes a prior year expense recovery of $9.4 million; and

Increased depreciation and amortization expense of $5 million in 2011 versus 2010 primarily due to the LNG terminal infrastructure enhancement project placed in service in March 2010 and a $93.3 million increase in property, plant and equipment placed in service after December 31, 2010. Depreciation and amortization expense is expected to continue to increase primarily due to ongoing capital additions.

The capacity associated with the contract buyouts, which had been requested by two customers, is available for sale to PEPL’s other customers at market rates. Such resold capacity may be lower than the approximately $4.1 million annual amount that would have been received from the four prior contracts. PEPL and Trunkline have also extended and restructured certain other contracts with a customer resulting in an additional term of 5 years at fixed rates, offset by lower current rates, which will result in an estimated $5.6 million reduction in 2012 reservation revenues versus 2011 levels.

Equity earnings, mainly attributable to the Company’s unconsolidated investment in Citrus, were lower by $2.2 million in 2011 versus 2010 primarily due to the following items, adjusted where applicable to reflect the Company’s proportional equity share in Citrus:

·	Higher transportation revenues of $87.7 million primarily due to placing Florida Gas’ Phase VIII Expansion project into service on April 1, 2011;

·	Lower other income of $39.6 million largely driven by lower equity AFUDC due to placing the Phase VIII Expansion project into service on April 1, 2011;

Higher interest expense of $23.5 million primarily due to the issuance of $500 million 5.45% Senior Notes and $350 million 4.00% Senior Notes in July 2010 and lower capitalized debt AFUDC mainly due to placing the Phase VIII Expansion project into service, partially offset by the repayment of the $325 million 7.625% Senior Notes in August 2010;

·	Higher operating expenses of $11.4 million mainly due to the Phase VIII Expansion project being placed into service and pipeline integrity assessments; and

·	Higher depreciation expense of $15.9 million primarily due to completion of the Phase VIII Expansion project.

Citrus property taxes are anticipated to increase effective January 1, 2012 due to the Phase VIII assets being completed and placed in service in April 2011.

See Part I, Item 8. Financial Statements and Supplementary Data, Note 3 – ETE Merger and Note 6 – Unconsolidated Investments – Contingent Matters Potentially Impacting Southern Union Through the Company’s Investment in Citrus for additional information related to Citrus and Florida Gas.

Year ended December 31, 2010 versus the year ended December 31, 2009. The $46.3 million EBIT improvement in the year ended December 31, 2010 versus the same period in 2009 was primarily due to higher equity earnings of $24.8 million, mainly from the Company’s unconsolidated investment in Citrus and a higher EBIT contribution from Panhandle totaling $21.5 million.

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Equity earnings, mainly attributable to the Company’s unconsolidated investment in Citrus, were higher by $24.8 million in 2010 versus 2009 primarily due to the following items, adjusted where applicable to reflect the Company’s proportional equity share in Citrus:

·	Higher other income of $42.5 million largely driven by higher equity AFUDC resulting from Florida Gas’ Phase VIII Expansion project;

Higher operating revenues of $4.3 million primarily due to higher reservation revenues related to certain higher rates effective April 1, 2010 associated with the Florida Gas 2009 rate case filing, adjusted by a provision for estimated rate refunds based on settlement rates approved by FERC. The increase in reservation revenues was partially offset by lower transportation commodity revenues primarily due to lower interruptible contract utilization by customers;

·	Higher operating expenses of $6.4 million primarily due to higher overall costs experienced in 2010 applicable to outside service costs and corporate service costs;

·	Lower depreciation expense of $1.6 million primarily due to reduced depreciation rates associated with the rate case filing effective April 1, 2010, partially offset by the impact of an increase in property, plant and equipment placed in service after December 31, 2009; and

·	Higher income tax expense of $17 million primarily due to higher pretax earnings.

See Item 8. Financial Statements and Supplementary Data, Note 6 – Unconsolidated Investments – Citrus for additional information related to Citrus and Florida Gas.

Panhandle’s $21.5 million EBIT improvement was primarily due to:

·	Higher operating revenues of $20.3 million primarily due to:

o	Higher LNG revenues of $65.2 million largely attributable to the LNG terminal infrastructure enhancement construction project placed in service in March 2010;

o	Higher transportation commodity revenues of $2.5 million primarily due to higher volumes flowing on Sea Robin in 2010 versus 2009, the 2009 volumes having been adversely impacted by Hurricane Ike;

o	Lower interruptible parking revenues of $36.9 million primarily due to less favorable market conditions resulting in lower rates in 2010; and

o	Lower transportation reservation revenues of $13.4 million in 2010 versus 2009 primarily due to lower short-term firm capacity sold and at lower rates on PEPL, in addition to lower average rates realized on Trunkline; and

·	Lower operating, maintenance and general expenses of $13.9 million in 2010 versus 2009 primarily attributable to:

Impact of provisions for repair and abandonment costs of $10.2 million recorded in 2009 for damages to offshore assets resulting from Hurricane Ike and a net reduction in 2010 in the repair and abandonment expenses for Hurricane Ike of $12.2 million primarily due to insurance recoveries, project scope reductions, favorable weather conditions experienced, and realized project efficiencies;

o	Impact of a $3.8 million increase in environmental reserves in 2009 primarily attributable to estimated costs to remediate PCBs at the Company’s facilities;

o	A $3.6 million decrease in fuel tracker costs primarily due to a net over-recovery in 2010 versus a net under-recovery in 2009;

o	A $3.1 million decrease in contract storage costs primarily due to a contract termination in March 2010;

A $7.9 million increase in outside service costs for field operations primarily attributable to higher in-line inspection costs in 2010 due to testing to meet pipeline safety requirements and plant services related to the LNG terminal infrastructure enhancement construction project placed in service in March 2010;

o	Higher allocated corporate service costs of $6.7 million primarily due to higher short- and long-term corporate incentive compensation; and

o	A $6.4 million increase in expense due to the impact of a provision reversal in 2009 related to past take-or-pay settlement contractual indemnities for which performance by the Company has not been required.

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The operating revenue improvement was partially offset by:

·	Increased depreciation and amortization expense of $9.4 million in 2010 versus 2009 due to a $598.6 million increase in property, plant and equipment placed in service after December 31, 2009, most significantly the LNG terminal infrastructure enhancement project placed in service in March 2010.

See Item 8. Financial Statements and Supplementary Data, Note 15 – Commitments and Contingencies – Other Commitments and Contingencies – 2008 Hurricane Damage for additional information related to the repair and abandonment provisions and insurance recovery resulting from hurricane damage.

Gathering and Processing Segment. The Gathering and Processing segment is primarily engaged in connecting producing wells of E&P 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 E&P companies, power generating companies, electric and gas utilities, energy marketers, industrial end-users located primarily in the Gulf Coast and southwestern United States, and petrochemicals. 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 E&P 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 Item 8. Financial Statements and Supplementary Data, Note 11 – Derivative Instruments and Hedging Activities – Commodity Contracts – Gathering and Processing Segment and Item 7A. Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk – Gathering and Processing Segment .

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

	Years Ended December 31,
	2011			2010			2009

	(In thousands)

Operating revenues, excluding impact of
commodity derivative instruments	$	1,185,753		$	1,020,758		$	776,835
Realized and unrealized commodity derivatives		(6,073	)		(12,735	)		(44,584	)
Operating revenues		1,179,680			1,008,023			732,251
Cost of natural gas and other energy (1)		(960,571	)		(814,712	)		(624,772	)
Gross margin (2)		219,109			193,311			107,479
Operating, maintenance and general		89,796			80,272			80,243
Depreciation and amortization		72,756			70,056			66,690
Taxes other than on income and revenues		5,781			5,734			5,342
Total operating income		50,776			37,249			(44,796	)
Earnings (loss) from unconsolidated investments		(248	)		4,145			4,410
Other income, net		138			362			(84	)
EBIT	$	50,666		$	41,756		$	(40,470	)

Operating Information:
Volumes
Avg natural gas processed (MMBtu/d)		417,398			430,683			401,715
Avg NGL produced (gallons/d)		1,474,648			1,463,827			1,325,052
Avg natural gas wellhead volumes (MMBtu/d)		488,109			530,156			566,472
Natural gas sales (MMBtu) (3)		72,353,292			81,760,690			89,690,706
NGL sales (gallons) (3)		663,945,640			631,248,301			589,020,090

Average Pricing
Realized natural gas ($/MMBtu) (4)	$	3.86		$	4.19		$	3.43
Realized NGL ($/gallon) (4)		1.33			1.05			0.78
Natural Gas Daily WAHA ($/MMBtu)		3.91			4.21			3.47
Natural Gas Daily El Paso ($/MMBtu)		3.87			4.15			3.41
Estimated plant processing spread ($/gallon)		0.97			0.65			0.47

________________

(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 more 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)

Volumes processed by SUGS include volumes sold under various buy-sell arrangements. For the years ended December 31, 2010 and 2009, the Company’s operating revenues and related volumes attributable to its buy-sell arrangements for natural gas totaled $38.1 million and $41.4 million, and 7.8 million MMBtus and 11.7 million MMBtus, respectively. The buy-sell arrangements for natural gas terminated in November 2010. The Company’s operating revenues and related volumes attributable to its buy-sell arrangements for NGL totaled $147.8 million, $116.9 million and $69.2 million and 115.2 million gallons, 119.7 million gallons and 91.2 million gallons, for the years ended December 31, 2011, 2010 and 2009, respectively.

(4)	Excludes impact of realized and unrealized commodity derivative gains and losses detailed in the above EBIT presentation.

See Item 1. Business – Business Segments – Gathering and Processing Segment for additional related operational and statistical information associated with the Gathering and Processing segment.

Year ended December 31, 2011 versus the year ended December 31, 2010. The $8.9 million EBIT improvement in the year ended December 31, 2011 versus the same period in 2010 was primarily due to the following items:

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·	Higher gross margin of $25.8 million primarily as the result of:

o	Impact of a net hedging loss of $6.1 million in the 2011 period versus $12.7 million in the 2010 period (which includes the impact of $50,000 of unrealized losses recorded in 2011);

Higher operating revenues of $165 million, excluding hedging gains and losses, largely attributable to higher market-driven realized average NGL prices (unadjusted for the impact of realized and unrealized commodity derivative gains and losses) of $1.33 per gallon in the 2011 period versus $1.05 per gallon in the 2010 period. This increase was partially offset by lower realized average natural gas prices (unadjusted for the impact of realized and unrealized commodity derivative gains and losses) of $3.86 per MMBtu in the 2011 period versus $4.19 per MMBtu in the 2010 period and reduced throughput volumes as a result of processing plant outages and producer well freeze-offs resulting from unusually cold weather in early 2011; and

o	A $145.8 million increase in the cost of gas and other energy in the 2011 period versus the 2010 period mainly due to higher market-driven NGL purchase costs, partially offset by lower natural gas costs in 2011.

These improvements in EBIT were partially offset by:

·	Higher operating, maintenance and general expenses of $9.5 million primarily due to:

o	Higher contract services of $3.1 million primarily associated with the plant down time experienced in early 2011 due to severe cold weather and plant down time experienced in the fourth quarter of 2011 due to a system blockage;

o	An increase in chemicals and lubricants costs of $2.4 million, which generally track with the price of oil;

o	Increased costs of $1.9 million associated with the fire at the Keystone natural gas processing plant in January 2011, including the write-off of property and equipment damaged by the fire; and

o	Higher ongoing litigation costs of $900,000;

·	Lower contribution from the investment in Grey Ranch of $4.4 million resulting from reduced gas flows; and

·	Increased depreciation and amortization expense of $2.7 million in 2011 versus 2010 primarily due to a $98.8 million increase in property, plant and equipment placed in service after December 31, 2010.

Year ended December 31, 2010 versus the year ended December 31, 2009. The $82.2 million EBIT improvement in the year ended December 31, 2010 versus the same period in 2009 was primarily due to the following items:

·	Higher gross margin of $85.8 million primarily as the result of:

Higher operating revenues of $243.9 million, excluding hedging gains and losses, largely attributable to higher market-driven realized average natural gas and NGL prices (unadjusted for the impact of realized and unrealized commodity derivative gains and losses) of $4.19 per MMBtu and $1.05 per gallon in the 2010 period versus $3.43 per MMBtu and $0.78 per gallon in the 2009 period, respectively, partially offset by the impact of lower system volumes as a result of well freeze-offs that occurred in early 2010;

o	A $189.9 million increase in the cost of gas and other energy in the 2010 period versus the 2009 period due to higher market-driven natural gas and NGL purchase costs and higher fractionation fees related to the change in fractionation provider in 2010;

o	Impact of a net hedging loss of $12.7 million in the 2010 period versus a net hedging loss of $44.6 million in the 2009 period (which includes the impact of $18.5 million of unrealized losses recorded in 2010); and

o	Impact of an approximately $4.9 million reduction in gross margin in 2009 attributable to a fire on July 17, 2009 at the Keystone processing plant resulting in a production outage until August 1, 2009 and $3.2 million of associated business interruption insurance recoveries in the 2010 period;

·	Lower operating, maintenance and general expenses of $29,000 primarily due to:

o	Impact of a $4.6 million net loss in 2009 versus 2010 resulting from the write-off of property and equipment damaged by the fire at the Keystone natural gas processing plant in 2009;

o	Higher benefits, labor, and allocated corporate services costs of $2.8 million primarily due to higher short-term and long-term incentive compensation; and

o	Higher contract services, chemicals and lubricants, labor, and other operating costs of $1.7 million primarily associated with the previously idled Mi Vida treater, which was returned to service during the first quarter of 2010; and

·	Higher depreciation and amortization expense of $3.4 million primarily attributable to a $54.8 million increase in property, plant and equipment placed in service after December 31, 2009.

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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 Distribution segment’s operations are regulated by the public utility regulatory commissions of the states in which each operates. For information related to the status of current rate filings relating to the Distribution segment, see Item 1. Business – Business Segments – Distribution Segment . 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 EBIT occurring in the traditional winter heating season during the first and fourth calendar quarters. On February 10, 2010, the MPSC issued an order approving continued use of a distribution rate structure that eliminates the impact of weather and conservation for Missouri Gas Energy’s residential margin revenues and related earnings and approving expanded use of that distribution rate structure for Missouri Gas Energy’s small general service customers, effective February 28, 2010. Together, Missouri Gas Energy’s residential and small general service customers comprised 99 percent of its total customers and approximately 91 percent of its net operating revenues as of February 28, 2010. For additional information related to rate matters within the Distribution segment, see Item 8. Financial Statements and Supplementary Data, Note 19 – Regulation and Rates – Missouri Gas Energy and New England Gas Company.

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

	Years Ended December 31,
	2011		2010			2009

	(In thousands)

Net operating revenues (1)	$	233,918	$	235,171		$	221,387

Operating, maintenance and general		132,853		125,847			118,338
Depreciation and amortization		33,445		32,544			31,269
Taxes other than on income
and revenues		12,297		12,781			11,925
Total operating income		55,323		63,999			59,855
Other income (expenses), net		41		(307	)		7,447
EBIT	$	55,364	$	63,692		$	67,302

Operating Information:
Natural gas sales volumes (MMcf)		55,123		56,522			56,779
Natural gas transported volumes (MMcf)		24,119		27,218			26,212

Weather – Degree Days: (2)
Missouri Gas Energy service territories		5,183		5,033			4,985
New England Gas Company service territories		5,162		5,288			5,633

___________________________

(1) Operating revenues for the Distribution segment are 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.

See Item 1. Business – Business Segments – Distribution Segment for additional related operational and statistical information related to the Distribution segment.

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Year ended December 31, 2011 versus the year ended December 31, 2010. The $8.3 million EBIT reduction in the year ended December 31, 2011 versus the same period in 2010 was primarily due to:

·	Higher operating, maintenance and general expenses of $7 million primarily attributable to:

o	Higher legal, injuries and damage claims of $1.8 million primarily due to ongoing litigation;

o	Impact of a $2.3 million settlement in 2010 for a previous environmental cost reimbursement claim made by the Company;

o	Higher vehicle fuel costs of $1 million primarily attributable to an increase in gasoline prices;

o	Higher labor costs of $900,000 largely due to merit increases in the 2011 period; and

o	Higher amortized pension costs of $500,000, which were previously being deferred until such costs were included in Missouri Gas Energy’s new rates, which became effective February 28, 2010; and

Lower net operating revenues of $1.3 million primarily due to $4.1 million of lower net operating revenues at Missouri Gas Energy largely attributable to the impact of the new customer rates effective February 28, 2010, which eliminated the impact of weather and conservation for the majority of Missouri Gas Energy’s revenues (resulting in lower reported revenues in the traditional winter heating season), and lower market-driven pipeline capacity release and off-system sales, partially offset by higher net operating revenues of $2.8 million at New England Gas Company mainly due to the impact of new customer rates effective April 1, 2011.

Year ended December 31, 2010 versus the year ended December 31, 2009. The $3.6 million EBIT reduction in the year ended December 31, 2010 versus the same period in 2009 was primarily due to:

·	Lower other income of $7.8 million primarily due to $8.1 million of income in 2009 resulting from settlements with insurance companies related to certain environmental matters; and

·	Higher operating, maintenance and general expenses of $7.5 million primarily attributable to:

o	Higher amortized pension costs of $3.4 million which were deferred until February 28, 2010 when Missouri Gas Energy’s rate case become effective;

o	Higher labor costs of $2.3 million largely due to new positions filled and merit and incentive increases in the 2010 period;

o	Higher provisions for uncollectible customer accounts of approximately $1.1 million mainly resulting from the impact of decreased governmental assistance provided to Missouri Gas Energy’s low income customers;

o	Higher payment processing fees of $1 million at Missouri Gas Energy primarily due to the rate case effective February 28, 2010, which required it to accept customer credit card payments; and

o	Impact of a $2.3 million settlement in 2010 received by the Company associated with an environmental cost reimbursement claim with another company.

These reductions in earnings were partially offset by higher net operating revenues of $13.8 million largely attributable to $15.1 million of higher net operating revenues at Missouri Gas Energy primarily due to the impact of the new customer rates effective February 28, 2010, which eliminated the impact of weather and conservation for the majority of Missouri Gas Energy’s revenues, partially offset by lower revenues of $1.3 million at New England Gas Company primarily due to warmer weather in the 2010 period.

The Company has benefitted from various federal and state governmental programs that have provided home energy assistance to low income customers. During 2011, 2010 and 2009, the Company received, through grants made on behalf of customers, funding from these agencies totaling $8.1 million, $8.9 million and $11.9 million, respectively, which served to reduce the related delinquent accounts receivable balances. If these programs were discontinued or the related funding was significantly reduced and the customers’ ability to pay had not changed, the Company would expect that bad debt expense in the Distribution segment would correspondingly increase.

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Corporate and Other Activities.

Year ended December 31, 2011 versus the year ended December 31, 2010. The EBIT reduction of $11 million was primarily due to legal and other outside service costs of $12.3 million attributable to the potential merger with ETE.

Year ended December 31, 2010 versus the year ended December 31, 2009. The EBIT reduction of $6.9 million was primarily due to:

·	Impact of $10.8 million of income in 2009 primarily resulting from settlements with insurance companies related to certain environmental matters; and

·	A higher net sales margin contribution of $4 million from PEI Power Corporation largely due to increased electric generation primarily attributable to processing of higher landfill gas volumes.

See Item 8. Financial Statements and Supplementary Data, Note 3 – ETE Merger for additional information related to the Company’s potential merger with ETE. On a consolidated basis, the Company recorded merger-related expenses of $15.7 million during the year ended December 31, 2011.

Interest Expense

Year ended December 31, 2011 versus the year ended December 31, 2010. Interest expense was $2.6 million higher in the year ended December 31, 2011 versus the same period in 2010 primarily due to the impact of $5.4 million of lower interest costs capitalized attributable to lower average capital project balances outstanding in 2011 compared to 2010 largely resulting from the LNG infrastructure enhancement project being placed in service in March 2010, partially offset by lower interest expense of $1.6 million resulting from the repayment of the $40.5 million 8.25% Senior Notes in April 2010 and the $100 million 6.089% Senior Notes in February 2010. There were no significant changes in the average interest rates and average debt balances outstanding associated with the Company’s debt obligations in 2011 versus 2010.

Year ended December 31, 2010 versus the year ended December 31, 2009. Interest expense was $19.9 million higher in the year ended December 31, 2010 versus the same period in 2009 primarily due to the impact of $19.1 million of lower interest costs capitalized attributable to lower average capital project balances outstanding in 2010 compared to 2009 largely resulting from the Trunkline LNG infrastructure enhancement project being placed in service in March 2010. There were no significant changes in the average interest rates and average debt balances outstanding associated with the Company’s debt obligations in 2010 versus 2009.

Federal and State Income Taxes from Continuing Operations

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

	Years Ended December 31,
	2011			2010			2009

	(In thousands)

Income tax expense	$	103,780		$	107,029		$	71,900
Effective tax rate (1)		29	%		31	%		29	%

________________

(1)

The EITR is lower than the U.S. federal income tax statutory rate of 35 percent primarily due to the 80 percent dividends received deduction for the anticipated receipt of dividends associated with earnings from the Company’s unconsolidated Citrus affiliate, partially offset by the impact of state income taxes, net of the federal income tax benefit.

Year ended December 31, 2011 versus the year ended December 31, 2010. The $3.2 million decrease of federal and state income tax expense was primarily due to the impact of $5.3 million of state investment tax credits recorded in 2011 and $4.2 million of higher income tax expense in 2010 resulting from the elimination of the Medicare Part D tax subsidy signed into law in March 2010, partially offset by the impact of higher pre-tax earnings for the year ended December 31, 2011 versus 2010.

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Year ended December 31, 2010 versus the year ended December 31, 2009. The $35.1 million increase of federal and state income tax expense was primarily due to higher pre-tax earnings from continuing operations of $98.2 million for the year ended December 31, 2010.

See Item 8. Financial Statements and Supplementary Data, Note 10 – Income Taxes for additional information regarding items impacting the EITR.

Loss from Discontinued Operations

Year ended December 31, 2011 versus the year ended December 31, 2010. The $18.1 million loss recorded in 2010 is due to the First Circuit affirming the Company’s conviction of a RCRA violation in an environmental permitting trial and denying the Company’s petition for an en banc rehearing. See Item 8. Financial Statements and Supplementary Data, Note 23 – Discontinued Operations for additional related information.

Preferred Stock Dividends and Loss on Extinguishment of Preferred Stock

Year ended December 31, 2011 versus the year ended December 31, 2010. The $8.3 million reduction in Preferred stock dividends and Loss on extinguishment of preferred stock for the year ended December 31, 2011 versus the same period in 2010 was due to the impact of the loss of $3.3 million the Company recorded in the 2010 period related to its redemption of all of its 4,600,013 depository shares outstanding representing 460,000 shares of its 7.55% Noncumulative Preferred Stock, Series A (Liquidation Preference $250 per share) ( Preferred Stock ) and the reduction in related dividends of $5 million in the 2011 period versus the 2010 period associated with these redemptions.

Year ended December 31, 2010 versus the year ended December 31, 2009. The $348,000 reduction in Preferred stock dividends and Loss on extinguishment of preferred stock for the year ended December 31, 2010 versus the same period in 2009 was due to the impact of the loss of $3.3 million the Company recorded in the 2010 period related to its redemption of all of its 4,600,013 depository shares outstanding representing 460,000 shares of its Preferred Stock and the reduction in related dividends of $3.6 million in the 2010 period versus the 2009 period associated with these redemptions.

See Item 8. Financial Statements and Supplementary Data, Note 17 – Preferred Securities for additional related information.

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LIQUIDITY AND CAPITAL RESOURCES

Cash generated from internal operations constitutes the Company’s primary source of liquidity. The Company’s working capital deficit at December 31, 2011 is $467.3 million, including $343.3 million of the current portion of long-term debt. Additional sources of liquidity for working capital purposes include the use of available credit facilities and may include various equity offerings, capital markets and bank debt financings, and proceeds from asset dispositions. The availability and terms relating to such liquidity will depend upon various factors and conditions such as the Company’s combined cash flow and earnings, the Company’s resulting capital structure and conditions in the financial markets at the time of such offerings.

