su10k_123110.htm

10-K 1 su10k_123110.htm SU FORM 10-K 12-31-10 su10k_123110.htm

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, 2010

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.)

5444 Westheimer Road	77056-5306
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, 2010 was $2,529,540,437 (based on the closing sales price of Common Stock on the New York Stock Exchange on June 30, 2010). 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 18, 2011 was 124,656,118.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s proxy statement for its annual meeting of stockholders that is scheduled to be held on May 4, 2011 are incorporated by reference into Part III.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

FORM 10-K

DECEMBER 31, 2010

Table of Contents

		Page
Glossary.	PART I	1
ITEM 1.	Business.	2
ITEM 1A.	Risk Factors.	18
ITEM 1B.	Unresolved Staff Comments.	31
ITEM 2.	Properties.	32
ITEM 3.	Legal Proceedings.	32
ITEM 4.	Reserved.	32
	PART II
ITEM 5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.	32
ITEM 6.	Selected Financial Data.	35
ITEM 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations.	36
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk.	62
ITEM 8.	Financial Statements and Supplementary Data.	65
ITEM 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.	65
ITEM 9A.	Controls and Procedures.	65
ITEM 9B.	Other Information.	66
	PART III
ITEM 10.	Directors, Executive Officers and Corporate Governance.	67
ITEM 11.	Executive Compensation.	67
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	67
ITEM 13.	Certain Relationships and Related Transactions, and Director Independence.	67
ITEM 14.	Principal Accounting Fees and Services.	67
	PART IV
ITEM 15.	Exhibits, Financial Statement Schedules.	68
Signatures.		71
Index to the Consolidated Financial Statements.		F-1

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

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

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

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

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

PART I

ITEM 1. Business.

OUR BUSINESS

Introduction

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.

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 17 – 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 88 percent of total segment revenues and 27 percent of consolidated revenues in 2010.

Florida Gas. Florida Gas is an open-access interstate pipeline system with a mainline capacity of 2.3 Bcf/d and approximately 5,000 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 60 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, 2010, 2009 and 2008, the Transportation and Storage segment’s operating revenues were $769.5 million, $749.2 million and $721.6 million, respectively. Earnings from unconsolidated investments related to Citrus were $99.8 million, $75 million and $74.9 million for the years ended December 31, 2010, 2009 and 2008, 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,
	2010		2009		2008

Panhandle:
PEPL transportation		563		676		702
Trunkline transportation		664		683		643
Sea Robin transportation		172		132		126
Trunkline LNG terminal usage		43		33		9

Florida Gas (1)		835		821		786

___________________________

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

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



	December 31, 2010

Panhandle:
Approximate Miles of Pipelines
PEPL		6,200
Trunkline		3,600
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)		32.3
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
PEPL		6.8
Trunkline		9.6
Sea Robin (1)		N/A
Weighted Average Remaining Life in Years of Firm Storage Contracts
PEPL		10.1
Trunkline		2.6

Florida Gas: (2)
Approximate Miles of Pipelines		5,000
Peak Day Delivery Capacity (Bcf/d)		2.3
Approximate Average Number of Transportation Customers		125
Weighted Average Remaining Life in Years of Firm Transportation Contracts		10.9

_______________________

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

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

Recent System Enhancements – Completed or Under Construction

LNG Terminal Enhancement. Trunkline LNG commenced construction of an enhancement at its LNG terminal in February 2007. The key components of the enhancement were 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. The negotiated rate with the project’s customer, BG LNG Services, will be 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.

Florida Gas Phase VIII Expansion. In November 2009, FERC approved Florida Gas’ certificate application to construct an expansion, which will increase its natural gas capacity into Florida by approximately 820 MMcf/d (Phase VIII Expansion). Florida Gas anticipates an in-service date in April 2011, at a currently estimated cost of approximately $2.48 billion, including capitalized equity and debt costs. Approximately $2.2 billion of capital costs have been recorded as of December 31, 2010. To date, Florida Gas has entered into firm transportation service agreements with shippers for 25-year terms accounting for approximately 74 percent of the available expansion capacity.

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
	For Year Ended			Weighted Average Life of Contracts
Company	December 31, 2010 (1)			at December 31, 2010

BG LNG Services		29	%	19.3 years (LNG, transportation)
ProLiance		13		10.9 years (transportation), 15.3 years (storage)
Other top 10 customers		23			N/A
Remaining customers		35			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, 2010			December 31, 2010

Florida Power & Light		38	%	13.0 Years
Tampa Electric/Peoples Gas		15		10.4 Years
Other top 10 customers		31			N/A
Remaining customers		16			N/A
Total percentage		100	%

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.

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	New rates effective April 1, 2010, subject to refund

________________________

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

(2)	Settlement provides for a rate moratorium through 2015.

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 5 – Unconsolidated Investments – Contingent Matters Potentially Impacting Southern Union Through the Company’s Investment in Citrus – Florida Gas Rate Filing and Note 18 – 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.

Gathering and Processing Segment

Services

SUGS’ operations consist of a network of natural gas and NGL pipelines, four 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. SUGS’ business is not generally seasonal in nature.