Sources (Uses) of Cash

	Years ended December 31,
	2011			2010			2009

				(In thousands)
Cash flows provided by (used in):
Operating activities	$	531,041		$	424,671		$	579,213
Investing activities		(328,033	)		(392,491	)		(419,424	)
Financing activities		(182,667	)		(39,426	)		(153,562	)
Increase (decrease) in cash and cash equivalents	$	20,341		$	(7,246	)	$	6,227

Operating Activities

Year ended December 31, 2011 versus the year ended December 31, 2010. Cash provided by operating activities increased by $106.4 million in the 2011 period versus the same period in 2010. Cash flows provided by operating activities before changes in operating assets and liabilities for the 2011 period were $520.9 million compared with $515.2 million for the 2010 period, an increase of $5.7 million primarily resulting from higher net earnings in 2011. Changes in operating assets and liabilities provided cash of $10.1 million in the 2011 period and used cash of $90.5 million in the 2010 period, resulting in an increase in cash from changes in operating assets and liabilities of $100.6 million in 2011 compared to 2010. The $100.6 million increase is primarily due to:

·	An increase in cash of $55.6 million resulting from lower accounts receivable in the Distribution segment primarily due to the timing of cash receipts from revenues;

·	An increase in cash of $40 million in the Distribution segment associated with recovery of a higher amount of previously deferred natural gas purchase costs from customers in the 2011 period; and

·	An increase in cash of $13 million at Missouri Gas Energy primarily due to the impact of a one-time catch-up contribution to Missouri Gas Energy’s other postretirement benefit plan in the 2010 period in accordance with its approved rate case effective February 8, 2010.

Year ended December 31, 2010 versus the year ended December 31, 2009. Cash provided by operating activities decreased by $154.5 million in the 2010 period versus the same period in 2009. Cash flows provided by operating activities before changes in operating assets and liabilities for the 2010 period were $515.2 million compared with $500.3 million for the 2009 period, an increase of $14.9 million primarily resulting from higher net earnings in 2010. Changes in operating assets and liabilities used cash of $90.5 million in the 2010 period and provided cash of $78.9 million in the 2009 period, resulting in a decrease in cash from changes in operating assets and liabilities of $169.4 million in 2010 compared to 2009. The $169.4 million decrease is primarily due to:

·	Decreased net cash settlements of $88.4 million for commodity derivative instruments in the Gathering and Processing segment in the 2010 period versus the 2009 period; and

·	A decrease in cash of $64.6 million resulting from higher accounts receivable in the Distribution segment primarily due to the timing of cash receipts from revenues.

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Accelerated First-Year Tax Depreciation. As a result of recent federal income tax legislation, bonus depreciation is allowed for the cost of qualified property placed in service after 2007 and before 2014. The majority of such qualifying property has historically been depreciated over a seven- to fifteen-year period. The Company has realized an estimated $90 million tax benefit for the years 2008 through 2011 associated with additional first-year bonus tax depreciation in excess of historical tax depreciation. The amount of tax benefit applicable to years 2012 through 2013 will be subject to the level of qualified property placed in service during those years.

Investing Activities

The Company’s current business strategy includes making prudent capital expenditures across its base of transmission, storage, gathering, processing and distribution assets and growing the businesses through the selective acquisition of assets in order to position itself favorably in the evolving natural gas markets.

Cash flows used in investing activities in the years ended December 31, 2011 and 2010 were $328.0 million and $392.5 million, respectively. The $65 million decrease in investing cash outflows was primarily due to a $100 million equity contribution to Citrus from CrossCountry Citrus, LLC (CrossCountry Citrus), an indirect wholly-owned subsidiary of the Company, in 2010, partially offset by a loan of $37 million to Citrus from CrossCountry Citrus, net of repayments, in 2011 to fund a portion of the Phase VIII Expansion costs.

Cash flows used in investing activities in the years ended December 31, 2010 and 2009 were $392.5 million and $419.4 million, respectively. The $26.9 million decrease in investing cash outflows was primarily due to a $97.8 million decrease in capital expenditures in the Transportation and Storage segment, partially offset by a $100 million equity contribution the Company made to Citrus in 2010 to partially fund the Phase VIII Expansion.

See Item 8. Financial Statements and Supplementary Data, Note 18 – Reportable Segments for information regarding the amount of capital expenditures made by each of the Company’s reportable segments.

Principal Capital Expenditure Projects

The capital replacement and retirement expenditures related to Hurricane Ike, which were substantially completed in 2011, totalled approximately $141 million. Approximately $141 million, $134 million and $110 million of the capital replacement and retirement expenditures were incurred as of December 31, 2011, 2010 and 2009, respectively. The Company anticipates reimbursement from OIL for a significant portion of the damages in excess of its $10 million deductible; however, the recoverable amount is subject to pro rata reduction to the extent that the level of total accepted claims from all insureds exceeds the carrier’s $750 million aggregate exposure limit. OIL announced that it has reached the $750 million aggregate exposure limit and currently calculates its estimated payout amount at 70 percent or less based on estimated claim information it has received. OIL is currently making interim payouts at the rate of 50 percent of accepted claims. As of December 31, 2011, OIL has paid a total of $64.7 million for claims submitted to date by the Company with respect to Hurricane Ike. The final amount of any applicable pro rata reduction cannot be determined until OIL has received and assessed all claims.

Missouri Safety Program. Pursuant to a 1989 MPSC order, Missouri Gas Energy is engaged in a major natural gas safety program in its service territories ( 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 with 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. The Company incurred capital expenditures of $13.8 million, $13.6 million and $14.4 million in 2011, 2010 and 2009, respectively, related to this program and estimates incurring approximately $94.8 million over the next 10 years, after which all service lines, representing about 33 percent of the annual safety program investment, will have been replaced.

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Citrus Sponsor Contributions. In 2011, CrossCountry Citrus and Citrus’ other stockholder each made sponsor contributions of $37 million in the form of loans to Citrus, net of repayments. The Citrus loan has been recorded in Other non-current assets on the Consolidated Balance Sheet. The contributions are related to the costs of Florida Gas’ Phase VIII Expansion project. In conjunction with anticipated sponsor contributions, Citrus has entered into a promissory note in favor of each stockholder for up to $150 million. The promissory notes have a final maturity date of March 31, 2014, with no principal payments required prior to the maturity date, and bear an interest rate equal to a one-month Eurodollar rate plus a credit spread of 1.5 percent. Amounts may be redrawn periodically under the notes to temporarily fund capital expenditures, debt retirements, or other working capital needs.

In 2010, CrossCountry Citrus, an indirect wholly-owned subsidiary of the Company, and Citrus’ other stockholder each made a $100 million sponsor capital contribution in the form of equity to Citrus to partially fund the Phase VIII Expansion. The Company’s $100 million capital contribution was funded using its credit facilities.

For additional information related to the Company’s strategy regarding other growth opportunities, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Business Strategy .

Financing Activities

The Company has historically demonstrated a commitment to strengthen its financial condition and solidify its current investment grade status, as evidenced by the issuance of common stock, equity units, preferred stock and asset sales and use of proceeds therefrom to reduce debt or limit use of debt in conjunction with past acquisitions.

Financing activities used cash flows of $182.7 million and $39.4 million in the years ended December 31, 2011 and 2010, respectively. The $143.2 million increase in net financing cash outflows was primarily due to:

·	Repayments of $97.1 million under the Company’s credit facilities in the 2011 period compared to $217.1 million in borrowings in 2010;

·	Payments of $115 million to redeem all of the Company’s outstanding Preferred Stock in the 2010 period;

·	Net repayments of $18.6 million of long-term debt in the 2011 period, compared to net debt repayments of $39.9 million in the 2010 period; and

·	Dividend payments of $7.2 million on the Company’s Preferred Stock in the 2010 period.

Financing activities used cash flows of $39.4 million and $153.6 million in the years ended December 31, 2010 and 2009, respectively. The $114.2 million decrease in net financing cash outflows was primarily due to:

·	Borrowings of $217.1 million under the Company’s credit facilities in the 2010 period compared to $321.5 million in payments in 2009;

·	Payments of $115 million in 2010 to redeem all of the Company’s outstanding Preferred Stock; and

·	Net repayments of $39.9 million of long-term debt in the 2010 period, compared to net debt issuances of $243.3 million in the 2009 period.

Debt Refinancing and Repayment

Term Loans. On August 3, 2010, the Company entered into an Amended and Restated $250 million Credit Agreement, maturing on August 3, 2013 ( 2010 Term Loan ). The 2010 Term Loan bears interest at a rate of LIBOR plus 2.125 percent. The 2010 Term Loan amended, restated and upsized the two-year $150 million term loan entered into on August 5, 2009 ( 2009 Term Loan ). Proceeds received from the 2010 Term Loan were used to refinance the existing indebtedness under the 2009 Term Loan, with the remaining proceeds used to provide working capital and for general corporate purposes. The balance of the 2010 Term Loan was $250 million and $250 million at effective interest rates of 2.40 and 2.39 percent at December 31, 2011 and 2010, respectively. The balance and effective interest rate of the 2010 Term Loan at February 17, 2012 were $250 million and 2.38 percent, respectively.

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Short-Term Debt Obligations, Excluding Current Portion of Long-Term Debt

Credit Facilities. During the second quarter of 2011, the Company entered into the Seventh Amended and Restated Revolving Credit Agreement with the banks named therein in the amount of $550 million (2011 Revolver) . The 2011 Revolver is an amendment, restatement and refinancing of the Company’s existing $550 million revolving credit facility, which was otherwise scheduled to mature on May 28, 2013. The 2011 Revolver will mature on May 20, 2016. Borrowings on the 2011 Revolver 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 2011 Revolver are calculated using a pricing grid, which is based upon the credit rating for the Company’s senior unsecured notes. The annualized interest rate and commitment fee rate bases for the 2011 Revolver at December 31, 2011 were LIBOR, plus 162.5 basis points, and 25 basis points, respectively.

The Company’s additional $25 million short-term committed credit facility was renewed in July 2011 for an additional 364-day period.

Balances of $200 million and $297.1 million were outstanding under the Company’s credit facilities at effective interest rates of 1.88 percent and 3.02 percent at December 31, 2011 and 2010, respectively. The Company classifies its borrowings under the credit facilities as short-term debt, as the individual borrowings are generally for periods of 15 to 180 days. At maturity, the Company may (i) retire the outstanding balance of each borrowing with available cash on hand and/or proceeds from a new borrowing, or (ii) at the Company’s option, extend the borrowing’s maturity date for up to an additional 90 days. As of February 17, 2012, there was a balance of $148.3 million outstanding under the Company’s credit facilities at an average effective interest rate of 1.86 percent.

Retirement of Debt Obligations

The Company refinanced LNG Holdings’ $455 million term loan due March 13, 2012 on February 23, 2012 with an unsecured three-year term loan facility due February 23, 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 Company expects to retire the $465 million term loan due June 2012 ($342.4 million of which is outstanding at December 31, 2011) utilizing a portion of the $445 million in merger consideration to be received by Southern Union in connection with the Citrus Merger. Should the Citrus Merger not occur by the June 2012 maturity date, the Company would expect to refinance and/or extend the $465 million term loan, or alternatively the Company might choose to retire such debt upon maturity by utilizing some combination of cash flows from operations, draw downs under existing credit facilities and altering the timing of controllable expenditures, among other things. The Company reasonably believes, based on its investment grade credit ratings and general financial condition, successful historical access to capital and debt markets and market expectations regarding the Company’s future earnings and cash flows, that it will be able to refinance and/or retire these obligations, as applicable, under acceptable terms prior to their maturity. There can be no assurance, however, that the Company will be able to achieve acceptable refinancing terms in any negotiation of new capital market debt or bank financings. Moreover, there can be no assurance the Company will be successful in its implementation of these refinancing and/or retirement plans and the Company’s inability to do so could cause a material adverse effect on the Company’s financial condition and liquidity.

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Credit Ratings. As of December 31, 2011, both Southern Union’s and Panhandle’s debt was rated BBB- by Fitch Ratings, Baa3 by Moody's Investor Services, Inc. and BBB- by Standard & Poor's. Due to the merger activities involving the Company, Standard and Poor’s has placed Southern Union and Panhandle on Credit Watch with developing implications, Moody’s has revised its outlook on Southern Union’s debt from stable to negative, and Fitch has placed Southern Union and Panhandle on Rating Watch Negative. 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 are downgraded below investment grade or if there are times when it is placed on "credit watch," the Company could be negatively impacted as follows:

·	Borrowing costs associated with existing debt obligations could increase annually up to approximately $6.6 million 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 being placed on credit watch or 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.

For additional related information, see Item 8. Financial Statements and Supplementary Data, Note 11 – Derivative Instruments and Hedging Activities – Derivative Instrument Contingent Features.

Dividend Restrictions. Under the terms of the indenture governing its senior unsecured notes ( Senior Notes ), Southern Union may not declare or pay any cash or asset dividends on its common stock (other than dividends and distributions payable solely in shares of its common stock or in rights to acquire its common stock) or acquire or retire any shares of its common stock, unless no event of default exists and certain financial ratio requirements are satisfied. Currently, the Company is in compliance with these requirements and, therefore, the Senior Notes indenture does not prohibit the Company from paying cash dividends.

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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 Item 8. Financial Statements and Supplementary Data, Note 6 – Unconsolidated Investments – Contingent Matters Potentially Impacting Southern Union Through the Company’s Investment in Citrus—Retirement of Debt Obligations . The following table summarizes the Company’s expected contractual obligations by payment due date as of December 31, 2011.

	Contractual Obligations
													2017 and
	Total		2012		2013		2014		2015		2016		thereafter

	(In thousands)

Long-term debt (1) (2)	$	3,500,702	$	343,254	$	500,797	$	772	$	455,751	$	708	$	2,199,420
Short-term borrowing,
including credit facilities (1)		200,000		200,000		-		-		-		-		-
Natural gas purchases (3)		126,109		68,603		3,948		3,823		3,717		3,620		42,398
Missouri Gas Energy
Safety Program		94,765		11,822		11,941		11,541		11,657		11,773		36,031
Transportation contracts		265,203		82,274		56,858		19,245		15,496		14,364		76,966
Natural gas storage
contracts (4)		217,242		38,897		35,662		31,007		27,388		23,771		60,517
Operating lease payments		134,785		15,172		17,342		15,606		14,306		13,377		58,982
Interest payments on debt (5)		2,454,788		161,866		156,762		138,101		138,066		138,032		1,721,961
Fractionation contract		182,502		21,528		22,215		22,827		23,151		23,512		69,269
Other (6)		28,698		21,462		794		814		744		336		4,548
	$	7,204,794	$	964,878	$	806,319	$	243,736	$	690,276	$	229,493	$	4,270,092

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(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, 2011, the Company was in compliance with all of its covenants. See Item 8. Financial Statements and Supplementary Data, Note 8 – Debt Obligations .

(2)	The long-term debt principal payment obligations exclude $2.9 million of unamortized debt premium as of December 31, 2011.

(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, 2011. Includes approximately $1.13 billion of interest payments associated with the $600 million Junior Subordinated Notes due November 1, 2066.

(6)	Includes unrecognized tax benefits and various other contractual obligations.

Contingencies

See Item 8. Financial Statements and Supplementary Data, Note 15 – Commitments and Contingencies .

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

See Item 8. Financial Statements and Supplementary Data, Note 19 – Regulation and Rates .

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Matters Impacting the Company’s Unconsolidated Investment in Citrus

Florida Gas and an affiliate of El Paso each submitted a bid in response to Florida Power & Light Company’s ( FPL ) proposed 300-mile Florida EnergySecure intrastate pipeline project, and FPL entered into a non-binding letter of intent with the El Paso affiliate in connection with such project. Although the Florida Public Service Commission did not approve the Florida EnergySecure intrastate pipeline project, FPL has indicated that it may seek bids for a future project. El Paso has reasserted that it is entitled to, and communicated that it currently intends that it may, participate in any such bidding process. In light of existing circumstances, Florida Gas, Citrus and Southern Union continue to disagree with El Paso’s position. A successful bid on such FPL project by El Paso, if the project ultimately is approved, could adversely impact Florida Gas’ ultimate contract terms for the remaining uncommitted Phase VIII Expansion transportation capacity and Florida Gas’ future growth opportunities in Florida.

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 $54.7 million, less than the associated actual revenues during the same period of $68.5 million. These expansion revenues are currently at negotiated rates totaling $72.6 million annually through 2015. 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.

See Item 8. Financial Statements and Supplementary Data, Note 19 – Regulation and Rates 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. 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.

Critical Accounting Policies

Summary

The Company’s consolidated financial statements have been prepared in accordance with GAAP. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and related disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates and assumptions about future events and their effects cannot be determined with certainty. On an ongoing basis, the Company evaluates its estimates based on historical experience, current market conditions and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. Nevertheless, actual results may differ from these estimates under different assumptions or conditions.

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In preparing the consolidated financial statements and related disclosure, the following are examples of certain areas that require significant management judgment in establishing related estimates and assumptions:

·	the economic lives of plant, property and equipment;

·	the fair values used to allocate purchase price and to determine possible asset impairment charges;

·	reserves for environmental claims, legal fees and other litigation or contingent liabilities;

·	provisions for income taxes and establishment of tax valuation reserves, including the interpretation of complex tax laws;

·	provisions for uncollectible receivables;

·	exposures under contractual indemnification;

·	pension and other postretirement benefit plan liabilities;

·	the fair values associated with derivative financial instruments; and

·	unbilled revenues.

The following is a summary of the Company’s most critical accounting policies, which are defined as those policies whereby judgments or uncertainties could affect the application of those policies and materially different amounts could be reported under different conditions or using different assumptions. For a summary of all of the Company’s significant accounting policies, see Item 8. Financial Statements and Supplementary Data, Note 2 – Summary of Significant Accounting Policies and Other Matters.

Effects of Regulation

The Company is subject to regulation by certain state and federal authorities in each of its reportable segments. Missouri Gas Energy, New England Gas Company and Florida Gas have accounting policies that are in accordance with the accounting requirements and ratemaking practices of the applicable regulatory authorities. The application of these accounting policies allows 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 Statement 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 Sheet and included in the Consolidated Statement of Operations for the period in which the discontinuance of regulatory accounting treatment occurs. The aggregate amounts of regulatory assets reflected in the Consolidated Balance Sheet applicable to the Distribution segment are $57.4 million and $66.2 million at December 31, 2011 and 2010, respectively. The aggregate amounts of regulatory liabilities reflected in the Consolidated Balance Sheet applicable to the Distribution segment are $8.4 million and $5.8 million at December 31, 2011 and 2010, respectively. For a summary of regulatory matters applicable to the Company, see Item 8. Financial Statements and Supplementary Data, Note 19 – Regulation and Rates . Panhandle and SUGS do not currently apply regulatory accounting standards.

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Evaluation of Assets for Impairment

Long-lived assets, primarily consisting of property, plant and equipment, goodwill and equity method investments, comprise a significant amount of the Company’s total assets. The Company makes judgments and estimates about the carrying value of certain of these assets, including amounts to be capitalized, depreciation methods and useful lives. The Company also reviews these assets for impairment on a periodic basis or whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable or such carrying amounts are in excess of the asset’s fair value. The Company primarily uses an income approach to estimate the recoverability or fair value of its assets, which requires it to make long-term forecasts of future net cash flows related to the assets. The process of estimating net cash flow forecasts is inherently subjective. Some of the key assumptions or estimates utilized by the Company in its cash flow forecast projections are:

·	future demand for services provided by the Company;

·	impact of future market conditions on customer and vendor pricing;

·	regulatory developments;

·	inflationary trends;

·	estimated useful lives of assets and ongoing capital requirements;

·	discount rates used; and

·	terminal asset values using EBITDA-based market multiples.

Significant changes to these assumptions or estimates could require a provision for impairment in a future period.

Long-Lived Assets Impairment Evaluation. 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. An impairment loss is measured as the amount by which the carrying amount of a long-lived asset exceeds its fair value.

A long-lived asset is tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. Long-lived assets or asset groups used in operations are evaluated for potential impairment at the lowest level for which identifiable cash flows are largely independent of the cash flows of other groups of assets and liabilities. A two-step impairment test is performed to identify a potential impairment and measure an impairment loss, if any, to be charged to earnings. Step one determines if the carrying amount ascribed to a long-lived asset or asset group is recoverable based on undiscounted cash flows. If the asset or asset group fails the step one recoverability test (i.e. related carrying amount is in excess of the undiscounted cash flows), then, as a second step, the fair value of the asset or asset group is compared to the related carrying amount to determine the amount of impairment loss to be charged to earnings. The fair value in the second test is primarily determined based upon discounted cash flows associated with the asset or asset group using assumptions that market participants would use.

Goodwill Impairment Evaluation. At December 31, 2011, the Company had a goodwill balance of $89.2 million relating to its Distribution segment reporting unit. The Company assesses goodwill for impairment at least annually as of November 30, and updates the annual test on an interim basis if events or circumstances occur that would more likely than not reduce the fair value of the applicable reporting unit below its book carrying amount. A two-step impairment test is performed to identify a potential impairment and measure an impairment loss, if any, to be charged to earnings. In the first step, the fair value of the reporting unit, which is primarily determined based on discounted cash flows using assumptions that market participants would use, is compared to the reporting unit’s carrying amount, including goodwill. If the carrying amount of the reporting unit is greater than its fair value, the reporting unit’s goodwill may be impaired and step two must be completed. In the second step, the carrying amount of the reporting unit’s goodwill is compared with the implied fair value of such goodwill. If the carrying amount of the reporting unit’s goodwill is greater than its implied fair value, an impairment loss must be charged to earnings for the excess (i.e. recorded goodwill must be written down to implied fair value of the reporting unit’s goodwill). Because the fair value of goodwill can be measured only as a residual amount and cannot be determined directly, the implied fair value of a reporting unit’s goodwill is calculated in the same manner as the amount of goodwill that is recognized in a purchase business combination. This process involves measuring the fair value of the reporting unit’s assets and liabilities (both recognized and unrecognized) at the time of the impairment test by performing a hypothetical purchase price allocation. The difference between the reporting unit’s fair value and the fair values assigned to the reporting unit’s individual assets and liabilities (both recognized and unrecognized), is the implied fair value of the reporting unit’s goodwill.

The Company evaluated goodwill for potential impairment for the years ended December 31, 2011, 2010 and 2009, and no impairment was indicated in the step one test.

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Equity Method Investments. A loss in value of an equity method investment that is other than temporary 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. The Company evaluated its equity method investments for potential impairment for the years ended December 31, 2011, 2010 and 2009, and no impairment was indicated.

Pensions and Other Postretirement Benefits

The Company is required to measure plan assets and benefit obligations as of its fiscal year-end balance sheet date. The Company recognizes the changes in the funded status of its defined benefit postretirement plans through Accumulated other comprehensive loss .

The calculation of the Company’s net periodic benefit cost and benefit obligation requires the use of a number of assumptions. Changes in these assumptions can have a significant effect on the amounts reported in the financial statements. The Company believes that the two most critical assumptions are the assumed discount rate and the expected rate of return on plan assets.

The Company establishes the discount rate using the Citigroup Pension Discount Curve as published on the Society of Actuaries website as the hypothetical portfolio of high-quality debt instruments that would provide the necessary cash flows to pay the benefits when due. Net periodic benefit cost and benefit obligation increases and equity correspondingly decreases as the discount rate is reduced. Lowering the discount rate assumption by 0.5 percent would increase the Company’s 2011 net periodic benefit cost (before regulatory accounting adjustments) and benefit obligation at the end of 2011 by approximately $1.5 million and $24.7 million, respectively, and would correspondingly increase Accumulated other comprehensive loss at the end of 2011 by $24.7 million on a pre-tax basis.