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 10 – 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, 2010, 2009 and 2008, SUGS’ gross margin (Operating revenues net of Cost of natural gas and other energy) was $193.3 million, $107.5 million and $304.1 million, respectively.

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

	December 31, 2010

Approximate Miles of Pipelines		5,500
Plant capacity (MMcf/d):
Cryogenic processing		415
Natural gas treating		585
Approximate Average Number of Customers		260

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, 2010 (1)			December 31, 2010

Conoco Phillips Company		54	%	Month-to-month (natural gas), 4 years (NGL)
Louis Dreyfus Energy Services, LP		12		3.8 years (2)
Other top 10 customers		24			N/A
Remaining customers		10			N/A
Total percentage		100	%

_____________________

(1)	Conoco Phillips Company accounted for 22 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, Louis Dreyfus Energy Services 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, 2010, comprised 13 percent, 68 percent and 19 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:

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 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 Phillips Company (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 10 – Derivative Instruments and Hedging Activities – Gathering and Processing Segment.

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. 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 and fractionation capacity;

·	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 the new rates, see Item 8. Financial Statements and Supplementary Data, Note 18 – 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, 2010

Approximate Miles of Pipelines
Mains		9,182
Service lines		5,928
Transmission lines		45

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,
	2010			2009			2008

Average number of customers:
Residential		484,014			485,136			485,971
Commercial		62,945			64,584			65,479
Industrial		94			95			122
		547,053			549,815			551,572
Transportation		1,733			1,698			1,579
Total customers		548,786			551,513			553,151

Natural gas sales (MMcf):
Residential		39,908			39,649			43,018
Commercial		16,412			16,249			17,977
Industrial		371			486			427
Natural gas sales billed		56,691			56,384			61,422
Net change in unbilled natural gas sales		(169	)		395			47
Total natural gas sales		56,522			56,779			61,469
Natural gas transported		27,218			26,212			28,214
Total natural gas sales and gas transported		83,740			82,991			89,683

Natural gas sales revenues (in thousands):
Residential	$	475,418		$	488,112		$	559,293
Commercial		184,327			183,593			223,141
Industrial		8,668			9,109			9,352
Natural gas revenues billed		668,413			680,814			791,786
Net change in unbilled natural gas sales revenues		4,021			(13,056	)		3,632
Total natural gas sales revenues		672,434			667,758			795,418
Natural gas transportation revenues		15,524			14,133			14,135
Other revenues		10,555			11,013			12,120
Total operating revenues	$	698,513		$	692,904		$	821,673

Weather:
Missouri Utility Operations:
Degree days (1)		5,033			4,985			5,499
Percent of 10-year measure (2)		97	%		96	%		106	%
Percent of 30-year measure (2)		97	%		96	%		106	%

Massachusetts Utility Operations:
Degree days (1)		5,288			5,633			5,348
Percent of 10-year measure (2)		86	%		92	%		83	%
Percent of 30-year measure (2)		87	%		91	%		88	%

______________________

(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.

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, 2010, 2009 and 2008.

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, 2010, 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-one 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 2011 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 18 – 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.

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	July 2008	MDPU rate order effective February 2, 2009

__________________

(1)	For more information related to these rate filings, see Item 8. Financial Statements and Supplementary Data, Note 18 – 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 14 – Commitments and Contingencies.

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, 2010, the Company had 2,437 employees, of whom 1,542 are paid on an hourly basis and 895 are paid on a salary basis. Unions represent 759 of the 1,542 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	213	May 28, 2012

Missouri Gas Energy:
	Gas Workers 781	212	April 30, 2014
	IBEW Local 53	90	April 30, 2014
	USW Local 11-267	27	April 30, 2014
	USW Local 12561, 14228	146	April 30, 2014

New England Gas Company:
	UWUA Local 431	71	May 4, 2013

As of December 31, 2010, the number of persons employed by each segment was as follows: Transportation and Storage segment – 1,184 persons; Gathering and Processing segment – 321 persons; Distribution segment – 811 persons; All Other subsidiary operations – 12 persons. In addition, the corporate employees of Southern Union totaled 109 persons.

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, 2010, Florida Gas had 326 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, 2010, 2009 or 2008.

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 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, 2010, consolidated debt on the Consolidated Balance Sheet totaled $3.52 billion outstanding, compared to total capitalization (long and short-term debt plus stockholders' equity) of $6.05 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.

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

As of December 31, 2010, 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. If the Company’s 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 debt obligations could increase annually up to approximately $8.1 million;

·	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.

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.

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.

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.

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 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.

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 recent moratorium 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, which was scheduled to expire on November 30, 2010, was implemented to permit the DOI to review the safety protocols and procedures used by offshore drilling companies, which review will enable the DOI to recommend enhanced safety and training needs for offshore drilling companies. The moratorium was lifted in October 2010. Additionally, the United States Bureau of Ocean Energy Management, Regulation and Enforcement (formerly the United States Mineral Management Service) has been fundamentally restructured by the DOI with the intent of providing enhanced oversight of onshore and offshore drilling operations for regulatory compliance enforcement, energy development and revenue collection. Certain enhanced regulatory mandates have been enacted with additional regulatory mandates expected. The new regulatory requirements will increase the cost of offshore drilling and production operations. The increased regulations and cost of drilling operations could result in decreased drilling activity in the areas serviced by the Company. Furthermore, the imposed moratorium did result in some offshore drilling companies relocating their offshore drilling operations for currently indeterminable periods of time to regions outside of the United States. Business decisions to not drill in the areas serviced by the Company resulting from the increased regulations and costs could result in a reduction in the future development and production of natural gas reserves in the vicinity of the Company’s facilities, which could adversely affect the Company’s business, financial condition, results of operations and cash flows.