The expected rate of return on plan assets is based on long-term expectations given current investment objectives and historical results. Net periodic benefit cost increases as the expected rate of return on plan assets is correspondingly reduced. Lowering the expected rate of return on plan assets assumption by 0.5 percent would increase the Company’s 2011 net periodic benefit cost (before regulatory accounting adjustments) by approximately $1.1 million.

See Item 8. Financial Statements and Supplementary Data, Note 9 – Benefits for additional related information.

Derivatives and Hedging Activities

All derivatives are recognized on the balance sheet at their fair value. On the date the derivative contract is entered into, the Company designates the derivative as: (i) a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (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 (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 if the short cut method of assessing effectiveness is not used. 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 the Fair Value Measurement discussion below for additional information related to the framework used by the Company to measure the fair value of its derivative financial instruments.

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The Company formally assesses, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions have been highly effective in offsetting changes in the fair value or cash flows of hedged items and whether those derivatives may be expected to remain highly effective in future periods. The Company discontinues hedge accounting when: (i) it determines that the derivative is no longer effective in offsetting changes in the fair value or cash flows of a hedged item; (ii) the derivative expires or is sold, terminated, or exercised; (iii) it is no longer probable that the forecasted transaction will occur; or (iv) management determines that designating the derivative as a hedging instrument is no longer appropriate. In all situations in which hedge accounting is discontinued and the derivative remains outstanding, the Company will carry the derivative at its fair value on the balance sheet, recognizing changes in the fair value in current-period earnings. See Item 8. Financial Statements and Supplementary Data, Note 11 – Derivative Instruments and Hedging Activities .

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. The 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.

See Item 8. Financial Statements and Supplementary Data Note 12 – Fair Value Measurement and Note 9 – Benefits – Pension and Other Postretirement Plans – Plan Assets for additional information regarding the assets and liabilities of the Company measured on a recurring and nonrecurring basis, respectively.

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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 bases. 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 Company’s 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. Reserves are established when, despite management’s belief that the Company’s tax return positions are fully supportable, management believes that certain positions may be successfully challenged. When facts and circumstances change, these reserves are adjusted through the provision for income taxes. See Item 8. Financial Statements and Supplementary Data, Note 10 – Taxes on Income 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 judgments by management regarding the estimated probabilities and ranges of exposure to potential liability. For further discussion of the Company’s commitments and contingencies, see Item 8. Financial Statements and Supplementary Data, Note 15 – Commitments and Contingencies.

New Accounting Pronouncements

See Item 8. Financial Statements and Supplementary Data, Note 2 – Summary of Significant Accounting Policies and Other Matters – New Accounting Principles .

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, 2011, the interest rate on 81 percent of the Company’s long-term debt was fixed after considering the impact of interest rate swaps.

At December 31, 2011, $19.9 million is included in Derivative instruments - liabilities and $59.8 million is included in Deferred Credits in the Consolidated Balance Sheet related to the fixed-rate interest rate swaps on the $455 million Term Loan due 2012 and $525 million of the $600 million Junior Subordinated Notes due 2066.

At December 31, 2011, 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 approximately $700,000 for each month during which such change continued. If interest rates change significantly, the Company may take actions to manage its exposure to the change.

The Company enters into treasury rate locks from time to time to manage its exposure against changes in future interest payments attributable to changes in the US treasury rates. By entering into these agreements, the Company locks in an agreed upon interest rate until the settlement of the contract, which typically occurs when the associated long-term debt is sold. The Company accounts for the treasury rate locks as cash flow hedges. The Company’s most recent treasury rate locks were settled in February and June 2008.

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The change in exposure to loss in earnings and cash flow related to interest rate risk for the year ended December 31, 2011 is not material to the Company.

See Item 8. Financial Statements and Supplementary Data , Note 11 – Derivative Instruments and Hedging Activities and Note 8 - Debt Obligations .

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 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.

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The following table summarizes SUGS' principal commodity derivative instruments as of December 31, 2011 (all instruments are settled monthly), which were developed based upon historical and projected operating conditions and processable volumes.

Average

2012

Fair Value

Fixed Price

Volumes

of Assets

Instrument Type

Index

(per MMBtu)

(MMBtu/d) (3)

(Liabilities) (5)

(In thousands)

Natural Gas - Cash Flow Hedges: (1)

Receive-fixed swap

Gas Daily - El Paso Permian

4.82

10,000

6,124

Total

10,000

6,124

Average

2012

Fair Value

Fixed Price

Volumes

of Assets

Instrument Type

Index

(per Gallon)

(Gallons/d)

(Liabilities) (5)

(In thousands)

Natural Gas Liquids - Cash Flow Hedges: (2)

Receive-fixed swap (4)

OPIS Mt. Belvieu

1.15

178,629

(6,140

)

Total

178,629

(6,140

)

__________________

(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)

The Company’s NGL 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.

(3)	All volumes are applicable to the period January 1, 2012 to December 31, 2012, with 55.25 percent of the volumes settled against Gas Daily - Waha and 44.75 percent of the volumes settled against Gas Daily – El Paso Permian.

(4)

The Company’s NGL swap arrangements consist of a ratio of NGL product that is approximately (on a gallon basis): 44 percent ethane, 29 percent propane, 4 percent iso-butane, 11 percent normal butane and 12 percent natural gasoline. The arrangements approximate 15,000 MMBtu/d equivalents at a weighted average fixed price of $13.66 per MMBtu.

(5)	See Item 8. Financial Statements and Supplementary Data, Note 11 – Derivative Instruments and Hedging Activities – Commodity Contracts – Gathering and Processing Segment for additional related information.

At December 31, 2011, 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 $1.3 million and $8.9 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 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, 2011, there were no hedges in place with respect to natural gas price risk associated with the Company’s interstate pipeline operations.

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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 Sheet. As of December 31, 2011, the fair values of the contracts, which expire at various times through December 2013, are included in the Consolidated Balance Sheet as liabilities, with matching adjustments to deferred cost of natural gas of $40.1 million.

ITEM 8 . Financial Statements and Supplementary Data.

The information required here is included in the report as set forth in the Index to Consolidated Financial Statements on page F-1.

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

The Company has established disclosure controls and procedures to ensure that information required to be disclosed by the Company, including consolidated entities, in reports filed or submitted under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed in the reports it files or submits under the Exchange Act is accumulated and communicated to management, including the Company’s CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure. The Company performed an evaluation under the supervision and with the participation of management, including its CEO and CFO, and with the participation of personnel from its Legal, Internal Audit, Risk Management and Financial Reporting Departments, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this report. Based on that evaluation, Southern Union’s CEO and CFO concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2011.

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.

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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, 2011.

The Company’s internal control over financial reporting as of December 31, 2011 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report, which is included herein.

Southern Union Company

February 24, 2012

Changes In Internal Control Over Financial Reporting

There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended December 31, 2011 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

ITEM 9B . Other Information.

All information required to be reported on Form 8-K for the quarter ended December 31, 2011 was appropriately reported.

PART III

ITEM 10. Directors, Executive Officers and Corporate Governance.

The information required by Item 10 will be filed with the SEC within 120 days after the close of the year ended December 31, 2011.

ITEM 11. Executive Compensation.

The information required by Item 11 will be filed with the SEC within 120 days after the close of the year ended December 31, 2011.

ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The information required by Item 12 will be filed with the SEC within 120 days after the close of the year ended December 31, 2011.

ITEM 13. Certain Relationships and Related Transactions, and Director Independence.

The information required by Item 13 will be filed with the SEC within 120 days after the close of the year ended December 31, 2011.

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ITEM 14. Principal Accounting Fees and Services.

The information required by Item 14 will be filed with the SEC within 120 days after the close of the year ended December 31, 2011.

PART IV

ITEM 15. Exhibits, Financial Statement Schedules.

(a)(1) and (2)

Financial Statements and Financial Statement Schedules.

(a)(3)

Exhibits.

Exhibit No. Description

2(a)

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(b)

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(c)

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(d)

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(a) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2005 and incorporated herein by reference.)

3(b)

By-Laws of Southern Union Company, as amended. (Filed as Exhibit 3(b) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2009 and incorporated herein by reference.)

4(a)

Specimen Common Stock Certificate. (Filed as Exhibit 4(a) to Southern Union's Annual Report on Form 10-K for the year ended December 31, 1989 and incorporated herein by reference.)

4(b)

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.)

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4(c)

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(d)

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(e)

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(f)

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(g)

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.)

4(h)

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(i)

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(j)

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(k) 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)

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(b)

Seventh Amended and Restated Revolving Credit Agreement, dated as of May 20, 2011, 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 May 24, 2011 and incorporated herein by reference.)

10(c)

Amended and Restated Credit Agreement, dated as of August 3, 2010, among the Company, as borrower, and the lenders party thereto (filed as Exhibit 10(b) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference.)

10(d)

First Amendment to Construction and Term Loan Agreement between Citrus Corp., as borrower, and Pipeline Funding Company, LLC, as lender and administrative agent, dated as of August 6, 2008. (Filed as Exhibit 10(a) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008 and incorporated herein by reference.)

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10(e)

Construction and Term Loan Agreement between Citrus Corp., as borrower, and Pipeline Funding Company, LLC, as lender and administrative agent, dated as of February 5, 2008. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on February 8, 2008 and incorporated herein by reference.)

10(f)

Amendment Number 1 to the Amended and Restated Credit Agreement between Trunkline LNG Holdings, LLC, as borrower, Panhandle Eastern Pipe Line Company, LP and CrossCountry Citrus, LLC, as guarantors, the financial institutions listed therein and Bayerische Hypo-Und Vereinsbank AG, New York Branch, as administrative agent, dated as of June 13, 2008. (Filed as Exhibit 10(d) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008 and incorporated herein by reference.)

10(g)

Amended and Restated Credit Agreement between Trunkline LNG Holdings, LLC, as borrower, Panhandle Eastern Pipeline Company, LP and CrossCountry Citrus, LLC, as guarantors, the financial institutions listed therein and Bayerische Hypo-Und Vereinsbank AG, New York Branch, as administrative agent, dated as of June 29, 2007. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on July 6, 2007 and incorporated herein by reference.)

10(h)

Form of Indemnification Agreement between Southern Union Company and each of the Directors of Southern Union Company and certain senior executive officers. (Filed as Exhibit 10(g) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2008 and incorporated herein by reference.)

10(i)

Southern Union Company 1992 Long-Term Stock Incentive Plan, As Amended. (Filed as Exhibit 10(l) to Southern Union’s Annual Report on Form 10-K for the year ended June 30, 1998 and incorporated herein by reference.) *

10(j)

Southern Union Company Director's Deferred Compensation Plan. (Filed as Exhibit 10(g) to Southern Union's Annual Report on Form 10-K for the year ended December 31, 1993 and incorporated herein by reference.)

10(k)

First Amendment to Southern Union Company Director’s Deferred Compensation Plan, effective April 1, 2007. (Filed as Exhibit 10(h) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 and incorporated herein by reference.)

10(l)

Southern Union Company Amended Supplemental Deferred Compensation Plan with Amendments. (Filed as Exhibit 4 to Southern Union’s Form S-8 filed May 27, 1999 and incorporated herein by reference.) *

10(m)

Second Amended and Restated Southern Union Company 2003 Stock and Incentive Plan. (Filed as Exhibit 4 to Form S-8, SEC File No. 333-138524, filed on November 8, 2006 and incorporated herein by reference.) *

10(n)

Third Amended and Restated Southern Union Company 2003 Stock and Incentive Plan. (Filed as Appendix I to Southern Union’s proxy statement on Schedule 14A filed on April 16, 2009 and incorporated herein by reference).*

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10(o)

Form of Long Term Incentive Award Agreement, dated December 28, 2006, between Southern Union Company and the undersigned. (Filed as Exhibit 99.1 to Southern Union’s Form 8-K dated January 3, 2007) and incorporated herein by reference.) *

10(p)

Employment Agreement between Southern Union Company and George L. Lindemann, dated as of August 28, 2008. (Filed as Exhibit 10(f) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference.) *

10(q)

Employment Agreement between Southern Union Company and Eric D. Herschmann, dated as of August 28, 2008. (Filed as Exhibit 10(g) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference.) *

10(r)

Employment Agreement between Southern Union Company and Robert O. Bond, dated as of August 28, 2008. (Filed as Exhibit 10(h) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference.) *

10(s)

Employment Agreement between Southern Union Company and Monica M. Gaudiosi, dated as of August 28, 2008. (Filed as Exhibit 10(i) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference.) *

10(t)

Employment Agreement between Southern Union Company and Richard N. Marshall, dated as of August 28, 2008. (Filed as Exhibit 10(j) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference.) *

10(u)

Second Amended and Restated Southern Union Company Executive Incentive Bonus Plan, dated March 25, 2010 (Filed as Appendix I to Southern Union Company’s proxy statement on Schedule 14A filed on March 26, 2010 and incorporated herein by reference.) *

10(v)

Form of Change in Control Severance Agreement, between Southern Union Company and certain Executives (filed as Exhibit 10.2 to Southern Union’s Current Report on Form 8-K filed on August 28, 2008 and incorporated herein by reference.) *

10(w)

Capital Stock Agreement dated June 30, 1986, as amended April 3, 2000 ("Agreement"), among El Paso Energy Corporation (as successor in interest to Sonat, Inc.); CrossCountry Energy, LLC (assignee of Enron Corp., which is the successor in interest to InterNorth, Inc. by virtue of a name change and successor in interest to Houston Natural Gas Corporation by virtue of a merger) and Citrus Corp. (Filed as Exhibit 10(t) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2008 and incorporated herein by reference.)

10(x)

Certificate of Incorporation of Citrus Corp. (Filed as Exhibit 10(q) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2006 and incorporated herein by reference.)

10(y)

By-Laws of Citrus Corp., filed herewith. (Filed as Exhibit 10(r) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2006 and incorporated herein by reference.)

Ratio of earnings to fixed charges.

Code of Ethics and Business Conduct. (Filed as Exhibit 14 to Southern Union’s Annual Report on Form 10-K filed on March 16, 2006 and incorporated herein by reference.)

Subsidiaries of the Registrant.

23.1

Consent of Independent Registered Public Accounting Firm for Southern Union Company.

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23.2	Consent of Independent Registered Public Accounting Firm for Citrus Corp.

Power of Attorney.

31.1

Certificate by Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) promulgated under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Certificate by Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) promulgated under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

Certificate by Chief Executive Officer pursuant to Rule 13a-14(b) or Rule 15d-14(b) promulgated under the Securities Exchange Act of 1934 and Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350.

32.2

Certificate by Chief Financial Officer pursuant to Rule 13a-14(b) or Rule 15d-14(b) promulgated under the Securities Exchange Act of 1934 and Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350.

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 **

____________

* Management contract or compensation plan or arrangement

** XBRL information is furnished and not filed for purposes of Sections 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange Act of 1934, and is not subject to liability under those sections, is not part of any registration statement or prospectus to which it relates

and is not incorporated or deemed to be incorporated by reference into any registration statement, prospectus or other document.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Southern Union has duly caused this report to be signed by the undersigned, thereunto duly authorized, on February 24, 2012.

	SOUTHERN UNION COMPANY

	By: /s/ George L. Lindemann
	George L. Lindemann
	Chairman of the Board and
	Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of Southern Union and in the capacities indicated as of February 24, 2012.

Signature/Name	Title
/s/ George L. Lindemann* George L. Lindemann	Chairman of the Board and Chief Executive Officer (Principal Executive Officer)
/s/ Eric D. Herschmann* Eric D. Herschmann	Vice Chairman of the Board, President and Chief Operating Officer

/s/ Richard N. Marshall Richard N. Marshall	Senior Vice President and Chief Financial Officer (Principal Financial Officer)
/s/ George E. Aldrich George E. Aldrich	Senior Vice President and Controller (Authorized Officer and Principal Accounting Officer)

/s/ David Brodsky* David Brodsky	Director
/s/ Frank W. Denius* Frank W. Denius	Director
/s/ Kurt A. Gitter, M.D.* Kurt A. Gitter, M.D.	Director
/s/ Herbert H. Jacobi* Herbert H. Jacobi	Director

/s/ Thomas N. McCarter, III* Thomas N. McCarter, III	Director
/s/ George Rountree, III* George Rountree, III	Director
/s/ Allan D. Scherer* Allan Scherer	Director

*By: /s/ RICHARD N. MARSHALL	*By: /s/ ROBERT M. KERRIGAN, III
Richard N. Marshall	Robert M. Kerrigan, III
Senior Vice President and Chief Financial Officer Attorney-in-fact	Vice President, Assistant General Counsel and Secretary
	Attorney-in-fact

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SOU THERN UNION COMPANY AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Financial Statements and Supplementary Data:	Page(s):
Consolidated Statements of Operations	F-2
Consolidated Balance Sheets	F-3 - F-4
Consolidated Statements of Cash Flows	F-5
Consolidated Statements of Stockholders’ Equity and Comprehensive Income	F-6 - F-7
Notes to Consolidated Financial Statements	F-8
Report of Independent Registered Public Accounting Firm	F-61

All schedules are omitted as the required information is not applicable or the information is presented in the consolidated financial statements or related notes.

F-1

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Years Ended December 31,
	2011			2010			2009

	(In thousands, except per share amounts)

Operating revenues (Note 18):
Natural gas gathering and processing	$	1,179,680		$	1,008,023		$	732,251
Natural gas distribution		666,650			698,513			692,904
Natural gas transportation and storage		803,650			769,450			749,161
Other		15,974			13,927			4,702
Total operating revenues		2,665,954			2,489,913			2,179,018

Operating expenses:
Cost of natural gas and other energy		1,362,177			1,243,749			1,060,892
Operating, maintenance and general		498,255			463,517			468,721
Depreciation and amortization		237,690			228,637			213,827
Revenue-related taxes		35,608			37,619			36,375
Taxes, other than on income and revenues		54,366			55,776			53,114
Total operating expenses		2,188,096			2,029,298			1,832,929

Operating income		477,858			460,615			346,089

Other income (expenses):
Interest expense		(219,232	)		(216,665	)		(196,800	)
Earnings from unconsolidated investments		98,935			105,415			80,790
Other, net (Note 22)		1,643			312			21,401
Total other expenses, net		(118,654	)		(110,938	)		(94,609	)

Earnings from continuing operations before income taxes		359,204			349,677			251,480

Federal and state income tax expense (Note 10)		103,780			107,029			71,900

Earnings from continuing operations		255,424			242,648			179,580

Loss from discontinued operations (Note 23)		-			(18,100	)		-

Net earnings		255,424			224,548			179,580

Preferred stock dividends		-			(5,040	)		(8,683	)
Loss on extinguishment of preferred stock		-			(3,295	)		-

Net earnings available for common stockholders	$	255,424		$	216,213		$	170,897

Net earnings available for common stockholders
from continuing operations per share (Note 5):
Basic	$	2.05		$	1.88		$	1.38
Diluted	$	2.02		$	1.87		$	1.37

Net earnings available for common stockholders per share (Note 5):
Basic	$	2.05		$	1.74		$	1.38
Diluted	$	2.02		$	1.73		$	1.37
Cash dividends declared on common stock per share:	$	0.60		$	0.60		$	0.60

Weighted average shares outstanding (Note 5):
Basic		124,720			124,474			124,076
Diluted		126,283			125,191			124,409

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

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS
	December 31,
	2011			2010

	(In thousands)

Current assets:
Cash and cash equivalents	$	23,640		$	3,299
Accounts receivable
net of allowances of $2,325 and $3,321, respectively		270,741			310,006
Accounts receivable – affiliates		10,467			10,747
Inventories		204,235			226,875
Deferred natural gas purchases		50,716			85,138
Natural gas imbalances - receivable		54,549			52,141
Prepayments and other assets		42,675			67,535
Total current assets		657,023			755,741

Property, plant and equipment (Note 13):
Plant in service		7,195,747			6,957,989
Construction work in progress		103,862			120,264
		7,299,609			7,078,253
Less accumulated depreciation and amortization		(1,573,273	)		(1,373,794	)
Net property, plant and equipment		5,726,336			5,704,459

Deferred charges:
Regulatory assets (Note 4)		57,447			66,216
Deferred charges		60,407			66,929
Total deferred charges		117,854			133,145

Unconsolidated investments (Note 6)		1,633,289			1,538,548

Goodwill		89,227			89,227

Other		47,130			17,423


Total assets	$	8,270,859		$	8,238,543

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

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

STOCKHOLDERS' EQUITY AND LIABILITIES

	December 31,
	2011			2010

	(In thousands)

Stockholders’ equity (Note 16):
Common stock, $1 par value; 200,000 shares authorized;
126,142 and 125,839 shares issued at December 31, 2011
and 2010, respectively	$	126,142		$	125,839
Premium on capital stock		1,934,102			1,920,622
Less treasury stock: 1,298 and 1,230 shares, respectively, at cost		(33,228	)		(30,532	)
Less common stock held in trust: 581 and 597 shares, respectively		(10,888	)		(10,857	)
Deferred compensation plans		10,888			10,857
Accumulated other comprehensive loss (Note 7)		(119,192	)		(40,157	)
Retained earnings		731,787			551,210
Total stockholders' equity		2,639,611			2,526,982

Long-term debt obligations (Note 8)		3,160,372			3,520,906

Total capitalization		5,799,983			6,047,888

Current liabilities:
Long-term debt due within one year (Note 8)		343,254			1,083
Notes payable (Note 8)		200,000			297,051
Accounts payable and accrued liabilities		194,127			218,531
Federal, state and local taxes payable		37,127			35,235
Accrued interest		33,837			37,464
Natural gas imbalances - payable		145,212			178,087
Derivative instruments (Note 11 and 12)		58,598			67,026
Other		112,135			137,221
Total current liabilities		1,124,290			971,698

Deferred credits		301,709			205,094

Accumulated deferred income taxes (Note 10)		1,044,877			1,013,863

Commitments and contingencies (Note 15)

Total stockholders' equity and liabilities	$	8,270,859		$	8,238,543

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

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2011			2010			2009

	(In thousands)
Cash flows provided by (used in) operating activities:
Net earnings	$	255,424		$	224,548		$	179,580
Adjustments to reconcile net earnings to net cash flows
provided by (used in) operating activities:
Depreciation and amortization		237,690			228,637			213,827
Deferred income taxes		103,538			107,418			121,210
Provision for bad debts		8,089			8,681			8,601
Unrealized loss on commodity derivatives		50			18,514			44,778
Loss from discontinued operations		-			18,100			-
Loss on asset sales or dispositions		1,578			1,867			5,563
Stock-based compensation expense		10,149			9,331			7,510
Earnings from unconsolidated investments,
adjusted for cash distributions		(95,605	)		(101,915	)		(80,790	)
Changes in operating assets and liabilities:
Accounts receivable, billed and unbilled		31,456			(41,386	)		45,452
Accounts payable and accrued liabilities		(10,390	)		(8,508	)		12,838
Deferred natural gas purchase costs		37,095			(2,883	)		(73,174	)
Inventories		(5,848	)		(2,964	)		76,098
Prepaids and other assets		(1,938	)		(1,534	)		60,748
Taxes and other liabilities		(38,809	)		17,831			(57,962	)
Deferred charges		19,022			6,891			(266	)
Deferred credits		(20,460	)		(57,957	)		15,200
Net cash flows provided by operating activities		531,041			424,671			579,213
Cash flows (used in) provided by investing activities:
Additions to property, plant and equipment		(290,290	)		(293,022	)		(405,381	)
Contributions to unconsolidated investments		-			(100,000	)		(3,250	)
Loan to unconsolidated investments		(72,000	)		-			-
Loan repayment from unconsolidated investments		35,000			-			-
Plant retirements and other		(743	)		531			(10,793	)
Net cash flows used in investing activities		(328,033	)		(392,491	)		(419,424	)
Cash flows provided by (used in) financing activities:
Increase (decrease) in book overdraft		8,975			(14,154	)		8,583
Issuance of long-term debt		-			101,019			303,905
Renewal cost for credit facilities and issuance costs of debt		(2,162	)		(7,066	)		(4,011	)
Dividends paid on common stock		(74,811	)		(74,668	)		(74,424	)
Dividends paid on preferred stock		-			(7,211	)		(8,683	)
Extinguishment of preferred stock		-			(115,000	)		-
Repayment of long-term debt obligation		(18,556	)		(140,947	)		(60,623	)
Net change in revolving credit facilities and short-term debt		(97,051	)		217,051			(321,459	)
Other		938			1,550			3,150
Net cash flows provided by (used in) financing activities		(182,667	)		(39,426	)		(153,562	)
Change in cash and cash equivalents		20,341			(7,246	)		6,227
Cash and cash equivalents at beginning of period		3,299			10,545			4,318
Cash and cash equivalents at end of period	$	23,640		$	3,299		$	10,545

Cash paid for interest (net of amounts capitalized)	$	213,625		$	212,442		$	217,437
Cash (received) paid during the period for income taxes		(10,918	)		(20,088	)		486

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

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

	Common		Preferred			Premium						Common			Deferred			Accumulated						Total
	Stock,		Stock,			on			Treasury			Stock			Compen-			Other			Retained			Stock-
	$1 Par		No Par			Capital			Stock,			Held			sation			Comprehensive			Earnings			holders'
	Value		Value			Stock			at cost			In Trust			Plans			Income (Loss)			(Deficit)			Equity

	(In thousands)

Balance December 31, 2008	$	125,122	$	115,000		$	1,893,975		$	(28,004	)	$	(11,908	)	$	11,908		$	(51,423	)	$	313,282		$	2,367,952
Comprehensive income (loss):
Net earnings		-		-			-			-			-			-			-			179,580			179,580
Net change in other
comprehensive loss (Note 7),		-		-			-			-			-			-			(5,082	)		-			(5,082	)
Comprehensive income		-		-			-			-			-			-			-			-			174,498
Preferred stock dividends		-		-			-			-			-			-			-			(8,683	)		(8,683	)
Common stock dividends declared		-		-			-			-			-			-			-			(74,481	)		(74,481	)
Stock-based compensation		-		-			7,510			-			-			-			-			-			7,510
Restricted stock issuances		147		-			(633	)		(980	)		-			-			-			-			(1,466	)
Exercise of stock options		300		-			4,441			(125	)		-			-			-			-			4,616
Contributions to Trust		-		-			-			-			(1,010	)		1,010			-			-			-
Disbursements from Trust		-		-			-			-			1,149			(1,149	)		-			-			-
Balance December 31, 2009	$	125,569	$	115,000		$	1,905,293		$	(29,109	)	$	(11,769	)	$	11,769		$	(56,505	)	$	409,698		$	2,469,946
Comprehensive income (loss):
Net earnings		-		-			-			-			-			-			-			224,548			224,548
Net change in other
comprehensive loss (Note 7)		-		-			-			-			-			-			16,348			-			16,348
Comprehensive income		-		-			-			-			-			-			-			-			240,896
Preferred stock dividends		-		-			-			-			-			-			-			(5,040	)		(5,040	)
Common stock dividends declared		-		-			-			-			-			-			-			(74,701	)		(74,701	)
Stock-based compensation		-		-			9,331			-			-			-			-			-			9,331
Restricted stock issuances		149		-			658			(1,270	)		-			-			-			-			(463	)
Exercise of stock options		121		-			2,045			(153	)		-			-			-			-			2,013
Redemption of preferred stock
(Note 17)		-		(115,000	)		3,295			-			-			-			-			(3,295	)		(115,000	)
Contributions to Trust		-		-			-			-			(782	)		782			-			-			-
Disbursements from Trust		-		-			-			-			1,694			(1,694	)		-			-			-
Balance December 31, 2010	$	125,839	$	-		$	1,920,622		$	(30,532	)	$	(10,857	)	$	10,857		$	(40,157	)	$	551,210		$	2,526,982

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

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

(Continued)

	Common		Preferred			Premium							Common				Deferred				Accumulated								Total
	Stock,		Stock,			on			Treasury				Stock				Compen-				Other				Retained				Stock-
	$1 Par		No Par			Capital			Stock,				Held				sation				Comprehensive				Earnings				holders'
	Value		Value			Stock			at cost				In Trust				Plans				Income (Loss)				(Deficit)				Equity

	(In thousands)

Balance December 31, 2010	$	125,839		$	-		$	1,920,622		$	(30,532	)		$	(10,857	)		$	10,857			$	(40,157	)		$	551,210			$	2,526,982
Comprehensive income (loss):
Net earnings		-			-			-			-				-				-				-				255,424				255,424
Net change in other
comprehensive loss (Note 7)		-			-			-			-				-				-				(79,035	)			-				(79,035	)
Comprehensive income		-			-			-			-				-				-				-				-				176,389
Common stock dividends declared		-			-			-			-				-				-				-				(74,847	)			(74,847	)
Stock-based compensation		-			-			10,149			-				-				-				-				-				10,149
Restricted stock issuances		162			-			1,234			(2,419	)			-				-				-				-				(1,023	)
Exercise of stock options		141			-			2,097			(277	)			-				-				-				-				1,961
Contributions to Trust		-			-			-			-				(701	)			701				-				-				-
Disbursements from Trust		-			-			-			-				670				(670	)			-				-				-
Balance December 31, 2011	$	126,142		$	-		$	1,934,102		$	(33,228	)		$	(10,888	)		$	10,888			$	(119,192	)		$	731,787			$	2,639,611



The Company’s common stock is $1 par value. Therefore, the change in Common Stock, $1 par value, is 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.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Corporate Structure

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. Through Panhandle, the Company owns and operates approximately 10,000 miles of interstate pipelines that transport up to 5.5 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. Through its investment in Citrus, the Company has an interest in and operates Florida Gas, an interstate pipeline company that transports natural gas from producing areas in South Texas through the Gulf Coast region to Florida. Through SUGS , the Company owns approximately 5,600 miles of natural gas and NGL pipelines, five cryogenic plants with a combined capacity of 475 MMcf/d and five natural gas treating plants with combined capacities of 585 MMcf/d. SUGS is primarily engaged in connecting producing wells of exploration and production ( E&P ) companies 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. Its operations are located in West Texas and Southeast New Mexico. 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.

See Note 3 – ETE Merger for information related to the Company’s intent to merge with ETE.

2. Summary of Significant Accounting Policies and Other Matters

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.

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.

Additions. Ongoing additions of property, plant and equipment are stated at cost. The Company capitalizes all construction-related direct labor and material costs, as well as indirect construction costs. Such indirect construction costs primarily include capitalized interest costs (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.

Retirements. 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.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

Computer Software. Computer software, which is a component of property, plant and equipment, is stated at cost and is generally amortized on a straight-line basis over its useful life on a product-by-product basis.

For additional information, see Note 13 – Property, Plant and Equipment .

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 Distribution segment reporting unit level at least annually 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. The Company evaluated goodwill for potential impairment for the years ended December 31, 2011, 2010 and 2009, and no impairment was indicated in the step one test. There were no changes recorded to goodwill for the years ended December 31, 2011, 2010 and 2009.

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

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 Sheet. At December 31, 2011 and 2010, such book overdraft balances classified in accounts payable were approximately $21 million and $12 million, respectively.

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 – Reportable Segments 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

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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				2009

	(In thousands)

Beginning balance	$	3,321			$	1,874			$	6,003
Additions: charged to cost and expenses		8,089				8,681				8,601
Deductions: write-off of uncollectible accounts		(10,663	)			(8,230	)			(14,505	)
Other		1,578				996				1,775
Ending balance	$	2,325			$	3,321			$	1,874

Earnings Per Share. Basic earnings per share is computed based on the weighted average number of common shares outstanding during each period. Diluted earnings per share is computed based on the weighted average number of common shares outstanding during each period, the assumed exercises of stock options and SARs, and the assumed vesting of restricted stock. See Note 5 – Earnings Per Share .

Stock-Based Compensation. The Company measures all employee stock-based compensation using a fair value method and records the related expense in its Consolidated Statement of Operations. For more information, see Note 14 – Stock-Based Compensation.

Accumulated Other Comprehensive Loss. The main components of comprehensive income (loss) that relate to the Company are net earnings, unrealized gain (loss) on hedging activities and unrealized actuarial gain (loss)

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and prior service credits (cost) on pension and other postretirement benefit plans. For more information, see Note 7 – Comprehensive Income (Loss).

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 twelve 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.

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

	Transportation &		Gathering &
	Storage		Processing		Distribution		Total

	(In thousands)
December 31, 2011
Current
Natural gas (1)	$	95,916	$	-	$	62,307	$	158,223
Materials and supplies		18,823		12,543		4,756		36,122
NGL (2)		-		9,890		-		9,890
Total Current		114,739		22,433		67,063		204,235

Non-Current
Natural gas (1)		2,643		-		-		2,643
	$	117,382	$	22,433	$	67,063	$	206,878

December 31, 2010
Current
Natural gas (1)	$	129,727	$	-	$	55,856	$	185,583
Materials and Supplies		17,527		9,973		3,880		31,380
NGL (2)		-		9,912		-		9,912
Total Current		147,254		19,885		59,736		226,875

Non-Current
Natural gas (1)		5,715		-		-		5,715
	$	152,969	$	19,885	$	59,736	$	232,590

____________________

(1)

Natural gas volumes held for operations in the Transportation and Storage segment at December 31, 2011 and 2010 were 29,718,000 MMBtu and 30,598,000 MMBtu, respectively. Natural gas volumes held for operations in the Distribution segment at December 31, 2011 and 2010 were 14,191,000 MMBtu and 12,517,000 MMBtu, respectively.

(2)	NGL at December 31, 2011 and 2010 were 12,061,000 gallons and 12,061,000 gallons, respectively.

Unconsolidated Investments. Investments in affiliates over which the Company may exercise significant influence, generally 20 percent to 50 percent ownership interests, are accounted for using the equity method. Any

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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 – Unconsolidated Investments .

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 Statement 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 Sheet and included in the Consolidated Statement of Operations for the period in which the discontinuance of regulatory accounting treatment occurs. See Note 4 – Regulatory Assets.

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;

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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, 2011 and 2010.

See Note 12 – Fair Value Measurement and Note 9 – Benefits – Pension and Other Postretirement Plans – Plan Assets 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.

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. Capitalized interest for the years ended December 31, 2011, 2010 and 2009 was $1.2 million, $6.6 million and $25.7 million, respectively.

Derivative Instruments and Hedging Activities. All derivatives are recognized on the Consolidated Balance Sheet at their fair value. On the date the derivative contract is entered into, the Company designates the derivative as (i) a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment ( a fair value hedge ); (ii) a hedge of a forecasted transaction or the variability of cash flows to be received or paid in conjunction with a recognized asset or liability ( a cash flow hedge ); or (iii) an instrument that is held for trading or non-hedging purposes ( a trading or economic hedging instrument ). For derivatives treated as a fair value hedge, the effective portion of changes in fair value is recorded as an adjustment to the hedged item. The ineffective portion of a fair value hedge is recognized in earnings if the short cut method of assessing effectiveness is not used. 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

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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 – Derivative Instruments and Hedging Activities and Note 12 – Fair Value Measurement 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 21 – Asset Retirement Obligations .

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.

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 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 – Benefits 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 15 – Commitments and Contingencies.

New Accounting Principles

Accounting Principles Not Yet Adopted. In December 2011, the FASB issued authoritative guidance that enhances current disclosures about offsetting asset and liabilities. The guidance requires entities to disclose both

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gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The guidance is effective for annual and interim reporting periods beginning on or after January 1, 2013. The Company does not expect the guidance to materially impact its consolidated financial statements.

In September 2011, the FASB issued authoritative guidance that revises the testing of goodwill impairment. Under the revised guidance, entities testing goodwill for impairment have the option of performing a qualitative assessment before calculating the fair value of the reporting unit (i.e., step 1 of the goodwill impairment test). If the entity determines, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not less than the carrying amount, the two-step impairment test would be required. The guidance is effective as of the beginning of a fiscal year that begins after December 15, 2011 and interim and annual periods thereafter, with early adoption permitted. The Company does not expect the guidance to materially impact its consolidated financial statements.

In June 2011, the FASB issued authoritative guidance that changes how a company may present comprehensive income. The guidance allows entities to elect to present items of net income and other comprehensive income in one continuous statement or in two separate, but consecutive, statements and eliminates the current option to report other comprehensive income and its components in the statement of changes in equity. The entity is also required to present on the face of the financial statements reclassification adjustments for items that are reclassified from other comprehensive income to net income in the statement where the components of net income and the components of other comprehensive income are presented. The guidance is effective as of the beginning of a fiscal year that begins after December 15, 2011 and interim and annual periods thereafter, with early adoption permitted. In December 2011, the FASB issued authoritative guidance that defers the presentation requirements for reclassification adjustments to allow the FASB time to redeliberate these requirements. The Company does not expect the guidance to materially impact its consolidated financial statements as the guidance only requires a change in the placement of previously disclosed information.

In May 2011, the FASB issued authoritative guidance on fair value measurements that clarifies some existing concepts, eliminates wording differences between GAAP and International Financial Reporting Standards ( IFRS ), and in some limited cases, changes some principles to achieve convergence between GAAP and IFRS. The guidance provides a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between GAAP and IFRS and also expands the disclosures for fair value measurements that are estimated using significant unobservable (Level 3) inputs. The guidance is effective for periods beginning after December 15, 2011. The Company is currently evaluating the impact of this guidance, but does not expect it will materially impact its consolidated financial statements.

3. ETE Merger

On July 19, 2011, Southern Union entered into a Second Amended and Restated Agreement and Plan of Merger with ETE and Sigma Acquisition Corporation, a wholly-owned subsidiary of ETE ( Merger Sub ) (as amended by Amendment No. 1 to Second Amended and Restated Agreement and Plan of Merger dated as of September 14, 2011, the Second Amended Merger Agreement ). The Second Amended Merger Agreement modifies certain terms of the Agreement and Plan of Merger entered into by Southern Union, ETE and Merger Sub on June 15, 2011 as amended on July 4, 2011. The Second Amended Merger Agreement provides for the merger of Merger Sub with and into Southern Union ( Merger ), with Southern Union continuing as the surviving corporation in the Merger. As a result of the Merger, Southern Union will become a wholly-owned subsidiary of ETE. Under the terms of the Second Amended Merger Agreement, Company shareholders can elect to exchange each issued and outstanding share of Company common stock for $44.25 of cash or 1.00x ETE common unit, with no more than 60 percent of the aggregate merger consideration payable in cash and no more than 50 percent payable in ETE common units. Elections in excess of either the cash or common unit limits will be subject to proration. On February 17, 2012, the parties mailed merger consideration election forms to Southern Union shareholders of record as of February 10, 2012 and announced that the election deadline for Southern Union stockholders to make merger consideration elections is expected to be 5:00 p.m., Eastern Time, on March 19, 2012 (or such other later date as ETE and Southern Union shall agree).

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The Second Amended Merger Agreement contains certain termination rights for Southern Union and ETE. In certain circumstances, upon termination of the Second Amended Merger Agreement, Southern Union or ETE, as applicable: (i) will be required to pay a termination fee of $181.3 million to the other and (ii) may be obligated to pay the other’s Merger costs and expenses in an amount not to exceed $54 million.

In addition, ETE and ETP are parties to an Amended and Restated Agreement and Plan of Merger dated as of July 19, 2011 (as amended by Amendment No. 1 to Agreement and Plan of Merger dated as of September 14, 2011) ( Citrus Merger Agreement ). The Citrus Merger Agreement provides that Southern Union, CrossCountry Energy, LLC ( CrossCountry ), PEPL Holdings, LLC ( PEPL Holdings ) and Citrus ETP Acquisition, L.L.C. ( Citrus ETP ) will become parties by joinder at a time immediately prior to the closing of the Merger. Upon becoming a party to the Citrus Merger Agreement, Southern Union will assume the obligations and rights of ETE. Under the Citrus Merger Agreement, CrossCountry, a wholly-owned subsidiary of Southern Union that indirectly owns a 50 percent interest in Citrus, will be merged with and into Citrus ETP with CrossCountry surviving as a wholly-owned subsidiary of ETP ( Citrus Merger ).

Immediately prior to the Citrus Merger and in connection with ETP’s financing of the Citrus Merger consideration, Southern Union will contribute its ninety-nine percent interest in PEPL and its 100 percent membership interest in Southern Union Panhandle, LLC to PEPL Holdings. PEPL Holdings is a wholly-owned subsidiary of CCE Acquisition, LLC. PEPL Holdings will guarantee payment, on a contingent recourse basis, of up to $2.0 billion of indebtedness of ETP related to the Citrus Merger (or, in the alternative, will indemnify a subsidiary of ETP for payments made by such subsidiary with respect to a guarantee of up to $2.0 billion of indebtedness of ETP by such subsidiary). The guarantee will be non-recourse to Southern Union.

As consideration for the Citrus Merger, Southern Union will receive from ETP approximately $2.0 billion, consisting of $1.895 billion in cash and $105 million of ETP common units, with the value of the ETP common units based on the volume-weighted average trading price for the ten consecutive trading days ending immediately prior to the date that is three trading days prior to the closing date of the Citrus Merger. After completion of the Citrus Merger, including receipt of the Citrus Merger consideration, Southern Union will contribute an amount not to exceed $1.45 billion from the Citrus Merger to Merger Sub in exchange for an equity interest in Merger Sub. The remaining cash proceeds of approximately $445 million in cash would be used to retire existing Company debt. It is further anticipated that Southern Union or one of its subsidiaries would retain the approximately $105 million of ETP units as an investment in an unconsolidated affiliate. The consummation of the Citrus Merger is not a condition to consummation of the Merger.

While consummation of the Merger is subject to certain customary conditions, the parties have already satisfied a number of conditions, including without limitation: (i) the receipt of stockholder approval, which occurred on December 9, 2011, (ii) the expiration of the waiting period applicable to the merger under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, which expiration occurred on July 28, 2011, and (iii) the effectiveness, on October 27, 2011 of ETE’s Registration Statement on Form S-4 relating to the ETE common units to be issued in connection with the Merger.

Southern Union and ETE are also continuing to proceed with the regulatory approval process before the MPSC. Pursuant to a joint application filed by Southern Union and ETE on July 13, 2011 and amended on September 15, 2011, the parties requested an order from the MPSC authorizing Southern Union to take certain actions to allow ETE to acquire the equity interests of Southern Union, including its subsidiaries. On February 16, 2012, the parties filed with the MPSC a Non-Unanimous Stipulation and Agreement (the Stipulation ) among Southern Union, ETE and the MPSC Staff. Pursuant to the Stipulation, the parties recommend that the MPSC issue an order finding that, subject to the conditions therein, the merger of Merger Sub with and into Southern Union is not detrimental to the public interest and authorizing the undertaking of the Merger and related transactions. The Office of Public Counsel has indicated that it does not oppose the Stipulation. Southern Union and ETE have requested that the MPSC consider the Stipulation expeditiously.

The Merger is expected to close in the first quarter of 2012, subject to receipt of MPSC approval and satisfaction of other closing conditions.

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4. Regulatory Assets

The Company records regulatory assets with respect to its Distribution segment operations. 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.

The following table provides a summary of regulatory assets at the dates indicated.

	December 31,
	2011		2010

	(In thousands)

Pension and Other Postretirement Benefits	$	10,481	$	18,140
Environmental		35,869		38,384
Missouri Safety Program		448		1,147
Other		10,649		8,545
	$	57,447	$	66,216

The Company’s regulatory assets at December 31, 2011 relating to Distribution segment operations that are being recovered through current rates totaled $36.6 million. The remaining recovery period associated with these assets ranged from 3 months to 84 months. The Company expects that the $20.8 million of regulatory assets at December 31, 2011 not currently in rates will be included in its rates as rate cases occur in the future. The Company’s regulatory assets at December 31, 2010 relating to Distribution segment operations that are being recovered through current rates totaled $48.8 million. The remaining recovery period associated with these assets ranged from 7 months to 84 months.

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5. Earnings Per Share

The following table summarizes the Company’s basic and diluted EPS calculations for the periods presented.


	Years Ended December 31,
	2011		2010			2009

	(In thousands, except per share amounts)

Net earnings from continuing operations	$	255,424	$	242,648		$	179,580
Loss from discontinued operations		-		(18,100	)		-
Preferred stock dividends		-		(5,040	)		(8,683	)
Loss on extinguishment of preferred stock		-		(3,295	)		-
Net earnings available for common stockholders	$	255,424	$	216,213		$	170,897

Weighted average shares outstanding - Basic		124,720		124,474			124,076
Weighted average shares outstanding - Diluted		126,283		125,191			124,409

Basic earnings per share:
Net earnings available for common stockholders
from continuing operations	$	2.05	$	1.88		$	1.38
Loss from discontinued operations		-		(0.14	)		-
Net earnings available for common stockholders	$	2.05	$	1.74		$	1.38

Diluted earnings per share:
Net earnings available for common stockholders
from continuing operations	$	2.02	$	1.87		$	1.37
Loss from discontinued operations		-		(0.14	)		-
Net earnings available for common stockholders	$	2.02	$	1.73		$	1.37

A reconciliation of the shares used in the basic and diluted EPS calculations is shown in the following table for
the periods presented.

	Years Ended December 31,
	2011		2010		2009

	(In thousands)

Weighted average shares outstanding - Basic		124,720		124,474		124,076
Dilutive effect of stock-based compensation awards		1,563		717		333
Weighted average shares outstanding - Diluted		126,283		125,191		124,409

For the years ended December 31, 2011, 2010 and 2009, no adjustments were required in Net earnings available for common stockholders in the diluted EPS calculations.

Except for the Company’s purchase of common stock used to pay employee federal and state income tax obligations associated with the lapse of restrictions on restricted stock awards and exercises of SARs, the Company did not purchase any shares of its common stock outstanding during the years ended December 31, 2011, 2010 or 2009.

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The table below includes information related to stock options and SARs that were outstanding but have been excluded from the computation of weighted-average stock options due to the exercise price exceeding the weighted-average market price of the Company’s common shares.

	December 31,
	2011		2010			2009

	(In thousands, except per share amounts)

Options and SARs excluded		-			2,171			2,696
Exercise price ranges	$	-		$	24.04 - 28.48		$	21.64 - 28.48
Weighted-average market price	$	35.26		$	23.81		$	17.70

6. Unconsolidated Investments

Unconsolidated investments at December 31, 2011 and 2010 include the Company’s 50 percent investment in Citrus and investments in other entities. The Company accounts for these investments using the equity method. The Company’s share of net earnings or loss from these equity investments is 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		2010

	(In thousands)

Citrus (1)	$	1,608,549		$	1,510,847
Other		24,740			27,701
	$	1,633,289		$	1,538,548

_____________________

(1) See Note 3 – ETE Merger for information regarding the Company’s intent for its ownership interest in Citrus to be merged with an ETP subsidiary.

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

	December 31,
	2011						2010
				Other Equity						Other Equity
	Citrus			Investments			Citrus			Investments

	(In thousands)

Balance Sheet Data:
Current assets	$	260,530			$	8,247	$	107,108			$	14,106
Non-current assets		5,814,630				42,763		5,453,583				44,602
Current liabilities		847,505	(1)			1,149		316,952	(1)			2,139
Non-current liabilities		3,309,834				87		3,512,350				185

___________________

(1)	The current portion of long-term debt at December 31, 2011 and 2010 was $686.5 million and $21.5 million, respectively.