The 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.

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. Such 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.

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 42 percent of its 2010 revenue. Florida Gas’ top two customers accounted for 53 percent of its 2010 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.

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 10 Derivative Instruments and Hedging Activities – Gathering and Processing Segment.

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, 2010 accounted for approximately 32 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.

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 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, 2010, Conoco accounted for approximately 22 percent and 54 percent of the Company’s and SUGS’ operating revenues, respectively.

RISKS THAT RELATE TO THE COMPANY’S DISTRIBUTION BUSINESS

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

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

The distribution business is influenced by fluctuations in costs, including operating costs such as insurance, postretirement and other benefit costs, wages, changes in the provision for the allowance for doubtful accounts associated with volatile natural gas costs and other operating costs. The profitability of regulated operations depends on the business’ ability to recover costs related to providing services to its customers. To the extent that such operating costs increase in an amount greater than that for which 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, 2010, the Company’s regulatory assets recorded in its Consolidated Balance Sheet totaled $66.2 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.

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 available to the Company;

·	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 commodity 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 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 and authorized rates of recovery of costs (including pipeline relocation costs);

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

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

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

ITEM 1B. Unresolved Staff Comments.

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 two electric power plants that share a site in Archbald, Pennsylvania. PEI Power Corporation wholly owns one plant, a 35 megawatt electric cogeneration facility fueled by a combination of natural gas and methane, and owns 49.9 percent of the second plant, a 45 megawatt natural gas-fired electric generation facility, through a joint venture with Cayuga Energy.

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 18 – Regulation and Rates and Note 14 – Commitments and Contingencies. Also see Item 1A. Risk Factors – Cautionary Factors That May Affect Future Results.

ITEM 4. Reserved.

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, 2009 are set forth below.

	Dollars per share
	High		Low		Dividends

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

December 31, 2009	$	23.17	$	19.24	$	0.15
September 30, 2009		21.46		16.72		0.15
June 30, 2009		18.83		14.69		0.15
March 31, 2009		16.22		11.59		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 15 – Stockholders’ Equity and Note 7 – Debt Obligations.

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, 2005, in Southern Union common stock, the S&P 500 Index and the Bloomberg U.S. Pipeline Index. Each case assumes the reinvestment of dividends.

	2005	2006	2007	2008	2009	2010
Southern Union	100	120	128	59	105	115
S&P 500 Index	100	116	122	77	97	112
Bloomberg U.S. Pipeline Index	100	116	137	84	119	146

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 Cos, Inc.

HOLDERS

As of February 18, 2011, there were 5,654 holders of record of Southern Union’s common stock, and 124,656,118 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 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.

The following table sets forth information regarding the Company’s equity compensation plans approved by security holders as of December 31, 2010.

	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	3,974,205 (1), (2)	$	21.13	3,689,620

______________

(1) Excludes 341,213 shares of restricted stock that were outstanding at December 31, 2010.

(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, 2010.

For additional information related to the Company’s equity compensation plans, see Item 8. Financial Statements and Supplementary Data, Note 13 – 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, 2010 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, 2010		3,599		$	24.76
Month Ended November 30, 2010		1,298			24.78
Month Ended December 31, 2010		57,402			24.28
Total		62,299		$	24.32

______________

(1) The total number of shares purchased includes: (i) the surrender to the Company of 54,187 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) 8,112 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).

ITEM 6. SELECTED FINANCIAL DATA.

	Years Ended December 31,
	2010			2009		2008		2007		2006 (1)(2)(3)

	(In thousands, except per share amounts)

Total operating revenues	$	2,489,913		$	2,179,018	$	3,070,154	$	2,616,665	$	2,340,144
Earnings from unconsolidated
investments		105,415			80,790		75,030		100,914		141,370
Net earnings (loss):
Continuing operations		242,648			179,580		295,151		228,711		199,718
Discontinued operations (4)		(18,100	)		-		-		-		(152,952	)
Available for common stockholders		216,213			170,897		279,412		211,346		46,766
Net earnings (loss) per diluted
common share: (5)
Continuing operations		1.87			1.37		2.26		1.75		1.70
Discontinued operations		(0.14	)		-		-		-		(1.30	)
Available for common stockholders		1.73			1.37		2.26		1.75		0.40
Total assets		8,238,543			8,075,074		7,997,907		7,397,913		6,782,790
Stockholders’ equity		2,526,982			2,469,946		2,367,952		2,205,806		2,050,408
Current portion of long-term debt and
capital lease obligation		1,083			140,500		60,623		434,680		461,011
Long-term debt and capital lease
obligation, excluding current portion		3,520,906			3,421,236		3,257,434		2,960,326		2,689,656
Cash dividends declared on common
stock		74,701			74,481		74,384		53,968		46,289

___________________

(1)

Includes the impact of the March 1, 2006 acquisition of Sid Richardson Energy Services, Ltd. and related entities, and the August 24, 2006 dispositions of PG Energy and the Rhode Island operations of New England Gas Company. See note 4 below for additional related information regarding the asset dispositions.