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		Years Ended December 31,
	2011						2010						2009
				Other Equity						Other Equity						Other Equity
	Citrus			Investments			Citrus			Investments			Citrus			Investments

	(In thousands)
Statement of Operations Data:
Revenues		$	693,626		$	9,801		$	517,158		$	22,492		$	508,416		$	20,395
Operating income			391,707			3,222			269,789			12,323			271,897			13,765
Net earnings			185,380			2,892			180,927			12,273			129,683			13,680

Citrus

Dividends. Citrus did not pay dividends to the Company during the years ended December 31, 2011, 2010 and 2009. Retained earnings at December 31, 2011 and 2010 included undistributed earnings from Citrus of $278.7 million and $181.1 million, respectively.

Citrus Excess Net Investment. The Company’s equity investment balances include 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 relate to the Company’s 50 percent equity ownership interest in Citrus. The following table sets forth the excess net investment of the Company’s 50 percent share of the underlying Citrus equity as of December 31, 2011.

	Excess			Amortization
	Purchase Costs			Period

	(In thousands)

Property, plant and equipment	$	2,885		40 years
Capitalized software		1,478		5 years
Long-term debt (1)		(80,204	)	4-20 years
Deferred taxes (1)		(6,883	)	40 years
Other net liabilities		(541	)		N/A
Goodwill (2)		664,609			N/A
Sub-total		581,344
Accumulated, net accretion to equity earnings		68,346
Net investment in excess of underlying equity	$	649,690

_____________________

(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.

Contingent Matters Potentially Impacting Southern Union Through the Company’s Investment in Citrus

In 2011, CrossCountry Citrus, LLC ( CrossCountry Citrus ), an indirect wholly-owned subsidiary of the Company, and Citrus’ other stockholder each made sponsor contributions of $37 million in the form of loans to Citrus, net of repayments. The Citrus loan has been recorded in Other non-current assets on the Consolidated Balance Sheet. The contributions are related to the costs of Florida Gas' Phase VIII Expansion project. In conjunction with anticipated sponsor contributions, Citrus has entered into a promissory note in favor of each stockholder for up to

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$150 million. The promissory notes have a final maturity date of March 31, 2014, with no principal payments required prior to the maturity date, and bear an interest rate equal to a one-month Eurodollar rate plus a credit spread of 1.5 percent. Amounts may be redrawn periodically under the notes to temporarily fund capital expenditures, debt retirements, or other working capital needs. Citrus’ principal operating asset is Florida Gas, whose debt is rated Baa2 by Moody’s Investor Services, Inc. and BBB by Standard & Poors.

In 2010, CrossCountry Citrus and Citrus’ other stockholder each made a $100 million sponsor capital contribution in the form of equity to Citrus to partially fund the Phase VIII Expansion. The Company’s $100 million capital contribution was funded using its credit facilities.

Florida Gas Rate Filing. On September 3, 2010, Florida Gas filed a settlement with FERC in full resolution of all issues set for hearing in its rate proceeding. The Administrative Law Judge certified the settlement on December 21, 2010. The settlement was approved by FERC on February 24, 2011 and became effective on April 1, 2011. The settlement results in an increase in certain of Florida Gas’ rate schedules and a decrease in other rate schedules as compared to rates in effect prior to April 1, 2010, with a portion of such decrease not effective until October 1, 2010.

Florida Gas Debt Issuance . In July 2010, Florida Gas issued $500 million of 5.45% Senior Notes due July 15, 2020 with an offering price of $99.826 (per $100 principal) and $350 million of 4.00% Senior Notes due July 15, 2015 with an offering price of $99.982 (per $100 principal). Florida Gas used the net proceeds to partially fund the Phase VIII Expansion project and for general corporate purposes, which included the repayment of a portion of Florida Gas’ outstanding debt. On July 19, 2010, Florida Gas (i) made a $98.6 million distribution to Citrus, (ii) repaid $83 million that was outstanding under its credit agreements, and (iii) invested the remainder of the proceeds. On August 19, 2010, Florida Gas redeemed its $325 million of 7.625% notes due December 1, 2010.

Retirement of Debt Obligations. As noted in the Citrus financial statements, Citrus expects to refinance Florida Gas’ $250 million senior notes due July 2012 and extend the maturity or refinance both of the 2007 Citrus Revolver and the 2007 Florida Gas Revolver, each due August 2012. Alternatively, should Citrus not be successful in such efforts, Citrus may choose to retire such debt upon maturity by utilizing some combination of cash flows from operations, utilizing available funds on existing sponsor loans from its stockholders, requesting additional sponsor loans from its stockholders and altering the timing of controllable expenditures, among other things. Citrus has obtained commitment letters from each of its stockholders to make additional sponsor loans in the event that the repayment of the senior notes and revolvers is necessary. However, Citrus reasonably believes, based on its investment grade credit ratings and general financial condition, successful historical access to capital and debt markets and market expectations regarding Citrus’ future earnings and cash flows, that it will be able to refinance and/or retire these obligations, as applicable, under acceptable terms prior to their maturity.

Environmental Matters. Florida Gas is responsible for environmental remediation of contamination resulting from past releases of hydrocarbons and chlorinated compounds at certain sites on its natural gas transmission systems. Florida Gas is implementing a program to remediate such contamination. 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. The outcome of these matters is not expected to have a material adverse impact on the Company’s equity investment in Citrus.

Regulatory Assets and Liabilities. Florida Gas is subject to regulation by certain state and federal authorities. Florida Gas has accounting policies that conform to regulatory accounting standards and are in accordance with the accounting requirements and ratemaking practices of applicable regulatory authorities. Florida Gas management’s assessment of the probability of its recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, Florida Gas 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 its consolidated balance sheet, resulting in an impact to the Company’s share of its equity earnings. Florida Gas’ regulatory asset and liability balances at December 31, 2011 were $32.7 million and $12.8 million, respectively.

Florida Gas Pipeline Relocation Costs. The FDOT/FTE has various turnpike/State Road 91 widening projects that have impacted or may, over time, impact one or more of Florida Gas’ mainline pipelines located in FDOT/FTE rights-of-way. Several FDOT/FTE projects are the subject of litigation in Broward County, Florida. On January 27, 2011, a jury awarded Florida Gas $82.7 million and rejected all damage claims by the FDOT/FTE. On May 2, 2011, the judge issued an order entitling Florida Gas to an easement of 15 feet on either side of its pipelines and 75 feet of temporary work space. The judge further ruled that Florida Gas is entitled to approximately $8 million in interest. In addition to ruling on other aspects of the easement, he ruled that pavement could not be placed directly over Florida Gas’ pipeline without the consent of Florida Gas although Florida Gas would be required to relocate the pipeline if it did not provide such consent. He also denied all other pending post-trial motions. The FDOT/FTE filed a notice of appeal on July 12, 2011. Briefing to the Florida Fourth District Court of Appeals ( 4 th DCA ) is complete. The 4 th DCA granted a request by the FDOT to expedite the appeal. Oral argument is set for March 7, 2012. Amounts ultimately received would primarily reduce Florida Gas’ property, plant and equipment costs.

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On April 14, 2011 Florida Gas filed suit against the FDOT/FTE, Dragados USA and I-595 Express, LLC in Broward County, Florida seeking an injunction and damages as the result of the construction of a mechanically stabilized earth wall and other encroachments in Florida Gas easements. The same judge that presided over the previously discussed FDOT/FTE proceeding was assigned to the case. Trial is expected to be set in the third quarter of 2012.

Federal Pipeline Integrity Rules. On December 15, 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule defines as HCAs. This rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002. The rule required operators to identify HCAs along their pipelines and to complete baseline integrity assessments, comprised of in-line inspection (smart pigging), hydrostatic testing or direct assessment, by December 2012. Operators were required to rank the risk of their pipeline segments containing HCAs; assessments are generally conducted on the higher risk segments first. In addition, some system modifications will be necessary to accommodate the in-line inspections. As of December 31, 2011, Florida Gas had completed approximately 96 percent of the baseline risk assessments required to be completed by December 2012. While identification and location of all the HCAs has been completed, it is not practicable to determine with certainty the total scope of required remediation activities prior to completion of the assessments and inspections. The required modifications and inspections are currently estimated to be in the range of approximately $30 million to $40 million per year through 2012.

See Note 3 – ETE Merger for information related to the Citrus Merger, pursuant to which CrossCountry, a subsidiary of the Company that indirectly owns a 50 percent interest in Citrus, would become a wholly-owned subsidiary of ETP.

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

7. Comprehensive Income (Loss)


The table below presents Comprehensive income (loss) for the periods presented.

	Years Ended December 31,
	2011			2010			2009

	(In thousands)

Net Earnings	$	255,424		$	224,548		$	179,580

Change in fair value of interest rate hedges, net of tax of $(27,589),
$(5,237) and $(3,051), respectively		(46,470	)		(7,790	)		(4,538	)
Reclassification of unrealized loss (gain) on interest rate hedges
into earnings, net of tax of $9,012, $9,019 and $8,222, respectively		13,443			13,463			12,350
Change in fair value of commodity hedges, net of tax of $2,598,
$14,093 and $3,773, respectively		4,610			25,012			6,696
Reclassification of unrealized (gain) loss on commodity hedges into
earnings, net of tax of $(8,536), $(6,787) and $(16,231), respectively		(15,149	)		(12,046	)		(28,804	)
Actuarial gain (loss) relating to pension and other postretirement
benefits, net of tax of $(24,240), $(4,472) and $6,535, respectively		(38,786	)		(5,319	)		8,185
Prior service cost relating to pension and other postretirement
benefit plan amendments, net of tax of $0, $0 and $(151),
respectively		-			-			(186	)
Reclassification of net actuarial loss and prior service credit
relating to pension and other postretirement benefits into
earnings, net of tax of $2,234, $2,205 and $2,814, respectively		3,174			2,886			4,035
Change in other comprehensive income (loss) from equity
investments, net of tax of $88, $88 and $(1,744), respectively		143			142			(2,820	)
Total other comprehensive income (loss)		(79,035	)		16,348			(5,082	)
Total comprehensive income	$	176,389		$	240,896		$	174,498

The table below presents the components in Accumulated other comprehensive loss as of the
dates indicated.

		December 31,
		2011		2010

			(In thousands)

Interest rate hedges, net		$	(50,259)	$	(17,232)
Commodity hedges, net			(11)		10,528
Benefit plans:
	Net actuarial loss and prior service costs, net - pensions		(51,845)		(32,982)
	Net actuarial gain and prior service credit, net - other postretirement benefits		(14,542)		2,207
Equity investments, net			(2,535)		(2,678)
Total Accumulated other comprehensive loss, net of tax		$	(119,192)	$	(40,157)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

8. Debt Obligations


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


	December 31, 2011				December 31, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value

	(In thousands)

Long-Term Debt Obligations:

Southern Union:
7.60% Senior Notes due 2024	$	359,765	$	417,666	$	359,765	$	392,144
8.25% Senior Notes due 2029		300,000		386,112		300,000		332,922
7.24% to 9.44% First Mortgage Bonds
due 2020 to 2027		19,500		23,439		19,500		21,473
7.20% Junior Subordinated Notes due 2066 (1)		600,000		546,480		600,000		609,743
Term Loan due 2013		250,000		251,854		250,000		249,915
Note Payable		7,746		7,746		8,297		8,297
		1,537,011		1,633,297		1,537,562		1,614,494

Panhandle:
6.05% Senior Notes due 2013		250,000		265,573		250,000		268,988
6.20% Senior Notes due 2017		300,000		340,494		300,000		322,893
8.125% Senior Notes due 2019		150,000		185,301		150,000		169,671
7.00% Senior Notes due 2029		66,305		75,128		66,305		69,911
7.00% Senior Notes due 2018		400,000		467,072		400,000		442,120
Term Loans due 2012		797,386		794,751		815,391		799,084
Net premiums on long-term debt		2,924		2,924		2,731		2,731
		1,966,615		2,131,243		1,984,427		2,075,398

Total Long-Term Debt Obligations		3,503,626		3,764,540		3,521,989		3,689,892

Credit Facilities		200,000		200,009		297,051		301,312

Total consolidated debt obligations		3,703,626	$	3,964,549		3,819,040	$	3,991,204
Less current portion of long-term debt (2)		343,254				1,083
Less short-term debt		200,000				297,051
Total long-term debt	$	3,160,372			$	3,520,906

____________________

(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 percent, reset quarterly. See Junior Subordinated Notes below for more information regarding the interest rate on these notes.

(2)	Excludes $455 million related to the 2012 Term Loan that was refinanced in February 2012 resulting in a change of the maturity date to February 2016. See Retirement of Debt Obligations below for more information.

The fair value of the Company’s term loans and credit facilities as of December 31, 2011 and 2010 were determined using the market approach, which utilized reported recent loan transactions for parties of similar credit quality and remaining life, as there is no active secondary market for loans of these types and sizes.

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The fair value of the Company’s other long-term debt as of December 31, 2011 and 2010 was also determined using the market approach, which utilized observable market data to corroborate the estimated credit spreads and prices for the Company’s non-bank long-term debt securities in the secondary market. Those valuations were based in part upon the reported trades of the Company’s non-bank long-term debt securities where available and the actual trades of debt securities of similar credit quality and remaining life where no secondary market trades were reported for the Company’s non-bank long-term debt securities.

Long-Term Debt. Southern Union has approximately $3.5 billion of long-term debt, including net premiums of $2.9 million, recorded at December 31, 2011, of which $343.3 million is current. Debt of $2.83 billion is at fixed rates ranging from 3.63 percent to 9.44 percent. Southern Union also has floating rate debt totaling $667.4 million, bearing an interest rate of 0.85 to 3.45 percent as of December 31, 2011.

As of December 31, 2011, the Company has scheduled long-term debt payments, excluding net premiums on debt, as follows:

															2017
	2012		2013			2014			2015			2016			and thereafter

	(In thousands)

Southern Union Company	$	868		$	250,797		$	772		$	751		$	708		$	1,283,115
Panhandle		342,386			250,000			-			455,000			-			916,305

Total	$	343,254		$	500,797		$	772		$	455,751		$	708		$	2,199,420

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.

Junior Subordinated Notes. The Company has interest rate swap agreements that effectively fix the interest rate applicable to the floating rate on $525 million of the $600 million Junior Subordinated Notes due 2066 ( Junior Subordinated Notes ). See Note 11 – Derivative Instruments and Hedging Activities – Interest Rate Contracts – Interest Rate Swaps for more information regarding these swap agreements. The interest rate on the remaining notes is a variable rate based upon the three-month LIBOR rate plus 3.0175 percent. The balance of the variable rate portion of the Junior Subordinated Notes was $75 million at an effective interest rate of 3.45 percent at December 31, 2011. The balance and effective interest rate at February 17, 2012 were $75 million and 3.45 percent, respectively.

Term Loans. On August 3, 2010, the Company entered into an Amended and Restated $250 million Credit Agreement, maturing on August 3, 2013 ( 2010 Term Loan ). The 2010 Term Loan bears interest at a rate of LIBOR plus 2.125 percent. The balance of the 2010 Term Loan was $250 million and $250 million at effective interest rates of 2.40 percent and 2.39 percent at December 31, 2011 and 2010, respectively. The balance and effective interest rate of the 2010 Term Loan at February 17, 2012 were $250 million and 2.38 percent, respectively.

On March 15, 2007, LNG Holdings, as borrower, and PEPL and Trunkline LNG, as guarantors, entered into a $455 million unsecured term loan facility due March 13, 2012 ( 2012 Term Loan ). The interest rate under the 2012 Term Loan is a floating rate tied to LIBOR or the prime rate, at the Company’s option, in addition to a margin based on the rating of PEPL’s senior unsecured debt. LNG Holdings has entered into interest rate swap agreements that effectively fix the interest rate applicable to the 2012 Term Loan at 4.98 percent plus a credit spread of 0.625 percent, based upon PEPL’s credit rating for its senior unsecured debt. The balance of the 2012

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Term Loan was $455 million at December 31, 2011 and 2010. See Note 11 – Derivative Instruments and Hedging Activities – Interest Rate Swaps for information regarding interest rate swaps.

On June 29, 2007, LNG Holdings, as borrower, and PEPL and CrossCountry Citrus, LLC, as guarantors, entered into an amended and restated $465 million term loan facility ( Amended Credit Agreement ) due June 29, 2012, with an interest rate of LIBOR plus 55 basis points, based upon the current credit rating of PEPL's senior unsecured debt. The balance of the Amended Credit Agreement was $342.4 million and $360.4 million at effective interest rates of 0.85 and 0.81 percent at December 31, 2011 and 2010, respectively. The balance and effective interest rate of the Amended Credit Agreement at February 17, 2012 were $342.4 million and 0.82 percent, respectively.

Credit Facilities. During the second quarter of 2011, the Company entered into the Seventh Amended and Restated Revolving Credit Agreement with the banks named therein in the amount of $550 million (2011 Revolver) . The 2011 Revolver is an amendment, restatement and refinancing of the Company’s $550 million revolving credit facility, which was otherwise scheduled to mature on May 28, 2013. The 2011 Revolver will mature on May 20, 2016. Borrowings on the 2011 Revolver 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 2011 Revolver are calculated using a pricing grid, which is based upon the credit rating for the Company’s senior unsecured notes. The annualized interest rate and commitment fee rate bases for the 2011 Revolver at December 31, 2011 were LIBOR, plus 162.5 basis points, and 25 basis points, respectively.

The Company’s additional $25 million short-term committed credit facility was renewed in July 2011 for an additional 364-day period.

Balances of $200 million and $297.1 million were outstanding under the Company’s credit facilities at effective interest rates of 1.88 and 3.02 percent at December 31, 2011 and 2010, respectively. The Company classifies its borrowings under the credit facilities as short-term debt as the individual borrowings are generally for periods of 15 to 180 days. At maturity, the Company may (i) retire the outstanding balance of each borrowing with available cash on hand and/or proceeds from a new borrowing, or (ii) at the Company’s option, extend the borrowing’s maturity date for up to an additional 90 days. As of February 17, 2012, there was a balance of $148.3 million outstanding under the Company’s credit facilities at an average effective interest rate of 1.86 percent.

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. 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.

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 Southern Union’s debt and other financial obligations and that of its subsidiaries. Under the current credit agreements, the significant debt covenants and cross defaults are as follows:

a)	Under the Company’s 2011 Revolver, the consolidated debt to total capitalization ratio, as defined therein, cannot exceed 65 percent;

b)	Under the Company’s 2011 Revolver, the Company must maintain an earnings before interest, tax, depreciation and amortization interest coverage ratio of at least 2.00 times;

c)	Under the Company’s First Mortgage Bond indentures for the Fall River Gas division of New England Gas Company, the Company’s consolidated debt to total capitalization ratio, as defined therein, cannot exceed 70 percent at the end of any calendar quarter; and

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d)	All of the Company’s major borrowing agreements contain cross-defaults if the Company defaults on an agreement involving at least $10 million of principal.

In addition to the above restrictions and default provisions, the Company and/or its subsidiaries are subject to a number of 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.

Retirement of Debt Obligations. The Company refinanced LNG Holdings’ $455 million term loan due March 13, 2012 on February 23, 2012 with an unsecured three-year term loan facility due February 23, 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 Company expects to retire the $465 million term loan due June 2012 ($342.4 million of which is outstanding at December 31, 2011) utilizing a portion of the $445 million in merger consideration to be received by Southern Union in connection with the Citrus Merger. Should the Citrus Merger not occur by the June 2012 maturity date, the Company would expect to refinance and/or extend the $465 million term loan, or alternatively the Company might choose to retire such debt upon maturity by utilizing some combination of cash flows from operations, draw downs under existing credit facilities and altering the timing of controllable expenditures, among other things. The Company reasonably believes, based on its investment grade credit ratings and general financial condition, successful historical access to capital and debt markets and market expectations regarding the Company’s future earnings and cash flows, that it will be able to refinance and/or retire these obligations, as applicable, under acceptable terms prior to their maturity. There can be no assurance, however, that the Company will be able to achieve acceptable refinancing terms in any negotiation of new capital market debt or bank financings. Moreover, there can be no assurance the Company will be successful in its implementation of these refinancing and/or retirement plans and the Company’s inability to do so could cause a material adverse effect on the Company’s financial condition and liquidity.

9. Benefits

Pension and Other Postretirement Benefit Plans

The Company has funded non-contributory defined benefit pension plans ( 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 Company has postretirement health care and life insurance plans ( other postretirement plans ) that cover substantially all Distribution and Transportation and Storage segment employees and 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.

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Obligations and Funded Status

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

	Pension Benefits						Other Postretirement Benefits
	December 31,						December 31,
	2011			2010			2011			2010

	(In thousands)

Change in benefit obligation:
Benefit obligation at beginning of period	$	193,686		$	177,235		$	109,768		$	98,055
Service cost		3,657			3,251			3,480			3,064
Interest cost		10,140			10,172			6,050			5,612
Benefits paid, net		(10,511	)		(10,546	)		(2,585	)		(3,224	)
Medicare Part D subsidy receipts		-			-			318			305
Actuarial loss and other		28,105			13,574			18,094			5,956
Benefit obligation at end of period	$	225,077		$	193,686		$	135,125		$	109,768

Change in plan assets:
Fair value of plan assets at beginning of period	$	127,000		$	115,863		$	102,146		$	68,903
Return on plan assets and other		(651	)		15,195			298			8,808
Employer contributions		16,957			6,488			10,363			27,659
Benefits paid, net		(10,511	)		(10,546	)		(2,585	)		(3,224	)
Fair value of plan assets at end of period	$	132,795		$	127,000		$	110,222		$	102,146

Amount underfunded at end of period	$	(92,282	)	$	(66,686	)	$	(24,903	)	$	(7,622	)

Amounts recognized in the Consolidated
Balance Sheet consist of:
Noncurrent assets	$	-		$	-		$	3,560		$	6,279
Current liabilities		(13	)		(13	)		(239	)		(170	)
Noncurrent liabilities		(92,269	)		(66,673	)		(28,224	)		(13,731	)
	$	(92,282	)	$	(66,686	)	$	(24,903	)	$	(7,622	)

Amounts recognized in Accumulated other
comprehensive loss (pre-tax basis) consist of:
Net actuarial loss (gain)	$	82,790		$	51,365		$	24,723		$	(246	)
Prior service cost		1,964			2,551			2,885			1,074
	$	84,754		$	53,916		$	27,608		$	828

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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
	December 31,						December 31,
	2011			2010			2011			2010

	(In thousands)

Projected benefit obligation		$	225,077		$	193,686			N/A			N/A
Accumulated benefit obligation			212,056			183,529		$	104,083		$	82,287
Fair value of plan assets			132,795			127,000			75,620			68,385

Net Periodic Benefit Cost

Net periodic benefit cost for the periods presented includes the components noted in the table below.

	Pension Benefits									Other Postretirement Benefits
	Years Ended December 31,									Years Ended December 31,
	2011			2010			2009			2011			2010			2009

	(In thousands)
Net Periodic Benefit Cost:
Service cost	$	3,657		$	3,251		$	2,778		$	3,480		$	3,064		$	2,970
Interest cost		10,140			10,172			9,955			6,050			5,612			5,481
Expected return on plan assets		(10,653	)		(9,348	)		(8,577	)		(5,820	)		(4,918	)		(3,123	)
Prior service cost (credit)
amortization		587			552			552			(1,811	)		(1,647	)		(1,260	)
Actuarial loss (gain)
amortization		7,985			8,048			8,405			(1,353	)		(1,862	)		(847	)
		11,716			12,675			13,113			546			249			3,221
Regulatory adjustment (1)		868			(4	)		54			2,665			2,665			2,665
Net periodic benefit cost	$	12,584		$	12,671		$	13,167		$	3,211		$	2,914		$	5,886

________________________________

(1)

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 2012 are $10.3 million and $580,000, 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 2012 are $1.3 million and $(1.1) million, respectively.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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
	December 31,						December 31,
	2011			2010			2011			2010

Discount rate		4.14	%		5.35	%		4.14	%		5.36	%
Rate of compensation increase		3.02	%		3.02	%		N/A			N/A

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
	Years Ended December 31,									Years Ended December 31,
	2011			2010			2009			2011			2010			2009

Discount rate		5.35	%		5.82	%		6.05	%		5.36	%		5.85	%		6.05	%
Expected return on assets:
Tax exempt accounts		8.25	%		8.25	%		8.50	%		7.00	%		7.00	%		7.00	%
Taxable accounts		N/A			N/A			N/A			4.50	%		5.00	%		5.00	%
Rate of compensation increase		3.02	%		3.24	%		3.24	%		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.