(2)	The Company’s investment in CCE Holdings was accounted for using the equity method until it became a wholly-owned subsidiary on December 1, 2006.

(3)	Net earnings from continuing operations are net of dividends on preferred stock of $17.4 million for the year ended December 31, 2006.

(4)

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 14 – Commitments and Contingencies – Litigation – Mercury Release for additional information related to the 2010 charge for discontinued operations.

(5)	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.

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 Southern Union’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 to anticipate 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 executive management for use in determining the performance of the businesses and in allocating resources to the businesses as well as based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment.

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 shareholders 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 18 – 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.

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,
	2010		2009			2008

	(In thousands)
EBIT:
Transportation and storage segment	$	458,273	$	411,935		$	404,834
Gathering and processing segment		41,756		(40,470	)		145,363
Distribution segment		63,692		67,302			61,418
Corporate and other activities		2,621		9,513			(4,281	)
Total EBIT		566,342		448,280			607,334
Interest expense		216,665		196,800			207,408
Earnings from continuing operations before income taxes		349,677		251,480			399,926
Federal and state income taxes		107,029		71,900			104,775
Earnings from continuing operations		242,648		179,580			295,151
Loss from discontinued operations		18,100		-			-
Preferred stock dividends		5,040		8,683			12,212
Loss on extinguishment of preferred stock		3,295		-			3,527
Net earnings available for common stockholders	$	216,213	$	170,897		$	279,412

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 U.S. Court of Appeals for the First Circuit (First Circuit) affirming the Company’s conviction of an RCRA violation in a mercury contamination 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 the 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.

Year ended December 31, 2009 versus the year ended December 31, 2008. The Company’s $108.5 million decrease in Net earnings available for common stockholders was primarily due to the lower EBIT contribution of $185.8 million from the Gathering and Processing segment resulting from lower operating revenues of $687.1 million, excluding hedging gains and losses, attributable to lower market-driven realized average natural gas and NGL prices and the impact of $101.7 million of lower revenues from hedging activities, partially offset by lower market-driven natural gas and NGL purchase costs of $592.2 million in 2009 versus 2008.

These reductions in earnings were partially offset by:

Higher EBIT contribution of $7.1 million from the Transportation and Storage segment primarily due to higher operating revenues of $27.5 million largely attributable to higher interruptible parking revenues of $17.1 million due to customer demand, market conditions and the availability of system capacity and higher transportation reservation revenues of $13.3 million primarily due to higher average rates realized on PEPL, partially offset by higher net operating, maintenance and general expenses of $7.8 million and higher depreciation and amortization expense of $9.8 million primarily resulting from net increases in property, plant and equipment placed in service;

·	Higher EBIT contribution of $5.9 million from the Distribution segment primarily due to the impact of $8.1 million of income in 2009 resulting from settlements with insurance companies related to certain environmental matters;

·	Higher EBIT contribution of $13.8 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 and higher legal fees of $5.9 million in the 2008 period;

Lower interest expense of $10.6 million primarily attributable to lower interest expense of $10.1 million due to lower LIBOR interest rates associated with the Company’s variable rate debt and the impact of a $6.8 million increase in interest costs capitalized attributable to higher average capital project balances outstanding in 2009 compared to 2008, partially offset by higher net interest expense of $7.1 million attributable to higher net debt balances outstanding on the Company’s fixed-rate debt obligations;

·	Impact of a $3.5 million loss recorded in the 2008 period related to the Company’s purchase of 459,999 shares of its Preferred Stock and the reduction in related dividends of $3.5 million; and

·	Lower federal and state income tax expense of $32.9 million primarily due to lower pre-tax earnings of $148.4 million, partially offset by the impact of a 29 percent EITR in the 2009 period versus a 26 percent EITR in 2008.

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 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 Segment and Item 1. Business – Business Segments – Transportation and Storage Segment, respectively.

The Company’s regulated transportation and storage businesses periodically 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 these 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.

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,
	2010			2009		2008
	(In thousands)

Operating revenues	$	769,450		$	749,161	$	721,640

Operating, maintenance and general		252,007			265,901		258,062
Depreciation and amortization		123,009			113,648		103,807
Taxes other than on income and revenues		36,065			34,539		32,061
Total operating income		358,369			335,073		327,710
Earnings from unconsolidated investments		99,991			75,205		75,173
Other income, net		(87	)		1,657		1,951
EBIT	$	458,273		$	411,935	$	404,834

Operating information (TBtu):
Panhandle natural gas volumes transported (1)		1,399			1,491		1,471
Florida Gas natural gas volumes transported (2)		835			821		786

_____________

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

(2)	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, 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.

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. Due to the increasing levels of capitalized project costs, AFUDC is expected to continue to trend higher until completion of the 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 5 – 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 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.

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. Depreciation and amortization expense is expected to continue to increase primarily due to ongoing capital additions.

See Item 8. Financial Statements and Supplementary Data, Note 14 – 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.

Year ended December 31, 2009 versus the year ended December 31, 2008. The $7.1 million EBIT improvement in the year ended December 31, 2009 versus the same period in 2008 was primarily due to a higher EBIT contribution from Panhandle.

Panhandle’s $7.1 million EBIT increase was primarily due to:

·	Higher operating revenues of $27.5 million primarily as the result of:

o	Higher interruptible parking revenues of $17.1 million primarily resulting from favorable market conditions resulting in higher rates in 2009 and the availability of system capacity;

Higher transportation reservation revenues of $13.3 million primarily due to higher average rates realized on PEPL and contributions from various expansion projects primarily consisting of the Trunkline Field Zone Expansion and PEPL East End Enhancement projects, partially offset by lower average rates realized on Trunkline and $1.2 million of additional revenues in the 2008 period attributable to the extra day in the 2008 leap year;

o	A $5.1 million increase in LNG terminalling revenue primarily due to higher reservation revenues attributable to a one-time annual rate increase associated with certain capacity effective January 1, 2009; and

o	Lower transportation usage revenues of $7.4 million primarily due to reduced volumes flowing on Sea Robin after Hurricane Ike.

The increased revenues were offset by:

·	Higher operating, maintenance and general expenses of $7.8 million in 2009 versus 2008 primarily attributable to:

o	A $5.6 million increase in benefits primarily due to higher medical costs;

o	A $5.5 million increase in third-party transportation and storage expense primarily due to additional capacity contracted;

o	A $4.8 million increase in fuel tracker costs primarily due to a net over-recovery in 2008 versus a net under-recovery in 2009; and

o	A $6.4 million decrease 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;

Increased depreciation and amortization expense of $9.8 million in 2009 versus 2008 due to a $136 million increase in property, plant and equipment placed in service after December 31, 2008. Depreciation and amortization expense is expected to continue to increase primarily due to significant capital additions, including capital spending associated with the LNG terminal infrastructure enhancement construction project; and

Higher taxes, other than on income and revenues, of $2.5 million primarily due to higher property tax assessments resulting from property additions and higher operating income. Property tax expense is expected to continue to increase primarily due to significant property additions, which has been partially mitigated by certain temporary property tax abatements.

Equity earnings, primarily attributable to the Company’s unconsolidated investment in Citrus, were higher by $32,000 in 2009 versus 2008 primarily due to the following items, adjusted where applicable to reflect the Company’s proportional equity share:

·	Higher other income of $23.5 million largely driven by higher equity AFUDC resulting from Florida Gas’ Phase VIII Expansion project. Due to the increasing levels of capitalized project costs, AFUDC is expected to continue to trend higher until completion of the Phase VIII Expansion project;

·	Higher operating revenues of $1.8 million primarily due to higher reservation revenues of $2.4 million resulting from increased capacity from prior expansions, partially offset by the impact of additional revenues in the 2008 period attributable to the extra day in the 2008 leap year;

Higher debt interest cost of $19 million primarily due to interest on a $500 million construction and term loan agreement funded in October 2008 and on the $600 million 7.90% Senior Notes issued in May 2009, partially offset by higher debt AFUDC, lower average outstanding revolver debt balances and lower LIBOR interest rates;

·	Higher income tax of $2.5 million primarily due to higher pretax earnings;

·	Higher depreciation expense of $2.3 million primarily due to increase in property, plant and equipment placed in service after December 31, 2008; and

·	Higher operating expenses of $1 million primarily due to higher overall costs experienced in 2009 applicable to employee labor, outside service costs and other operating costs.

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 services it provides, SUGS' business is not generally seasonal in nature. However, SUGS operations and the operations of its natural gas producers can be adversely impacted by severe weather.

The majority of SUGS’ gross margin is derived from the sale of NGL and natural gas equity volumes and fee based services. The prices of NGL and natural gas are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of factors beyond the Company’s control. The Company monitors these risks and manages the associated commodity price risk using both economic and accounting hedge derivative instruments. For additional information related to the Company’s commodity price risk management, see Item 8. Financial Statements and Supplementary Data, Note 10 – 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.

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,
	2010			2009			2008
	(In thousands)

Operating revenues, excluding impact of
commodity derivative instruments	$	1,020,758		$	776,835		$	1,463,966
Realized and unrealized commodity derivatives		(12,735	)		(44,584	)		57,075
Operating revenues		1,008,023			732,251			1,521,041
Cost of natural gas and other energy (1)		(814,712	)		(624,772	)		(1,216,953	)
Gross margin (2)		193,311			107,479			304,088
Operating, maintenance and general		80,272			80,243			90,657
Depreciation and amortization		70,056			66,690			62,716
Taxes other than on income and revenues		5,734			5,342			4,466
Total operating income		37,249			(44,796	)		146,249
Earnings (loss) from unconsolidated investments		4,145			4,410			(990	)
Other income, net		362			(84	)		104
EBIT	$	41,756		$	(40,470	)	$	145,363