	December 31,
	2011			2010

Health care cost trend rate assumed for next year		8.50	%		9.00	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)		4.75	%		4.75	%
Year that the rate reaches the ultimate trend rate		2019			2019

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

	One Percentage			One Percentage
	Point Increase			Point Decrease

	(In thousands)

Effect on total of service and interest cost		$	878		$	(847	)
Effect on accumulated postretirement benefit obligation			11,809			(10,806	)

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 percent to 70 percent, fixed income of 15 percent to 35 percent, alternative assets of 10 percent to 35 percent and cash of 0 percent to 10 percent. To achieve diversity within its other postretirement plan asset portfolio, the Company has targeted the following asset allocations: equity of 25 percent to 35 percent, fixed income of 65 percent to 75 percent and cash and cash equivalents of 0 percent to 10 percent. These target allocations 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				Fair Value Measurements at December 31, 2011
	as of				Using Fair Value Hierarchy
	December 31, 2011				Level 1			Level 2			Level 3

	(In thousands)
Asset Category:
Cash and cash
equivalents	$	11,791				$	11,791		$	-		$	-
Mutual fund		110,632	(1	)			-			110,632			-
Multi-strategy
hedge funds		10,372	(2	)			-			10,372			-
Total	$	132,795				$	11,791		$	121,004		$	-

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Fair Value				Fair Value Measurements at December 31, 2010
	as of				Using Fair Value Hierarchy
	December 31, 2010				Level 1			Level 2			Level 3

	(In thousands)
Asset Category:
Cash and cash
equivalents	$	4,901				$	4,901		$	-		$	-
Mutual fund		111,829	(1	)			-			111,829			-
Multi-strategy
hedge funds		10,270	(2	)			-			10,270			-
Total	$	127,000				$	4,901		$	122,099		$	-

___________________

(1)

This comingled fund invests primarily in a diversified portfolio of equity and fixed income funds. As of December 31, 2011, the fund was primarily comprised of approximately 36 percent large-cap U.S. equities, 6 percent small-cap U.S. equities, 20 percent international equities, 30 percent fixed income securities, and 8 percent in other investments. As of December 31, 2010, the fund was primarily comprised of approximately 38 percent large-cap U.S. equities, 8 percent small-cap U.S. equities, 20 percent international equities, 29 percent fixed income securities, and 5 percent 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				Fair Value Measurements at December 31, 2011
		as of				Using Fair Value Hierarchy
	December 31, 2011					Level 1			Level 2			Level 3

		(In thousands)
Asset Category:
Cash and Cash
Equivalents		$	2,476				$	2,476		$	-		$	-
Mutual fund			107,746	(1	)			107,746			-			-
Total		$	110,222				$	110,222		$	-		$	-


		Fair Value				Fair Value Measurements at December 31, 2010
		as of				Using Fair Value Hierarchy
	December 31, 2010					Level 1			Level 2			Level 3

		(In thousands)
Asset Category:
Cash and Cash
Equivalents		$	2,303				$	2,303		$	-		$	-
Mutual fund			99,843	(1	)			99,843			-			-
Total		$	102,146				$	102,146		$	-		$	-

___________________

(1)

This fund of funds primarily invests in a combination of equity, fixed income and short-term mutual funds. As of December 31, 2011, the fund was primarily comprised of approximately 19 percent large-cap U.S. equities, 2 percent small-cap U.S. equities, 10 percent international equities, 55 percent fixed income securities, 8 percent cash, and 6 percent in other investments. As of December 31, 2010, the fund was primarily comprised of approximately 17 percent large-cap U.S. equities, 4 percent small-cap U.S. equities, 10 percent international equities, 57 percent fixed income securities, 10 percent cash, and 2 percent in other investments.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 2 – Summary of Significant Accounting Policies and Other Matters – Fair Value Measurements for 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 $16.8 million to its pension plans and approximately $10.9 million to its other postretirement plans in 2012. 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.

					Other			Other
					Postretirement			Postretirement
					Benefits			Benefits
			Pension		(Gross, Before			(Medicare Part D
Years			Benefits		Medicare Part D)			Subsidy Receipts)

			(In thousands)
2012			$	11,703		$	4,798		$	584
2013				11,860			5,553			606
2014				12,328			6,422			712
2015				12,031			7,219			819
2016				12,075			7,960			958
2017	-	2021		64,869			48,348			6,532

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 2009 through 2011 ranging from 2 percent to 6.25 percent of the participant’s compensation paid into the Savings Plan. Company contributions are 100 percent 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 percent vested after six years of continuous service. Company contributions to the Savings Plan during the years ended December 31, 2011, 2010 and 2009 were $7.6 million, $7.4 million and $7 million, respectively.

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 percent to 12 percent. Company contributions are generally 100 percent vested after five years of continuous service. Company contributions to Retirement Power Accounts during the years ended December 31, 2011, 2010 and 2009 were $8.1 million, $7.9 million and $7.9 million, respectively.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10. Taxes on Income

The following table provides a summary of the current and deferred components of income tax expense from continuing operations for the periods presented.

		Years Ended December 31,
		2011		2010		2009

					(In thousands)
Current:
	Federal	$	4,637	$	1,963	$	(44,060)
	State		(4,395)		(2,352)		(5,250)
			242		(389)		(49,310)

Deferred:
	Federal		95,972		93,330		108,956
	State		7,566		14,088		12,254
			103,538		107,418		121,210

Total federal and state income tax
	expense from continuing operations	$	103,780	$	107,029	$	71,900

Effective tax rate			29%		31%		29%

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) at the dates indicated.

	December 31,
	2011			2010

	(In thousands)
Deferred income tax assets:
Alternative minimum tax credit	$	38,391		$	36,526
Other postretirement benefits		21,837			20,206
Pension benefits		32,495			23,491
Derivative financial instruments (interest rates)		32,057			13,571
Net operating loss		24,750			-
Other		34,566			39,245
Total deferred income tax assets		184,096			133,039

Deferred income tax liabilities:
Property, plant and equipment		(1,139,135	)		(1,032,473	)
Unconsolidated investments (Citrus)		(29,059	)		(19,177	)
Goodwill		(16,718	)		(16,952	)
Environmental reserve		(11,641	)		(9,374	)
Other		(19,268	)		(32,296	)
Total deferred income tax liabilities		(1,215,821	)		(1,110,272	)
Net deferred income tax liability		(1,031,725	)		(977,233	)
Less current income tax assets (liabilities)		13,152			36,630
Accumulated deferred income taxes	$	(1,044,877	)	$	(1,013,863	)

The Company has federal net operating loss (NOL) carryforwards of $65 million, of which $15 million will expire in 2030 and $50 million in 2031. The Company has state NOL carryforwards of $52 million, expiring between 2013 and 2031.

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

	Years Ended December 31,
	2011			2010			2009

	(In thousands)

Computed statutory income tax expense at 35%	$	125,721		$	122,387		$	88,018
Changes in income taxes resulting from:
Earnings from unconsolidated investments related to
anticipated receipt of dividends		(27,317	)		(26,973	)		(20,300	)
State income taxes, net of federal income tax benefit		2,296			7,878			4,553
Other		3,080			3,737			(371	)
Actual income tax expense from continuing operations	$	103,780		$	107,029		$	71,900

Due to the anticipated increase in dividends from Citrus as a result of the Phase VIII Expansion, the Company expects the entire deferred income tax liability related to its investment in Citrus would be realized at the Company’s statutory income tax rate less the dividends received deduction.

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

	Years ended December 31,
	2011			2010			2009

	(In thousands)

Beginning of the year	$	15,837		$	12,864		$	7,210

Additions:
Tax positions taken in prior years		188			-			2,195
Tax positions taken in current year		3,354			3,146			3,459

Reductions:
Settlements		(791	)		(173	)		-
End of year	$	18,588		$	15,837		$	12,864

As of December 31, 2011, the Company has unrecognized tax benefits for capitalization policies and state filing positions of $2.3 million and $16.3 million, respectively. However, only the $16.3 million ($10.6 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 $3.3 million ($2.1 million, net of federal tax) within the next twelve months due to settlement of certain state filing positions.

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

During 2011, the Company recognized interest and penalties of $726,000 ($709,000, net of tax). At December 31, 2011, the Company has interest and penalties accrued of $2.1 million ($1.8 million, net of tax).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company is no longer subject to U.S. federal, state or local examinations for the tax period ended December 31, 2004 and prior years, except June 30, 2004, to the extent of $1.3 million of refund claims.

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 Sheet.

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 associated with the $600 million Junior Subordinated Notes due 2066 ( Junior Subordinated Notes ) 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 will pay interest on the Junior Subordinated Notes at the floating rate of three-month LIBOR plus a credit spread of 3.0175 percent 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 loss and reclassified into Interest expense in the same periods during which the related interest payments on long-term debt impact earnings. As of December 31, 2011, the floating rate LIBOR-based portion of the interest payments commencing November 1, 2011 was exchanged for weighted average fixed rate interest payments of 3.63 percent.

The Company also has outstanding pay-fixed interest rate swaps with a total notional amount of $455 million applicable to the LNG Holdings $455 million term loan. These interest rate swaps are accounted for as cash flow hedges, with the effective portion of changes in their fair value recorded in Accumulated other comprehensive loss and reclassified into Interest expense in the same periods during which the related interest payments on long-term debt impact earnings.

As of December 31, 2011, approximately $12.4 million of net after-tax losses in Accumulated other comprehensive loss related to these interest rate swaps is expected to be amortized into Interest expense during the next twelve months. There was no swap ineffectiveness during the period ended December 31, 2011. Any ineffective portion of the cash flow hedge would be reported in current-period earnings.

Treasury Rate Locks. As of December 31, 2011, the Company had no outstanding treasury rate locks. However, certain of its treasury rate locks that settled in prior periods are associated with interest payments on outstanding long-term debt. These treasury rate locks are accounted for as cash flow hedges, with the effective portion of their settled value recorded in Accumulated other comprehensive loss and reclassified into Interest expense in the same periods during which the related interest payments on long-term debt impact earnings. As of December 31, 2011, approximately $571,000 of net after-tax losses in Accumulated other comprehensive loss related to these treasury rate locks will be amortized into Interest expense during the next twelve months.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 equity natural gas and NGL volumes resulting from movements in market commodity prices.

Natural Gas Price Swaps. As of December 31, 2011, the Company had outstanding receive-fixed natural gas price swaps with a total notional amount of 3,660,000 MMBtus for 2012. 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 loss and reclassified into Operating revenues in the same periods during which the forecasted natural gas sales impact earnings. As of December 31, 2011, approximately $4 million of net after-tax gains in Accumulated other comprehensive loss related to these natural gas price swaps are expected to be amortized into Operating revenues during the next twelve months. Any ineffective portion of the cash flow hedge is reported in current-period earnings.

NGL Price Swaps. As of December 31, 2011, the Company had outstanding receive-fixed NGL price swaps with a total notional amount of 65,378,124 gallons (5,490,000 MMBtu equivalent basis) for 2012. These NGL price swaps are accounted for as cash flow hedges, with the effective portion of changes in their fair value recorded in Accumulated other comprehensive loss and reclassified into Operating revenues in the same periods during which the forecasted NGL sales impact earnings. As of December 31, 2011, approximately $4 million of net after-tax losses in Accumulated other comprehensive loss related to these NGL price swaps are expected to be amortized into Operating revenues during the next twelve months. Any ineffective portion of the cash flow hedge is reported in current-period earnings.

Commodity Contracts - Distribution Segment

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, 2011, the Company had outstanding pay-fixed natural gas price swaps with total notional amounts of 19,400,000 MMBtu and 5,560,000 MMBtu for 2012 and 2013, respectively. These natural gas price swaps are accounted for as economic hedges, with changes in their fair value recorded to Deferred natural gas purchases.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Summary Financial Statement Information

The following table summarizes the fair value amounts of the Company’s derivative instruments and their location in the Consolidated Balance Sheet at the dates indicated.

	Asset Derivatives (1)				Liability Derivatives (1)
	December 31,				December 31,
Balance Sheet Location	2011		2010		2011		2010

	(In thousands)				(In thousands)
Cash Flow Hedges:
Interest rate contracts
Derivative instruments-liabilities	$	-	$	-	$	19,936	$	19,694
Deferred credits		-		-		59,789		4,652

Commodity contracts - Gathering and Processing:
Natural gas price swaps
Prepayments and other assets		6,124		-		-		-
Derivative instruments-liabilities		-		16,459		-		-
NGL price swaps
Prepayments and other assets		-		-		1,996		-
Derivative instruments-liabilities		-		-		4,144		-
	$	6,124	$	16,459	$	85,865	$	24,346

Economic Hedges:
Commodity contracts - Gathering and Processing:
NGL processing spread swaps
Derivative instruments-liabilities	$	-	$	-	$	-	$	29,057
Other derivative instruments
Prepayments and other assets		-		133		-		-
Derivative instruments-liabilities		-		-		50		-

Commodity contracts - Distribution:
Natural gas price swaps
Derivative instruments-liabilities		-		234		34,468		34,968
Deferred credits		3		105		5,643		2,806
	$	3	$	472	$	40,161	$	66,831

Total	$	6,127	$	16,931	$	126,026	$	91,177

_____________

(1)

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 Sheet on a net basis and disclosed herein on a gross basis.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the location and amount of derivative instrument gains and losses reported in the Company’s consolidated financial statements for the periods presented:

	Years Ended December 31,
	2011			2010			2009

	(In thousands)
Cash Flow Hedges: (1)
Interest rate contracts:
Change in fair value - increase in Accumulated other comprehensive
loss , excluding tax expense effect of $27,589, $5,237 and $3,051, respectively	$	74,059		$	13,028		$	7,589
Reclassification of unrealized loss from Accumulated other
comprehensive loss - increase of Interest expense , excluding tax
expense effect of $(9,012), $(9,019) and $(8,222), respectively		(22,455	)		(22,483	)		(20,572	)
Commodity contracts - Gathering and Processing:
Change in fair value - decrease in Accumulated other comprehensive
loss , excluding tax expense effect of $(2,598), $(14,093) and $(3,773),
respectively		(7,208	)		(39,105	)		(10,469	)
Reclassification of unrealized gain from Accumulated other comprehensive
loss - increase of Operating revenues , excluding tax expense effect of $8,536,
$6,787 and $16,231, respectively		23,685			18,833			45,035

Economic Hedges:
Commodity contracts - Gathering and Processing:
Change in fair value of strategic hedges - (increase)/decrease in Operating revenues (2)		29,855			31,154			88,799
Change in fair value of other hedges - (increase)/decrease in Operating revenues		(96	)		283			(12	)
Commodity contracts - Distribution:
Change in fair value - increase/(decrease) in Deferred gas purchases		2,673			(6,166	)		(49,083	)

_________________

(1)	See Note 7 – Comprehensive Income (Loss) for additional related information.

(2)

Includes $29.1 million, $34.5 million and $59.7 million of the cash settlement impact for previously recognized unrealized losses in the years ended December 31, 2011 and 2010 and unrealized gains in the year ended December 31, 2009, respectively. Additionally, includes nil, $18.6 million and $44.9 million of unrealized mark-to-market losses recorded in the years ended December 31, 2011, 2010 and 2009, respectively.

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, 2011 was $22.9 million.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

12. Fair Value Measurement

The following tables set forth the Company’s assets and liabilities that are measured at fair value on a recurring basis at the dates indicated.

	Fair Value			Fair Value Measurements at December 31, 2011
	as of			Using Fair Value Hierarchy
	December 31, 2011			Level 1			Level 2			Level 3

	(In thousands)
Assets:
Commodity derivatives		$	4,128		$	-		$	4,128		$	-
Long-term investments			962			962			-			-
Total		$	5,090		$	962		$	4,128		$	-

Liabilities:
Commodity derivatives		$	44,302		$	-		$	44,302		$	-
Interest-rate swap derivatives			79,725			-			79,725			-
Total		$	124,027		$	-		$	124,027		$	-



	Fair Value			Fair Value Measurements at December 31, 2010
	as of			Using Fair Value Hierarchy
	December 31, 2010			Level 1			Level 2			Level 3

	(In thousands)
Assets:
Commodity derivatives		$	133		$	-		$	133		$	-
Long-term investments			937			937			-			-
Total		$	1,070		$	937		$	133		$	-

Liabilities:
Commodity derivatives		$	50,033		$	-		$	50,033		$	-
Interest-rate swap derivatives			24,346			-			24,346			-
Total		$	74,379		$	-		$	74,379		$	-

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 primarily include natural gas and NGL 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, 2011, 2010 or 2009.

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.

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13. Property, Plant and Equipment

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

			December 31,
	Lives in Years (1)		2011 (2)		2010 (2)

			(In thousands)
Regulated Operations:
Distribution plant		9-60	$	1,042,857	$	1,001,032
Gathering and processing plant		26		166,990		183,548
Transmission plant		5-46		2,321,009		2,239,762
General - LNG		5-40		1,118,791		1,117,418
Underground storage plant		5-46		321,920		314,744
General plant and other		3-50		304,385		283,737
Construction work in progress				48,268		52,800
				5,324,220		5,193,041
Less accumulated depreciation and amortization				1,219,017		1,074,161
				4,105,203		4,118,880
Non-regulated Operations:
Distribution plant		5-40		60,466		59,749
Gathering and processing plant		1-50		1,839,571		1,740,725
General plant and other		3-29		19,758		17,274
Construction work in progress				55,594		67,464
				1,975,389		1,885,212
Less accumulated depreciation and amortization				354,256		299,633
				1,621,133		1,585,579
Net property, plant and equipment			$	5,726,336	$	5,704,459

_________________

(1)	The composite weighted-average depreciation rates for the years ended December 31, 2011, 2010 and 2009 were 3.4 percent, 3.5 percent and 3.5 percent, respectively.

(2)	Includes capitalized computerized software cost totaling:

Unamortized computer software cost	$	140,397	$	131,182
Less accumulated amortization		89,258		79,637
Net capitalized computer software costs	$	51,139	$	51,545

Amortization expense of capitalized computer software costs for the years ended December 31, 2011, 2010 and 2009 was $10.7 million, $11.4 million and $13.1 million, respectively. The estimated amortization expense of capitalized computer software costs for the next five years ending December 31 are as follows: 2012 -- $9.7 million; 2013 -- $8.4 million; 2014 -- $7.7 million; 2015 -- $6.6 million; and 2016 -- $4.9 million. Computer software costs are amortized between one and fifteen years.

14. 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

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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.

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	2009

Expected volatility	32.83% to 35.60%			32.79% to 34.98%	32.22% to 33.69%
Expected dividend yield		2.45	%	2.45% to 2.47%	2.37% to 2.45%
Risk-free interest rate	1.58% to 2.41%			1.78% to 2.40%	2.34% to 2.72%
Expected life	4.75 to 6 years			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
		Weighted-			Weighted-
	Shares	Average		Shares	Average
	Under	Exercise		Under	Exercise
	Option	Price		Option	Price

Outstanding December 31, 2008	2,311,111	$	20.61	312,109	$	13.70
Granted	752,433		20.72	-		-
Exercised	(14,889)		16.83	(263,090)		13.52
Forfeited	(34,435)		17.39	-		-
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, 2009	1,229,447	$	20.70	49,019	$	14.65
Exercisable December 31, 2010	1,814,539		19.83	39,159		14.65
Exercisable December 31, 2011	2,478,000		19.86	-		-

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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

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
				Weighted-Average
	SARs			Exercise Price

Outstanding December 31, 2008		1,200,552		$	18.02
Granted		417,647			21.64
Exercised		(50,174	)		12.55
Forfeited		(74,894	)		18.82
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, 2009		494,775		$	22.06
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.

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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 $108.9 million and $83.8 million, respectively.

As of December 31, 2011, there was $6.8 million of total unrecognized compensation cost related to non-vested stock options and SARs compensation arrangements granted under the stock option plans. That cost is expected to be recognized over a weighted-average contractual period of 1.56 years. The total fair value of options and SARs vested as of December 31, 2011 was $21.5 million. Compensation expense recognized related to stock options and SARs totaled $6.9 million ($4.4 million, net of tax), $6.3 million ($4 million, net of tax) and $5.4 million ($3.5 million, net of tax) for the years ended December 31, 2011, 2010 and 2009, respectively. Cash received from the exercise of stock options was $1.8 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 $2.4 million. The Company realized an additional tax benefit of approximately $487,000 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.

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.

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

	Number of
	Restricted Stock			Weighted-Average
	Equity Units			Grant Date
	Outstanding			Fair Value

Restricted shares at December 31, 2008		363,185		$	18.94
Granted		165,567			20.24
Released		(146,990	)		19.90
Forfeited		(2,788	)		18.98
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			Weighted-Average
	Restricted Stock Liability			Grant Date
	Units Outstanding			Fair Value

Restricted units at December 31, 2008		548,639		$	17.31
Granted		268,027			21.06
Released		(204,937	)		19.38
Forfeited		(48,079	)		16.87
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

As of December 31, 2011, there was $21.3 million of total unrecognized compensation cost related to non-expired, restricted stock equity units and restricted stock liability units compensation arrangements granted under the restricted stock plans. That cost is expected to be recognized over a weighted-average contractual period of 2.2 years. The total fair value of restricted stock equity and liability units that were released during the year ended December 31, 2011 was $12.9 million. Compensation expense recognized related to restricted stock equity and liability units totaled $13.8 million ($8.7 million, net of tax), $8.8 million ($5.5 million, net of tax) and $6.8 million ($4.3 million, net of tax) for the years ended December 31, 2011, 2010 and 2009, respectively.

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The Company settled the restricted stock liability units released in 2011, 2010 and 2009 with cash payments of $10 million, $5.8 million and $4.4 million, respectively.

15. Commitments and Contingencies

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 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 $10.9 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 Sheet.

Environmental Remediation Liabilities

The table below reflects the amount of accrued liabilities recorded in the Consolidated Balance Sheet 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.

	December 31,
	2011			2010

	(In thousands)

Current		$	9,353		$	10,648
Noncurrent			11,635			11,920
Total environmental liabilities		$	20,988		$	22,568

During the years ended December 31, 2011, 2010 and 2009, the Company had $3.2 million, $4.5 million and $12 million of expenditures related to environmental cleanup programs, respectively.

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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.

East End Project. The East End Project involved the installation of a total of approximately 31 miles of pipeline in and around Tuscola, Illinois, Montezuma, Indiana and Zionsville, Indiana. Construction began in 2007 and was completed in the second quarter of 2008. PEPL sought recovery of each contractor’s share of approximately $50 million of cost overruns from the construction contractor, an inspection contractor and the construction management contractor for improper welding, inspection and construction management of the East End Project. Certain of the contractors filed counterclaims against PEPL for alleged underpayments of approximately $18 million. PEPL settled with three defendants prior to trial in Harris County, Texas. Trial began on May 16, 2011 and after the fourth week of trial a settlement was reached with the last defendant, Acuren. The various settlements resulted in the Company receiving a total of approximately $16 million and $9 million for reimbursement of previously incurred legal expenses associated with the proceeding and project cost overruns, respectively.

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 $18.5 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 current Vice Chairman, President and COO, 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 legal fees charged that were passed through the recovery mechanism and whether they would qualify for a lesser, 50 percent, level of recovery. The Company has filed its answer. The hearing officer has deferred hearing the Company’s motion to dismiss until the end of the proceedings. The AG’s motion to be reimbursed costs by the Company of up to $150,000 was granted. The Company believes it has complied with all applicable requirements of the MDPU 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.