Operating Information:
Volumes
Avg natural gas processed (MMBtu/d)		430,683			401,715			410,511
Avg NGL produced (gallons/d)		1,463,827			1,325,052			1,321,325
Avg natural gas wellhead volumes (MMBtu/d)		530,156			566,472			596,150
Natural gas sales (MMBtu) (3)		81,760,690			89,690,706			92,376,383
NGL sales (gallons) (3)		631,248,301			589,020,090			542,311,822

Average Pricing
Realized natural gas ($/MMBtu) (4)	$	4.19		$	3.43		$	7.67
Realized NGL ($/gallon) (4)		1.05			0.78			1.37
Natural Gas Daily WAHA ($/MMBtu)		4.21			3.47			7.57
Natural Gas Daily El Paso ($/MMBtu)		4.15			3.41			7.44
Estimated plant processing spread ($/gallon)		0.65			0.47			0.64

________________

(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, 2009 and 2008, the Company’s operating revenues and related volumes attributable to its buy-sell arrangements for natural gas totaled $38.1 million, $41.4 million and $95.7 million, and 7.8 million MMBtus, 11.7 million MMBtus and 12.2 million MMBtus, respectively. The Company’s operating revenues and related volumes attributable to its buy-sell arrangements for NGL totaled $116.9 million, $69.2 million and $117.9 million and 119.7 million gallons, 91.2 million gallons and 83 million gallons, for the years ended December 31, 2010, 2009 and 2008, 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, 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.

Severe cold weather conditions in February 2011 resulted in damage to two of the Company’s natural gas processing plants. Producers upstream of the Company’s plants also suffered production freeze-offs in part due to the weather conditions and in part due to the Company’s inability to continue to take their production. The damage to the Company’s plants resulted in shut-in or operating at reduced volumes at two natural gas processing facilities for a period of two weeks. Attendant production at these facilities is now at or near pre-event operating levels as production from producers’ wells returns to pre-event levels. The Company estimates a negative impact to its EBIT for February 2011 of approximately $7 million.

Year ended December 31, 2009 versus the year ended December 31, 2008. The $185.8 million EBIT reduction in the year ended December 31, 2009 versus the same period in 2008 was primarily due to the following items:

·	Lower gross margin of $196.6 million primarily as the result of:

Lower operating revenues of $687.1 million largely attributable to lower market-driven realized average natural gas and NGL prices (unadjusted for the impact of realized and unrealized commodity derivative gains and losses) of $3.43 per MMBtu and $0.78 per gallon in the 2009 period versus $7.67 per MMBtu and $1.37 per gallon in the 2008 period, respectively;

o	A $592.2 million decrease in the cost of gas and other energy in the 2009 period versus the 2008 period due to lower market-driven natural gas and NGL purchase costs;

o	Impact of a net hedging loss of $44.6 million in the 2009 period versus a net hedging gain of $57.1 million in the 2008 period (which includes the impact of $44.8 million of unrealized losses recorded in 2009);

o	A reduction of approximately $10.6 million in gross margin in 2008 resulting from damage by Hurricane Ike to the Company’s third-party NGL fractionator; and

o	A reduction of approximately $4.9 million in gross margin attributable to a fire on July 17, 2009 at the Keystone processing plant resulting in a production outage until August 1, 2009 and additional reduced production flow;

·	Higher depreciation and amortization expense of $4 million primarily attributable to a $68.2 million increase in property, plant and equipment placed in service after December 31, 2008;

·	Lower operating, maintenance and general expenses of $10.4 million primarily due to:

o	A $5.8 million decrease in maintenance, contract services and other plant operating costs largely attributable to a 2009 cost reduction initiative primarily related to the Company’s variable and discretionary costs;

o	A $2.3 million loss in 2008 related to the settlement of the GP II Energy litigation;

o	Higher bad debt expense of $2.2 million recorded in 2008 versus 2009 associated with a company that filed for bankruptcy protection in 2008;

o	A $1.8 million decrease in chemical and lubricants costs, which generally track the price of oil;

o	A $1.5 million decrease in utility costs primarily due to lower compressor fuel costs attributable to the declining costs of natural gas in 2009 versus 2008; and

o	A $4.6 million net loss in 2009 versus 2008 primarily resulting from the write-off of property and equipment damaged by the fire at the Keystone natural gas processing plant in 2009; and

Higher equity earnings of $5.4 million from the Company’s unconsolidated investment in Grey Ranch primarily due to higher volumes in 2009 versus the 2008 period resulting from an increase in capacity from 90 MMcf/d to 200 MMcf/d effective December 31, 2008 and due to a plant outage at the processing plant during the third quarter of 2008 resulting from a fire at the facility in June 2008.

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 18 – 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,
	2010			2009		2008
	(In thousands)

Net operating revenues (1)	$	235,171		$	221,387	$	221,111

Operating, maintenance and general		125,847			118,338		116,288
Depreciation and amortization		32,544			31,269		30,530
Taxes other than on income
and revenues		12,781			11,925		11,045
Total operating income		63,999			59,855		63,248
Other income (expenses), net		(307	)		7,447		(1,830	)
EBIT	$	63,692		$	67,302	$	61,418

Operating Information:
Natural gas sales volumes (MMcf)		56,522			56,779		61,469
Natural gas transported volumes (MMcf)		27,218			26,212		28,214

Weather – Degree Days: (2)
Missouri Gas Energy service territories		5,033			4,985		5,499
New England Gas Company service territories		5,288			5,633		5,348

___________________________

(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.

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.

Year ended December 31, 2009 versus the year ended December 31, 2008. The $5.9 million EBIT improvement in the year ended December 31, 2009 versus the same period in 2008 was primarily due to:

·	Higher other income of $9.3 million primarily due to $8.1 million of income in 2009 resulting from settlements with insurance companies related to certain environmental matters;

Higher net operating revenues of $300,000 primarily due to $5.6 million of higher net operating revenues at New England Gas Company largely attributable to new rates associated with the $3.7 million annual rate increase effective February 3, 2009 and colder weather in the 2009 period, partially offset by a lower contribution of $5.3 million from Missouri Gas Energy primarily due to the impact of warmer weather in the 2009 period and lower market-driven pipeline capacity release and off system sales of $2.8 million in 2009 versus 2008;

Higher operating, maintenance and general expenses of $2.1 million primarily due to higher pension costs of $1.9 million, which are recovered in current rates, and higher labor costs of $1.7 million largely due to salaries previously capitalized in the 2008 period, new positions filled in the 2009 period, and merit and incentive increases in 2009 versus 2008, partially offset by $2 million of lower environmental remediation costs primarily attributable to the establishment of reserves in 2008 related to completed site investigation evaluations;

·	Higher taxes other than on income and revenues of $900,000 largely attributable to increased property value assessments in 2009 applicable to Missouri Gas Energy; and

·	Higher depreciation expense of $700,000 primarily attributable to a $39.1 million increase in property, plant and equipment placed in service after December 31, 2008.

The Company has benefitted from various federal and state governmental programs that have provided home energy assistance to low income customers. During 2010, 2009 and 2008, the Company received, through grants made on behalf of customers, funding from these agencies totaling $8.9 million, $11.9 million and $10.3 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.

Corporate and Other Activities

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.

Year ended December 31, 2009 versus the year ended December 31, 2008. The EBIT improvement of $13.8 million was primarily due to:

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

·	Higher legal fees of $5.9 million in the 2008 period primarily attributable to litigation.

Interest Expense

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.

Year ended December 31, 2009 versus the year ended December 31, 2008. Interest expense was $10.6 million lower in the year ended December 31, 2009 versus the same period in 2008 primarily due to:

·	Lower interest expense of $10.1 million primarily due to the effect of lower LIBOR interest rates on the $360.4 million variable rate Trunkline LNG term loan agreement;

Lower interest expense of $6.8 million primarily due to the impact of the higher level of capitalized interest costs attributable to higher average capital project balances outstanding in 2009 compared to 2008. Capitalized interest is expected to reduce in 2010 primarily due to a lower level of projected capital expenditures in 2010 versus 2009;

·	Lower interest expense of $3.5 million associated with borrowings under the Company’s revolving credit agreements primarily due to lower average interest rates and lower average outstanding balances in 2009 compared to 2008;

Higher net interest expense of $7.1 million primarily due to higher outstanding debt balances from the $400 million 7.00% Senior Notes issued in June 2008, the $150 million 8.125% Senior Notes issued in June 2009 and the $150 million term loan issued in August 2009, partially offset by lower interest expense resulting from the repayment of the $300 million 4.80% Senior Notes in August 2008, the $125 million 6.15% Senior Notes in August 2008 and the $60.6 million 6.50% Senior Notes in July 2009; and

·	Higher other interest costs of $2.7 million primarily attributable to lower net debt premium amortization in 2009 resulting from debt retirements.

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,
		2010		2009		2008
		(In thousands)

Income tax expense	$	107,029	$	71,900	$	104,775
Effective tax rate (1)		31%		29%		26%

________________

(1)

The EITR applicable to continuing operations 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, 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.

Year ended December 31, 2009 versus the year ended December 31, 2008. The $32.9 million reduction of federal and state income tax expense was primarily due to lower pre-tax earnings of $148.4 million for the year ended December 31, 2009.

See Item 8. Financial Statements and Supplementary Data, Note 9 – Income Taxes for additional information regarding items impacting the EITR.

Loss from Discontinued Operations

Year ended December 31, 2010 versus the year ended December 31, 2009. The $18.1 million loss recorded in 2010 is due to the First Circuit affirming the Company’s conviction of an RCRA violation in a mercury permitting trial and denying the Company's petition for an en banc rehearing. See Item 8. Financial Statements and Supplementary Data, Note 14 – Commitments and Contingencies – Litigation – Mercury Release for additional related information.

Preferred Stock Dividends and Loss on Extinguishment of Preferred Stock

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 7.55% Noncumulative Preferred Stock, Series A (Liquidation Preference $250 per share) (Preferred Stock) and the reduction in related dividends of $3.6 million in the 2010 period versus the 2009 period associated with these redemptions.