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

Since the first quarter of 2010, 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 ( COs ) and proposed penalties for alleged violations at Jal #4 in the amount of $518,720 and at Jal #3 in the amount of $5,507,583. Hearings on the COs are scheduled for late April 2012. SUGS has meritorious defenses to the NMED claims and can offer significant mitigating factors to the claimed violations, including the installation of approximately $50 million of emission control equipment in the last nine years at these facilities. 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

On June 21, 2011, a putative class action lawsuit captioned Jaroslawicz v. Southern Union Company, et al. , Cause No. 2011-37091, was filed in the 333 rd Judicial District Court of Harris County, Texas. The petition named as defendants the members of the Southern Union Board, as well as Southern Union and ETE. The plaintiff alleged that the defendants breached their fiduciary duties to Southern Union’s stockholders or aided and abetted breaches of fiduciary duties in connection with the Merger. The petition alleged that the Merger involves an unfair price and an inadequate sales process and that defendants entered into the transaction to benefit themselves personally. The petition sought injunctive relief, including an injunction of the Merger, attorneys’ and other fees and costs, indemnification and other relief.

Also on June 21, 2011, another putative class action lawsuit captioned Magda v. Southern Union Company, et al. , Cause No. 2011-37134, was filed in the 11 th Judicial District Court of Harris County, Texas. The petition named as defendants the members of the Southern Union Board, Southern Union and ETE. The plaintiff alleged 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 those alleged breaches. The petition alleged 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, and that defendants have failed to disclose all material information related to the Merger to Southern Union stockholders. The petition sought injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief.

On June 28, 2011 and August 19, 2011, amended petitions were filed in the Magda and Jaroslawicz actions, respectively, naming the same defendants and alleging 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 those 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. The two Texas cases have been consolidated with the following style: in re: Southern Union Company ; Cause No. 2011-37091, in the 333 rd Judicial District Court of Harris County, Texas. 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 (described below).

On June 27, 2011, a putative class action lawsuit captioned Southeastern Pennsylvania Transportation Authority, et al. v. Southern Union Company, et al., C.A. No. 6615-CS, was filed in the Delaware Court of Chancery. The complaint named as defendants the members of the Southern Union Board, Southern Union and ETE. The plaintiffs alleged that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger, and further claimed that ETE aided and abetted those alleged breaches. The complaint alleged 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 the directors should deem a competing proposal made by The Williams Companies, Inc. ( Williams ) to be superior. The complaint sought compensatory damages, injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief.

On June 29 and 30, 2011, putative class action lawsuits captioned KBC Asset Management NV v. Southern Union Company, et al. , C.A. No. 6622-CS, and LBBW Asset Management Investment GmbH v. Southern Union Company, et al. , C.A. No. 6627-CS, respectively were filed in the Delaware Court of Chancery. The complaints named as defendants the members of the Southern Union Board, Southern Union, ETE and Merger Sub. The plaintiffs alleged that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger and that ETE aided and abetted those alleged breaches. The complaints alleged 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 the directors must give full consideration to the Williams proposal. The complaints sought compensatory damages, injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief.

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On July 6, 2011, a putative class action lawsuit captioned Memo v. Southern Union Company, et al ., C.A. No. 6639-CS, was filed in the Delaware Court of Chancery. The complaint named as defendants the members of the Southern Union Board, Southern Union ETE and Merger Sub. The plaintiffs alleged that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the amended Merger agreement and that Southern Union, ETE and Merger Sub aided and abetted those alleged breaches. The complaint alleged 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, and that the terms of the amended Merger agreement are preclusive. The complaint sought injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief.

On August 25, 2011, a consolidated amended complaint was filed in the Southeastern Pennsylvania Transportation Authority, KBC Asset Management NV, Memo and LBBW Asset Management Investment GmbH actions pending in the Delaware Court of Chancery naming the same defendants as the original complaints in those actions and alleging that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger, that ETE aided and abetted those alleged breaches of fiduciary duty, and that the provisions in Section 5.4 of the Second Amended Merger Agreement relating to Southern Union’s ability to accept a superior proposal is invalid under Delaware law. The amended complaint alleges 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 consolidated amended complaint seeks injunctive relief, including an injunction of the Merger and an award of attorneys’ and other fees and costs, in addition to other relief.

On November 9, 2011, the attorneys for the plaintiffs in the aforementioned Texas and Delaware actions stated that they did not intend to pursue their efforts to enjoin the Merger. Plaintiffs have indicated that they intend to pursue a claim for damages. A trial has not yet been scheduled in any of these matters.

On November 28, 2011, a derivative lawsuit captioned W. J. Garrett Trust v. Bill W. Byrne, et al., Cause No. 2011-71702, was filed in the 234th Judicial District Court of Harris County, Texas. The petition stated that it was filed on behalf of ETP. ETP was also named as a nominal defendant. The petition also named as defendants Energy Transfer Partners, GP, L.P. ( ETP GP ), Energy Transfer Partners, LLC ( ETP LLC ), ETE and the Boards of Directors of ETP, ETP GP, and ETP LLC (collectively, the ETE Defendants ). The petition also named Southern Union as a defendant. On January 6, 2012, the plaintiff in the Garrett Trust action filed an amended petition naming the same defendants. In these petitions, the plaintiff alleges that the ETE Defendants breached their fiduciary and contractual duties in connection with the Citrus Merger and ETP’s divestiture of its propane assets to Amerigas Partners LP (the Amerigas Transaction ). The petition alleges that the Citrus Merger, among other things, involves an unfair price and an unfair process and that the Directors of ETP, ETP GP, and ETP LLC failed to adequately evaluate the transaction. The petition also alleges that the Directors of ETP, ETP GP, and ETP LLC failed to, among other things, adequately evaluate the Amerigas Transaction. The amended complaint alleges that these defendants entered into both transactions primarily to assist in ETE’s consummation of its merger with Southern Union and thereby primarily to benefit themselves personally. The amended petition asserts claims for breaches of fiduciary duty, breaches of contractual duties, and acts of bad faith against each of the individual defendants, ETP GP, and ETP LLC. The amended complaint asserts claims against ETE and Southern Union for aiding and abetting the breaches of fiduciary duty, breaches of contractual duties, and acts of bad faith, as well as tortious interference with contract. The amended petition also asserts claims for declaratory judgment and conspiracy against all defendants. The lawsuit seeks, among other things, the following relief: (i) a declaration that the lawsuit is properly maintainable as a derivative action; (ii) a declaration that the Citrus Merger and Amerigas Transaction were unlawful and unenforceable because they involved breaches of fiduciary and contractual duties; (iii) a declaration that ETE and Southern Union aided and abetted the alleged breaches of fiduciary and contractual duties; (iv) a declaration that defendants conspired to, aided and abetted, and did breach fiduciary and contractual duties; (v) an order directing the individual defendants, ETP GP, and ETP LLC to exercise their fiduciary duties to obtain a transaction or transactions in the best interest of ETP’s unitholders; (vi) damages; and (vii) attorneys’ and other fees and costs.

The Company has not recorded an accrued liability and believes the allegations of all the foregoing actions related to the Merger with ETE lack merit and intends to contest them vigorously.

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Litigation Concerning the Citrus Merger

CrossCountry Energy, LLC ( CrossCountry ), the Company subsidiary that indirectly owns 50 percent of the capital stock of Citrus and is a Principal under the Citrus Capital Stock Agreement ( CSA ), filed a complaint in the Delaware Court of Chancery against El Paso Citrus Holdings, Inc., the owner of the other 50 percent of the capital stock of Citrus, and its parent El Paso Corporation (collectively, El Paso ), seeking a declaratory judgment that the Citrus Merger does not, as El Paso contends, trigger any provisions of the CSA which would require the Company to provide El Paso a right of first refusal concerning Citrus. The complaint was filed by CrossCountry following an exchange of letters between El Paso and the Company regarding the terms of the CSA. Following the filing of the declaratory judgment action, El Paso filed a third-party complaint against the Company, ETE, and ETP alleging, among other things, breach of the CSA. El Paso is not currently seeking to enjoin the closing of the Citrus Merger, but rather seeks a rescission of the Citrus Merger after it is completed or, alternatively, damages. Trial is currently set for April 2012. The Company has not recorded an accrued liability and believes the allegations by El Paso lack merit and intends to contest them vigorously.

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, 2011 and 2010, the Company recorded litigation and other claim-related accrued liabilities of $28.3 million and $26.9 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.

Other Commitments and Contingencies

Retirement of Debt Obligations. See Note 8 – Debt Obligations – Retirement of Debt Obligations for information related to the Company’s debt maturing in 2012 and Note 6 – Unconsolidated Investments – Contingent Matters Potentially Impacting Southern Union Through the Company’s Investment in Citrus – Retirement of Debt Obligations for information related to the Company’s commitment to potentially make additional sponsor loans to Citrus in the event repayment of certain Citrus debt obligations becomes necessary.

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 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 . Approximately $141 million, $134 million and $110 million of the capital replacement and retirement expenditures were incurred as of December 31, 2011, 2010 and 2009, respectively. The Company anticipates reimbursement from OIL for a significant portion of the damages in excess of its $10 million deductible; however, the recoverable amount is subject to pro rata reduction to the extent that the level of total accepted claims from all insureds exceeds the carrier’s $750 million aggregate exposure limit. OIL announced that it has reached the $750 million aggregate exposure limit and currently calculates its estimated payout amount at 70 percent or less based on estimated claim information it has received. OIL is currently making interim payouts at the rate of 50 percent of accepted claims. As of December 31, 2011, OIL has paid a total of $64.7 million for claims submitted to date by the Company with respect to Hurricane Ike. The final amount of any applicable pro rata reduction cannot be determined until OIL has received and assessed all claims.

Purchase Commitments. At December 31, 2011, the Company had purchase commitments for natural gas transportation services, storage services and certain quantities of natural gas at a combination of fixed, variable

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and market-based prices that have an aggregate value of approximately $608.6 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. The Company incurred capital expenditures of $13.8 million, $13.6 million and $14.4 million in 2011, 2010 and 2009, respectively, related to this program and estimates incurring approximately $94.8 million over the next 10 years, after which all service lines, representing about 33 percent of the annual safety program investment, will have been replaced.

Regulation and Rates. See Note 19 – Regulation and Rates 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.

Future Regulatory Compliance Commitments

SPCC Rules. In 2008 and 2009, the EPA adopted amendments to the SPCC rules with the stated intention of providing greater clarity, tailoring requirements and streamlining requirements. On November 10, 2011, the amendments to the SPCC rules went into effect. The Company modified its programs, assets and operations in its Transportation and Storage and Gathering and Processing segments and is finalizing implementation in accordance with the provisions found in the rule. Costs associated with these activities have not had a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.

Air Quality Control

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 ten tons per year of any one Hazardous Air Pollutant ( HAP ) or twenty-five tons per year of all HAPs) and engines less than 500 horsepower at Major Sources (sources that emit ten tons per year or more of any one HAP or twenty-five 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.

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 seventy-five parts per billion ( ppb ) with compliance anticipated in 2013 to 2015. In January 2010, the EPA proposed lowering the standard to sixty to seventy ppb in lieu of the seventy-five 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.

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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.

16. Stockholders’ Equity

Dividends. The table below presents the amount of cash dividends declared and paid in the respective periods.

Stockholder	Date	Amount		Amount
Record Date	Paid	Per Share		Paid
				(In thousands)

December 30, 2011	January 13, 2012	$	0.15	$	18,726
September 30, 2011	October 14, 2011		0.15		18,712
June 24, 2011	July 8, 2011		0.15		18,709
March 25, 2011	April 8, 2011		0.15		18,700

December 31, 2010	January 14, 2011	$	0.15	$	18,690
September 24, 2010	October 8, 2010		0.15		18,674
June 25, 2010	July 9, 2010		0.15		18,672
March 26, 2010	April 9, 2010		0.15		18,665

December 25, 2009	January 8, 2010	$	0.15	$	18,657
September 25, 2009	October 9, 2009		0.15		18,610
June 26, 2009	July 10, 2009		0.15		18,607
March 27, 2009	April 10, 2009		0.15		18,607

Under the terms of the indenture governing its Senior Notes, Southern Union may not declare or pay any cash or asset dividends on its common stock (other than dividends and distributions payable solely in shares of its common stock or in rights to acquire its common stock) or acquire or retire any shares of its common stock, unless no event of default exists and certain financial ratio requirements are satisfied. Currently, the Company is

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in compliance with these requirements and, therefore, the Senior Notes indenture does not prohibit the Company from paying cash dividends.

Stock Award Plans. The Third Amended 2003 Plan allows for awards in the form of stock options (either incentive stock options or non-qualified options), SARs, stock bonus awards, restricted stock, performance units or other equity-based rights. The persons eligible to receive awards under the Third Amended 2003 Plan include all of the employees, directors, officers and agents of, and other service providers to, the Company and its affiliates and subsidiaries. Under the Third Amended 2003 Plan: (i) no participant may receive in any calendar year awards covering more than 500,000 shares; (ii) the exercise price for a stock option may not be less than 100 percent of the fair market value of the common stock on the date of grant; and (iii) no award may be granted after September 28, 2013.

The Company maintained its 1992 Plan, under which options to purchase 8,491,540 shares of its common stock were authorized to be granted until July 1, 2002 to officers and key employees. Options granted under the 1992 Plan were exercisable for ten years from the date of grant or such lesser period as designated for particular options, and became exercisable after a specified period of time from the date of grant in cumulative annual installments. All awards granted under the Company’s 1992 plan were expired as of December 31, 2011.

For more information on stock-based awards, see Note 14 – Stock-Based Compensation .

17. Preferred Securities

On October 8, 2003, the Company issued 9,200,000 depositary shares, each representing a 1/10 th 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 $3.3 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 .

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. 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 – Corporate Structure for additional information associated with the Company’s reportable segments.

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 evaluates operational and financial segment performance based on several factors, of which the primary financial measure is EBIT, a non-GAAP measure. The Company defines EBIT as Net earnings available for common stockholders , adjusted for the following:

·	items that do not impact net earnings, such as extraordinary items, discontinued operations and the impact of changes in accounting principles;

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·	income taxes;

interest;

·	dividends on preferred stock; and

·	loss on extinguishment of preferred stock.

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 years ended December 31, 2011, 2010 and 2009.

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

	Years Ended December 31,
	2011			2010			2009

	(In thousands)
Operating revenues from external customers:
Transportation and Storage	$	803,650		$	769,450		$	749,161
Gathering and Processing		1,179,680			1,008,023			732,251
Distribution		666,650			698,513			692,904
Total segment operating revenues		2,649,980			2,475,986			2,174,316
Corporate and other activities		15,974			13,927			4,702
	$	2,665,954		$	2,489,913		$	2,179,018

Depreciation and amortization:
Transportation and Storage	$	128,011		$	123,009		$	113,648
Gathering and Processing		72,756			70,056			66,690
Distribution		33,445			32,544			31,269
Total segment depreciation and amortization		234,212			225,609			211,607
Corporate and other activities		3,478			3,028			2,220
	$	237,690		$	228,637		$	213,827

Earnings (loss) from unconsolidated investments:
Transportation and Storage	$	97,775		$	99,991		$	75,205
Gathering and Processing		(248	)		4,145			4,410
Corporate and other activities		1,408			1,279			1,175
	$	98,935		$	105,415		$	80,790

Other income (expense), net:
Transportation and Storage	$	603		$	(87	)	$	1,657
Gathering and Processing		138			362			(84	)
Distribution		41			(307	)		7,447
Total segment other income (expense), net		782			(32	)		9,020
Corporate and other activities		861			344			12,381
	$	1,643		$	312		$	21,401

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			Years Ended December 31,
			2011		2010		2009

			(In thousands)
Segment performance:
	Transportation and Storage EBIT		$	480,775	$	458,273	$	411,935
	Gathering and Processing EBIT			50,666		41,756		(40,470)
	Distribution EBIT			55,364		63,692		67,302
		Total segment EBIT		586,805		563,721		438,767
	Corporate and other activities			(8,369)		2,621		9,513
	Interest expense			219,232		216,665		196,800
	Federal and state income taxes			103,780		107,029		71,900
	Loss from discontinued operations			-		18,100		-
	Net earnings			255,424		224,548		179,580
	Preferred stock dividends			-		5,040		8,683
	Loss on extinguishment of preferred stock			-		3,295		-
		Net earnings available for common stockholders	$	255,424	$	216,213	$	170,897



			December 31,
			2011		2010

			(In thousands)
Total assets:
	Transportation and Storage		$	5,288,967	$	5,224,992
	Gathering and Processing			1,742,516		1,700,598
	Distribution			1,075,253		1,135,352
		Total segment assets		8,106,736		8,060,942
	Corporate and other activities			164,123		177,601
	Total assets		$	8,270,859	$	8,238,543


			Years Ended December 31,
			2011		2010		2009

			(In thousands)
Expenditures for long-lived assets:
	Transportation and Storage		$	101,852	$	145,674	$	247,097
	Gathering and Processing			113,864		95,577		70,221
	Distribution			50,780		41,484		46,090
		Total segment expenditures for long-lived assets		266,496		282,735		363,408
	Corporate and other activities			2,491		4,690		30,141
		Total expenditures for long-lived assets (1)	$	268,987	$	287,425	$	393,549

_______________________

(1)	Related cash impact includes the net reduction in capital accruals totaling $23 million, $9.5 million and $22 million for the years ended December 31, 2011, 2010 and 2009, respectively.

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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. The Distribution segment has no single customer, or group of customers under common control, that accounted for ten percent or more of the Company’s Distribution segment or consolidated operating revenues for the periods presented.

	Percent of Transportation and						Percent of Consolidated
	Storage Segment Revenues						Company Total Operating Revenues
	Years Ended December 31,						Years Ended December 31,
	2011		2010		2009		2011		2010		2009

BG LNG Services	30	%	29	%	22	%	9	%	9	%	8	%
ProLiance	13		13		13		4		4		4
Other top 10 customers	21		23		26		6		7		9
Remaining customers	36		35		39		10		11		13
Total percentage	100	%	100	%	100	%	29	%	31	%	34	%

	Percent of Gathering and						Percent of Consolidated
	Processing Segment Revenues						Company Total Operating Revenues
	Years Ended December 31,						Years Ended December 31,
	2011		2010		2009		2011		2010		2009

ConocoPhillips Company (1)	62	%	54	%	7	%	27	%	22	%	2	%
Lone Star NGL Product Services, LLC	12		12		12		5		5		4
Other top 10 customers	20		24		48		9		10		17
Remaining customers	6		10		33		3		5		12
Total percentage	100	%	100	%	100	%	44	%	42	%	35	%

_____________

(1)

For the five-year period ending 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 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. Trunkline LNG commenced construction of an enhancement at its LNG terminal in February 2007. The key components of the enhancement are an ambient air vaporizer system and NGL recovery units. On March 11, 2010, Trunkline LNG received approval from FERC to place the infrastructure enhancement construction project in service. Total construction costs were approximately $440 million plus capitalized interest, which includes additional costs incurred during final commissioning. The negotiated rate with the project’s customer, BG LNG Services, has been adjusted based on final capital costs pursuant to a contract-based formula. In addition, Trunkline LNG and BG LNG Services have extended the existing terminal and pipeline services agreements to coincide with the infrastructure enhancement construction project contract, which runs 20 years from the in-service date.

On August 31, 2009, Sea Robin filed with FERC to implement a rate surcharge to recover Hurricane Ike-related costs not otherwise recovered from insurance proceeds or from other third parties. The surcharge is primarily related to recovery of property, plant and equipment costs. On September 30, 2009, FERC approved the surcharge to be effective March 1, 2010, subject to refund and the outcome of hearings with FERC to explore issues set forth in certain customer protests, including the costs to be included and the applicability of the surcharge to discounted contracts. The Administrative Law Judge ( ALJ ) issued an initial decision on December 13, 2010, approving the surcharge for recovery from all shippers, including discounted and non-discounted

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shippers, over a recovery period of 21.4 years and including applicable carrying charges. The Company, as well as other parties, filed briefs for exception on certain aspects of the decision. On December 15, 2011, FERC issued an order changing the 21.4 year recovery period to a four-year recovery period and held that the commencement of carrying charges should begin the later of August 31, 2009 and the date the associated cost is incurred. FERC also determined that Sea Robin’s discount agreements with certain shippers permit it to recover the surcharge from those shippers.

In December 2011, Sea Robin reversed all outstanding reserves for refund associated with the surcharge filing, approximately $17.7 million of which had been reserved as of September 30, 2011. As of December 31, 2011, Sea Robin has incurred approximately $44 million of costs remaining to be recovered via the surcharge, including carrying charges and net of insurance and surcharge recoveries to date.

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 abandonment and sale 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 have filed interventions and protests of this filing. The Company is responding to information requests from FERC on this filing. The transfer is subject to approval by FERC.

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 to present and is estimated to take approximately one year to complete.

On December 15, 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule defines as HCAs. This rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002. The rule requires operators to identify HCAs along their pipelines and to complete baseline integrity assessments, comprised of in-line inspection (smart pigging), hydrostatic testing or direct assessment, by December 2012. Operators were required to rank the risk of their pipeline segments containing HCAs; assessments are generally conducted on the higher risk segments first. In addition, some system modifications will be necessary to accommodate the in-line inspections. As of December 31, 2011, Panhandle had completed approximately 93 percent of the baseline risk assessments required to be completed by December 2012. While identification and location of all the HCAs has been completed, it is not practicable to determine with certainty the total scope of required remediation activities prior to completion of the assessments and inspections. The required modifications and inspections are currently estimated to be in the range of approximately $20 million to $30 million per year through 2012.

Missouri Gas Energy . On July 13, 2011, a joint application was filed by Southern Union, Merger Sub and ETE requesting that the MPSC authorize Southern Union to take certain actions to allow ETE to acquire the equity interests of Southern Union. The parties filed an amended application on September 15, 2011. On February 16, 2012, the parties filed with the MPSC a Stipulation among Southern Union, ETE and the MPSC Staff. Pursuant to the Stipulation, the parties recommend that the MPSC issue an order finding that, subject to the conditions therein, the merger of Merger Sub with and into Southern Union is not detrimental to the public interest and authorizing the undertaking of the Merger and related transactions. The Office of Public Counsel has indicated that it does not oppose the Stipulation. Southern Union and ETE have requested that the MPSC consider the Stipulation expeditiously. For additional related information, see Note 3 – ETE Merger .

On June 10, 2011, Missouri Gas Energy filed an application with the MPSC requesting authority to defer the financial impact of the tornado that struck Joplin, Missouri on May 22, 2011, on the grounds that the tornado constituted a material, extraordinary and non-recurring event with respect to Missouri Gas Energy’s operations. On January 25, 2012, the MPSC issued its Report and Order in which it granted Missouri Gas Energy’s request to defer as a regulatory asset for consideration of recovery in a future rate proceeding the incremental costs occasioned by the tornado but denied Missouri Gas Energy’s request to defer as a regulatory asset for consideration of recovery in a future rate proceeding the lost fixed cost recovery occasioned by the tornado.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On April 2, 2009, Missouri Gas Energy made a filing with the MPSC seeking to implement an annual base rate increase of approximately $32.4 million. On February 10, 2010, the MPSC issued its Report and Order in this case, authorizing a revenue increase of $16.2 million and approving distribution rate structures for Missouri Gas Energy’s residential and small general service customers (which comprised approximately 99 percent of its total customers and approximately 91 percent of its net operating revenues at the time the rates went into effect) that eliminate the impact of weather and conservation for residential and small general service margin revenues and related earnings in Missouri. The new rates became effective February 28, 2010. Judicial review of the MPSC’s Report and Order is being sought by the Office of the Public Counsel, with respect to rate structure issues, and by Missouri Gas Energy, with respect to cost of capital issues. Those judicial review proceedings are expected to be completed in 2012, and the results of such proceedings are not expected to have a material adverse impact on the Company’s consolidated financial position, results of operations or cash flows.

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 percent of the amount by which its 2007 earnings fell below a return on equity of 7 percent. 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 approximately $1.7 million, representing 50 percent of the amount by which its 2008 earnings deficiency fell below a return on equity of 7 percent. 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 $4.1 million is the appropriate ESA amount for recovery related to calendar year 2007 and that such amount should be recovered over a 12-month period beginning November 1, 2011; and (ii) investigate New England Gas Company’s request for recovery of an ESA amount of $1.7 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. The 2008 ESA is awaiting further action by the MDPU.

On May 13, 2011, the independent auditor selected by the MDPU submitted the final audit report pertaining to 2007 cost of service information as ordered by the MDPU in connection with New England Gas Company’s 2008 base rate proceeding. On December 15, 2011, the MDPU issued its order accepting the audit report and closing the docket with no further action.

20. Leases

The Company leases certain facilities, equipment and office space under cancelable and non-cancelable operating leases. The minimum annual rentals under operating leases for the next five years ending December 31 are as follows: 2012—$15.2 million; 2013— $17.3 million; 2014—$15.6 million; 2015— $14.3 million; 2016—$13.4 million; and $59 million in total thereafter. Rental expense was $20.9 million, $20.1 million and $22.7 million for the years ended December 31, 2011, 2010 and 2009, respectively.

21. 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.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

The following table is a general description of ARO and associated long-lived assets at December 31, 2011.

	In Service
ARO Description	Date	Long-Lived Assets	Amount
			(In thousands)

Retire natural gas storage wells	Various	Natural gas storage wells		$	517
Retire offshore platforms and lines	Various	Offshore lines		$	3,180
Other	Various	Mainlines, compressors and gathering plants		$	4,941

As of December 31, 2011, 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.

	Years Ended December 31,
	2011			2010				2009

	(In thousands)

Beginning balance	$	61,280			$	61,667			$	51,641
Incurred		1,162				29,872				10,770
Revisions		(412	)			(11,395	)			(3,246	)
Settled		(16,836	)			(19,858	)			(1,557	)
Accretion expense		384				994				4,059
Ending balance	$	45,578			$	61,280			$	61,667

In 2010, additional AROs of $28.6 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 $11.4 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 $19.7 million. Such revisions and settlements were primarily associated with AROs of $8.3 million and $33.8 million recorded in 2009 and 2008, respectively, associated with damage caused by Hurricane Ike. During 2011, the Company recorded settlements of approximately $16.6 million, primarily associated with the abandonment of certain offshore properties damaged by Hurricane Ike. See Note 15 – Commitments and Contingencies – Other Commitments and Contingencies – 2008 Hurricane Damage for additional related information.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

22. Other Income and Expense Items

Other, net income for the year ended December 31, 2009 totaling $21.4 million consists primarily of $20.3 million of settlements with insurance companies related to certain environmental matters and collection of a $1.9 million settlement amount awarded to the Company related to the Southwest Gas litigation action filed by the Company in 2002 against former Arizona Corporation Commissioner James Irvin. These contingent gains were recognized in 2009 when the related settlement awards were received.

23. Discontinued Operations

In October 2004, New England Gas Company discovered that one of its facilities, formerly associated with discontinued operations 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 federal 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. The payment of the fine and community service amounts were stayed while the Company pursued an appeal .

On December 22, 2010, a United States Court of Appeals for the First Circuit ( First Circuit ) panel affirmed the conviction and the sentence. On February 17, 2011, the First Circuit denied the Company’s petition for en banc rehearing. With regard to the sentence, the First Circuit panel ruled that although the jury’s verdict was necessarily limited to a single day’s violation of RCRA (carrying a maximum fine of $50,000), the trial judge was nevertheless authorized for sentencing purposes independently to find the number of days the Company purportedly violated RCRA. In its decision, the Panel noted that the sentencing issue as applied to criminal fines was a novel one in the First Circuit and that, if the First Circuit panel's application of judicial precedents is incorrect, it would not be harmless error to the Company and the case must be remanded to the District Court for resentencing.

The Company thereafter filed a petition for a writ of certiorari review of the sentence by the United States Supreme Court ( Supreme Court ) in which the Company argued that the sentence, which went beyond the fine authorized by the jury’s verdict, violated the Company’s jury trial rights under the Fifth and Sixth Amendments, and was contrary to Supreme Court precedent. The Supreme Court granted the Company’s petition, and briefing of the Company’s appeal is now in process. The Supreme Court will hear oral argument on the Company’s appeal on March 19, 2012.

In light of the First Circuit's decisions, the Company recorded a charge to earnings of approximately $18.1 million in 2010 and reported such charge as Loss from discontinued operations in the Consolidated Statement of Operations. The earnings charge is nondeductible for federal and state income tax purposes .

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

24. Quarterly Operations (Unaudited)

The following table presents the operating results for each quarter of the year ended December 31, 2011.

	Quarters Ended
	March 31			June 30			September 30			December 31

	(In thousands, except per share amounts)

Operating revenues		$	746,822		$	631,607		$	617,211		$	670,314
Operating income			108,032			115,022			110,526			144,278
Net earnings			60,662			59,773			58,032			76,957
Net earnings available for common
stockholders			60,662			59,773			58,032			76,957
Basic earnings per share:		$	0.49		$	0.48		$	0.47		$	0.62
Dilutive earnings per share:		$	0.48		$	0.47		$	0.46		$	0.61


The following table presents the operating results for each quarter of the year ended December 31, 2010.

	Quarters Ended
	March 31			June 30			September 30			December 31

	(In thousands, except per share amounts)

Operating revenues		$	758,994		$	573,096		$	487,527		$	670,296
Operating income			119,278			131,744			76,407			133,186
Net earnings from continuing operations			56,460			74,889			37,331			73,968
Loss from discontinued operations			-			-			-			(18,100	)
Net earnings available for common
stockholders			54,289			69,424			36,632			55,868
Basic earnings per share:
Continuing operations		$	0.44		$	0.56		$	0.29		$	0.59
Available for common stockholders		$	0.43		$	0.55		$	0.29		$	0.45
Dilutive earnings per share:
Continuing operations		$	0.44		$	0.56		$	0.29		$	0.59
Available for common stockholders		$	0.43		$	0.55		$	0.29		$	0.45

The sum of EPS by quarter in the above tables may not equal the net earnings per common and common share equivalents for the applicable year due to variations in the weighted average common and common share equivalents outstanding used in computing such amounts.

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Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors

of Southern Union Company:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statement of operations, of stockholder's equity and comprehensive income and of cash flows present fairly, in all material respects, the financial position of Southern Union Company and its subsidiaries (the "Company") at December 31, 2011 and 2010 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding 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.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 24, 2012

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Citrus Corp. and Subsidiaries

Consolidated Financial Statements

Years ended December 31, 2011, 2010 and 2009

with Report of Independent Registered Public Accounting Firm

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CITRUS CORP. AND SUBSIDIARIES
CONSOLIDATED FINANCIAL STATEMENTS




Table of Contents

		Page

Report of Independent Registered Public Accounting Firm		F-64

Audited Consolidated Financial Statements
	Consolidated Balance Sheets	F-65
	Consolidated Statements of Income	F-66
	Consolidated Statements of Stockholders' Equity	F-67
	Consolidated Statements of Cash Flows	F-68
	Notes to Consolidated Financial Statements	F-69 - F-89

F-63

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Citrus Corp.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of comprehensive income, of stockholders' equity and of cash flows present fairly, in all material respects, the financial position of Citrus Corp. and subsidiaries (the "Company") at December 31, 2011 and December 31, 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. 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 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.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 24, 2012

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CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,
	2011			2010

	(In thousands)
ASSETS

Current assets
Cash and cash equivalents	$	22,746		$	39,018
Accounts receivable, billed and unbilled,
less allowances of $17 and $17, respectively		64,421			49,985
Income tax asset (Note 10)		84,889			-
Deferred tax asset (Note 10)		58,056			-
Materials and supplies		19,278			14,737
Other		11,140			3,368
Total current assets		260,530			107,108

Property, plant and equipment (Note 11)
Plant in service		7,510,640			4,854,917
Construction work in progress		48,447			2,217,174
		7,559,087			7,072,091
Less accumulated depreciation and amortization		1,799,172			1,667,360
Net property, plant and equipment		5,759,915			5,404,731

Other assets
Unamortized debt expense		16,249			19,070
Regulatory assets (Note 12)		32,729			21,725
Other		5,737			8,057
Total other assets		54,715			48,852

Total assets	$	6,075,160		$	5,560,691

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities
Current portion of long-term debt - notes	$	271,480		$	21,500
Current portion of long-term debt - revolvers		415,000			-
Accounts payable - trade and other		38,915			31,703
Accounts payable - affiliates		11,219			11,260
Accrued interest		45,410			45,637
Capital accruals		28,354			133,002
Provision for rate refunds (Note 4)		-			30,837
Other		37,127			43,013
Total current liabilities		847,505			316,952

Deferred credits
Accumulated deferred income taxes, net (Note 10)		1,152,727			895,279
Regulatory liabilities (Note 13)		12,822			9,363
Other (Note 13)		17,872			16,558
Total deferred credits		1,183,421			921,200

Long-term debt (Note 8)		2,052,413			2,591,150
Stockholder promissory notes (Note 8)		74,000			-
Commitments and contingencies (Note 14)

Stockholders' Equity
Common stock, $1 par value; 1,000 shares authorized, issued and outstanding		1			1
Additional paid-in capital		834,271			834,271
Accumulated other comprehensive loss		(4,428	)		(5,480	)
Retained earnings		1,087,977			902,597
Total stockholders' equity		1,917,821			1,731,389

Total liabilities and stockholders' equity	$	6,075,160		$	5,560,691

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

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CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

	Years Ended December 31,
	2011			2010			2009

				(In thousands)


Operating revenues
Transportation of natural gas (Note 4)	$	693,626		$	517,158		$	508,416

Total operating revenues		693,626			517,158			508,416

Operating expenses
Operations and maintenance		79,864			64,655			53,714
Operations and maintenance - affiliates (Note 5)		45,004			39,495			37,671
Depreciation and amortization		139,083			107,270			110,384
Taxes, other than on income		37,968			35,949			34,750

Total operating expenses		301,919			247,369			236,519


Operating income		391,707			269,789			271,897

Other income (expense)
Interest expense and related charges, net		(156,213	)		(116,417	)		(118,806	)
Other, net		60,744			139,920			55,021

Total other income (expense), net		(95,469	)		23,503			(63,785	)

Income before income taxes		296,238			293,292			208,112

Income taxes (Note 10)		110,858			112,365			78,429
Net income	$	185,380		$	180,927		$	129,683

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

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CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

	Years Ended December 31,
	2011			2010			2009

				(In thousands)

Common stock
Balance, beginning and end of period	$	1		$	1		$	1

Additional paid-in capital
Balance, beginning of period		834,271			634,271			634,271
Equity contributions (Note 5)		-			200,000			-
Balance, end of period		834,271			834,271			634,271

Accumulated other comprehensive loss
Balance, beginning of period		(5,480	)		(8,248	)		(5,246	)
Net change in other comprehensive income
(loss) (Note 7)		1,052			2,768			(3,002	)
Balance, end of period		(4,428	)		(5,480	)		(8,248	)

Retained earnings
Balance, beginning of period		902,597			721,670			591,987
Net income		185,380			180,927			129,683
Balance, end of period		1,087,977			902,597			721,670

Total stockholders' equity	$	1,917,821		$	1,731,389		$	1,347,694

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

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CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2011			2010			2009

				(In thousands)
Cash flows provided by (used in) operating activities
Net income	$	185,380		$	180,927		$	129,683
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		139,083			107,270			110,384
Deferred income taxes		196,738			60,602			36,216
Allowance for equity funds used during construction		(37,278	)		(86,153	)		(37,060	)
Allowance for equity funds used during construction - tax gross up		(23,054	)		(53,268	)		(22,990	)
Other		5,438			4,939			5,862
Changes in operating assets and liabilities:
Accounts receivable		(14,436	)		(8,983	)		(694	)
Accounts payable		7,171			(2,273	)		2,992
Accrued provision for rate refunds		(30,837	)		30,837			-
Accrued interest		(226	)		16,257			8,462
Accrued current taxes		(97,649	)		1,104			14,150
Other current assets and liabilities		(4,349	)		(4,238	)		(1,301	)
Other long-term assets and liabilities		(4,276	)		(6,512	)		3,938
Net cash flows provided by operating activities		321,705			240,509			249,642

Cash flows provided by (used in) investing activities
Capital expenditures		(575,255	)		(1,545,526	)		(455,064	)
Allowance for equity funds used during construction		37,278			86,153			37,060
Net cash flows used in investing activities		(537,977	)		(1,459,373	)		(418,004	)

Cash flows provided by (used in) financing activities
Issuance of long-term debt		-			850,000			600,000
Issuance costs of debt		-			(6,988	)		(5,964	)
Premium for redemption of debt		-			(6,519	)		-
Equity contribution		-			200,000			-
Repayment of long-term debt obligations		(21,500	)		(346,500	)		(51,500	)
Net change in revolving credit facilities		147,500			262,292			(79,375	)
Interest rate hedge - settlement		-			-			(9,234	)
Stockholder promissory notes
Borrowings		144,000			-			-
Payments		(70,000	)		-			-
Net cash flows provided by financing activities		200,000			952,285			453,927

Change in cash and cash equivalents		(16,272	)		(266,579	)		285,565

Cash and cash equivalents at beginning of period		39,018			305,597			20,032

Cash and cash equivalents at end of period	$	22,746		$	39,018		$	305,597


Cash paid for interest, net of amounts capitalized	$	168,363	$	145,473	$	118,569
Cash paid for income taxes, net of refunds	$	3,505	$	52,955	$	36,311

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

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CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Corporate Structure

Citrus Corp. ( Citrus ), a holding company formed in 1986, owns 100 percent of the membership interest in Florida Gas Transmission Company, LLC ( Florida Gas ), and 100 percent of the stock of Citrus Energy Services, Inc. ( CESI ) (collectively, the Company ). At December 31, 2011, the stock of Citrus was owned 50 percent by El Paso Citrus Holdings, Inc. ( EPCH ), a wholly-owned subsidiary of El Paso Corporation ( El Paso ), and 50 percent by CrossCountry Citrus, LLC ( CCC ), a wholly-owned subsidiary of CrossCountry Energy, LLC ( CrossCountry ) an indirect subsidiary of Southern Union Company ( Southern Union ).

Florida Gas, an open-access interstate natural gas pipeline extending from south Texas through the Gulf Coast region of the United States to south Florida, is engaged in the interstate transmission of natural gas and is subject to the jurisdiction of the Federal Energy Regulatory Commission ( FERC ). Florida Gas’ pipeline system primarily receives natural gas from producing basins along the Louisiana and Texas Gulf Coast, Mobile Bay and offshore Gulf of Mexico, and transports natural gas to the Florida market.

See Note 3 – Proposed Transfer of Southern Union’s Equity Interest in Citrus and Related Litigation for information related to Southern Union’s intent to merge with Energy Transfer Equity, L.P. ( ETE ).

The Company evaluated subsequent events through February 24, 2012, the date on which these financial statements were issued.

2. Summary of Significant Accounting Policies and Other Matters

Basis of Presentation . The Company’s consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) .

Principles of Consolidation. The consolidated financial statements include the accounts of Citrus and its wholly-owned subsidiaries. All significant intercompany accounts and transactions are eliminated in consolidation.

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 the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Regulatory Accounting . The Company is subject to regulation by certain state and federal authorities. The Company’s accounting policies conform to authoritative guidance that is in accordance with the accounting requirements and ratemaking practices of the 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 Statement of Income 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. Certain allowable regulatory deferrals of phase-in costs are prohibited under GAAP. As a consequence, certain phase-in costs of Florida Gas’ Phase III expansion are not deferred for GAAP-basis reporting but are deferred for future recovery for ratemaking purposes.

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 Sheet and included in the Consolidated Statement of Income for the period in which the discontinuance of regulatory accounting treatment occurs. See Note 12 – Regulatory Assets and Note 13 – Deferred Credits .

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CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Property, Plant and Equipment .

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

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

Depreciation. The Company amortized that portion of its investment in Florida Gas property which is in excess of historical cost (acquisition adjustment) on a straight-line basis at an annual composite rate of 1.6 percent based upon the estimated useful life of the pipeline system.

Florida Gas computed depreciation expense using the straight-line method at an annual composite rate of 2.21 percent, 2.57 percent and 2.78 percent for the years ended December 31, 2011, 2010 and 2009, respectively. The depreciation rates decreased effective April 1, 2010 based on the settlement of Florida Gas’ rate case; see Note 4 – Regulatory Matters for additional information.

Allowance for Funds Used During Construction (AFUDC) . The recognition of AFUDC is a utility accounting practice with calculations under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant. It represents the cost of capital invested in construction work-in-progress. AFUDC has been segregated into two component parts – borrowed funds and equity funds. The allowance for borrowed funds, which is included in the accompanying Statements of Income as a reduction in Interest expense, totaled $18.1 million, $50.5 million and $13.2 million for the years ended December 31, 2011, 2010 and 2009, respectively. The allowance for equity funds used during construction, including related amounts to gross up equity AFUDC to a before tax basis, totaled $60.3 million, $139.4 million and $60.1 million for the years ended December 31, 2011, 2010 and 2009, respectively. AFUDC equity funds are included in Other income in the accompanying Statements of Income.

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.

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

Accounts Receivable and Allowance for Doubtful Accounts . The Company manages trade credit risks to minimize exposure to uncollectible trade receivables. 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. The Company considers many factors including historical customer collection experience, general and specific economic trends and known specific issues related to individual customers, sectors, and transactions that might impact collectability. Increases in the allowance are recorded as a component of operating expenses. Reductions in the allowance are recorded when receivables are written off or subsequently collected. Past due receivable balances are written-off when the Company’s efforts have been unsuccessful in collecting the amount due. Unrecovered accounts receivable charged against the allowance for doubtful accounts were nil for each of the years ended December 31, 2011, 2010 and 2009, respectively.

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CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the relative contribution to the Company’s total operating revenue of each customer that comprised at least ten percent of its operating revenues for the periods presented. Revenues from individual third party and affiliate customers exceeding 10 percent of total revenues were approximately 59 percent, 53 percent and 54 percent of total revenue for the years ended December 31, 2011, 2010 and 2009, respectively.

	Years Ended December 31,
	2011		2010		2009
	(In thousands)

NextEra Energy, Inc. (1)	$	320,312	$	209,385	$	199,217
TECO Energy		88,343		79,228		73,430

The Company had the following transportation receivables from these customers at the dates indicated:

	December 31,
	2011		2010
	(In thousands)

NextEra Energy, Inc. (1)	$	29,060	$	16,881
TECO Energy		7,070		5,969

(1) Formerly referred to as Florida Power & Light Company

The Company has a concentration of customers in the electric and natural gas utility industries. These concentrations of customers may impact the Company's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. Credit losses incurred on receivables in these industries compare favorably to losses experienced in the Company's receivable portfolio as a whole. The Company also has a concentration of customers located in the southeastern United States, primarily within the state of Florida. Receivables are generally not collateralized. From time to time, specifically identified customers having perceived credit risk are required to provide prepayments, deposits, or other forms of security to the Company. Florida Gas sought additional assurances from customers due to credit concerns, and had customer deposits totaling $1.5 million and $1.5 million, and prepayments of $49,000 and $62,000 at December 31, 2011 and 2010, respectively. The Company's management believes that the portfolio of Florida Gas’ receivables, which includes regulated electric utilities, regulated local distribution companies, and municipalities, is of minimal credit risk.

Materials and Supplies . Materials and supplies are stated at the lower of weighted average cost or market value. Materials transferred out of warehouses are priced at weighted average cost. Materials and supplies include spare parts which are critical to the pipeline system operations.

Natural Gas Imbalances . Natural gas imbalances occur as a result of differences in volumes of natural gas received and delivered. These imbalances due to or from shippers and operators are valued at an appropriate index price. Natural gas imbalances are settled in cash or made up in-kind subject to the terms of Florida Gas’ tariff, and generally do not impact earnings.

Fuel Tracker . The fuel tracker is the cumulative balance owed to Florida Gas by its customers or owed by Florida Gas to its customers for gas used in the operation of its system, including costs incurred in the operation of electric compression and gas lost from the system or otherwise unaccounted for. The customers, pursuant to Florida Gas’ tariff and related contracts, provide fuel to Florida Gas based on specified percentages of the customers’ natural gas volumes delivered into the pipeline. The percentages are designed to match the actual fuel consumed in moving the natural gas through Florida Gas’ facilities, with any difference between the volumes provided versus fuel consumed reflected in the fuel tracker. A regulatory liability is recorded in the accompanying Consolidated Balance Sheets for net volumes of natural gas owed to customers collectively. Whenever fuel is due from customers from prior under recovery based on contractual and specific tariff provisions a regulatory asset is recorded. Natural gas owed from or to customers is valued at market and a surcharge is invoiced to recover or refund the previous under or over collections. Changes in the balances have no effect on the net income of Florida Gas.

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CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Twelve months ended December 31,
	2011		2010		2009
	(In thousands)
Operation and maintenance:
Transporation service charges (1)	$	8,449	$	8,164	$	7,092
Corporate service charges (2)		11,667		8,919		7,493
Operational and administrative service charges (3)		24,888		22,412		23,086

	December 31, 2011				December 31, 2010
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
Citrus:
Revolving credit agreement due 2012	$	181,000	$	179,828	$	178,500	$	174,632
Construction and term loan agreement due 2029		500,000		765,306		500,000		711,531
Florida Gas:
10.110% senior notes due 2013		28,000		30,447		42,000		47,174
9.190% senior notes due 2024		97,500		132,416		105,000		142,067
7.000% senior notes due 2012		250,000		265,388		250,000		277,094
7.900% senior notes due 2019		600,000		804,647		600,000		756,398
4.000% senior notes due 2015		350,000		379,341		350,000		366,779
5.450% senior notes due 2020		500,000		573,750		500,000		541,841
Revolving credit agreement due 2012		234,000		232,485		89,000		87,072
Total debt outstanding	$	2,740,500	$	3,363,608	$	2,614,500	$	3,104,588
Less current portion of long-term debt		686,500				21,500
Less unamortized debt discount and swap loss		1,587				1,850
Total long-term debt	$	2,052,413			$	2,591,150

Stockholder promissory notes	$	74,000			$	-

	One Percentage Point Increase		One Percentage Point Decrease
	(In thousands)
Effect on total service and interest cost	$	230	$	(220	)
Effect on accumulated postretirement benefit obligation		2,936		(2,719	)

	Fair Value as of December 31,
	2011		2010
	(In thousands)
Asset Category:
Cash and cash equivalents	$	-	$	-
Mutual fund (1)		15,628		13,335
Total	$	15,628	$	13,335

Years	Expected Benefits Before Effect of Medicare Part D		Payments Medicare Part D Subsidy Receipts		Net
			(In thousands)

2012	$	711	$	93	$	618
2013		849		104		745
2014		953		119		834
2015		1,071		132		939
2016		1,189		149		1,040
2017-2021		7,975		1,001		6,974

	Lives in		December 31,
	Years		2011		2010
			(In thousands)

Transmission		20-60	$	6,201,558	$	3,552,004
General		3-40		25,612		22,014
Intangibles (1)		6-10		31,004		28,433
Construction work-in-progress				48,447		2,217,174
Acquisition adjustment		62.5		1,252,466		1,252,466
				7,559,087		7,072,091
Less accumulated depreciation and amortization				1,799,172		1,667,360
Net property, plant and equipment			$	5,759,915	$	5,404,731

__________________________________________
(1) Includes capitalized computer software costs totaling:
Computer software cost			$	25,959	$	23,789
Less accumulated amortization				11,763		9,856
Net computer software costs			$	14,196	$	13,933