Year ended December 31, 2009 versus the year ended December 31, 2008. The $3.5 million reduction in Preferred stock dividends and Loss on extinguishment of preferred stock for the year ended December 31, 2009 versus the same period in 2008 was due to the impact of the loss the Company recorded in the 2008 period related to its purchase of 4,599,987 depository shares representing 459,999 shares of its Preferred Stock and the reduction in related dividends of $3.5 million in the 2009 period versus the 2008 period associated with these repurchases.

See Item 8. Financial Statements and Supplementary Data, Note 16 – Preferred Securities for additional related information.

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, 2010 is $216 million. 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,
	2010			2009			2008
				(In thousands)
Cash flows provided by (used in):
Operating activities	$	424,671		$	579,213		$	486,827
Investing activities		(392,491	)		(419,424	)		(568,952	)
Financing activities		(39,426	)		(153,562	)		80,753
Increase (decrease) in cash and cash equivalents	$	(7,246	)	$	6,227		$	(1,372	)

Operating Activities

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 was $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.

Year ended December 31, 2009 versus the year ended December 31, 2008. Cash provided by operating activities increased by $92.4 million in the 2009 period versus the same period in 2008. Cash flows provided by operating activities before changes in operating assets and liabilities for the 2009 period was $500.3 million compared with $540.6 million for the 2008 period, a decrease of $40.3 million primarily resulting from lower net earnings in 2009. Changes in operating assets and liabilities provided cash of $78.9 million in the 2009 period and used cash of $53.7 million in the 2008 period, resulting in an increase in cash from changes in operating assets and liabilities of $132.7 million in 2009 compared to 2008. The $132.7 million increase is primarily due to:

·	Decreased inventory of $110.2 million in the Distribution segment largely attributable to lower natural gas prices in the 2009 period;

·	Decrease in tax payment obligations of $69.4 million primarily due to lower pre-tax earnings in 2009 versus 2008; and

·	Higher net cash settlements of $55.7 million of commodity derivative instruments in the Gathering and Processing segment in the 2009 period versus the 2008 period.

These increases were partially offset by higher deferred natural gas purchase costs of $86.1 million resulting from the normal regulatory lag in recovering such deferred natural gas “pass through” costs.

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 $26 million tax benefit for the years 2008 through 2010 associated with additional first-year bonus tax depreciation in excess of historical tax depreciation. The amount of tax benefit applicable to years 2011 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 year 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 to partially fund the Phase VIII Expansion.

Cash flows used in investing activities in the year ended December 31, 2009 and 2008 were $419.4 million and $569 million, respectively. The $149.5 million decrease in investing cash outflows is primarily due to a $152.8 million decrease in capital and property retirement expenditures, net of $21 million of higher insurance reimbursements received for hurricane damages, in the 2009 period. See Item 8. Financial Statements and Supplementary Data, Note 14 – Commitments and Contingencies – Other Commitments and Contingencies – 2008 Hurricane Damage for information related to insurance recoveries that partially offset the capital and property retirement expenditures.

The following table presents a summary of capital expenditures for long-lived assets by segment.

	Years ended December 31,
	2010		2009			2008
	(In thousands)

Transportation and Storage	$	145,674		$	247,097		$	434,004
Gathering and Processing		95,577			70,221			67,317
Distribution		41,484			46,090			41,125
Total segment expenditures for long-lived assets		282,735			363,408			542,446
Corporate and other activities		4,690			30,141			9,345
Total expenditures for long-lived assets (1)	$	287,425		$	393,549		$	551,791

____________________

(1) Related cash impact includes the net reduction in capital accruals totaling $9.5 million, $22 million and $21.9 million for the years ended December 31, 2010, 2009 and 2008, respectively.

Principal Capital Expenditure Projects

See Item 1. Business – Business Segments – Transportation and Storage Segment – Recent System Enhancements – Completed or Under Construction for additional information on the major 2010 and ongoing capital expenditure projects within the Company’s Transportation and Storage segment.

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, suffered damage to several platforms and gathering pipelines. In late July 2009, during testing to put the remaining offshore facilities back in service, Sea Robin experienced a pipeline rupture in an area where the pipeline had previously been displaced during Hurricane Ike and subsequently re-buried. Sea Robin experienced reduced volumes until January 2010 when the remainder of the damaged facilities was back in service.

The capital replacement and retirement expenditure estimates relating to Hurricane Ike have been reduced from $185 million to approximately $150 million and are expected to be completed in 2011. Approximately $134 million, $110 million and $23 million of the capital replacement and retirement expenditures were incurred as of December 31, 2010, 2009 and 2008, 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. The Company received a total of $25.8 million and $36.7 million in 2010 and 2009, respectively, for claims submitted to date 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.

Potential Sea Robin Impairment. Sea Robin, comprised primarily of offshore facilities, suffered damage from Hurricane Ike related to several platforms and gathering pipelines. See Item 8. Financial Statements and Supplementary Data, Note 2 – Summary of Significant Accounting Policies and Other Matters – Asset Impairment for information related to the Company’s analysis of the Sea Robin assets for potential impairment as of December 31, 2009. As there were no indicators of potential impairment during 2010, the impairment test on Sea Robin was not performed as of December 31, 2010. The Company currently estimates that approximately $115 million of the approximately $150 million total estimated capital replacement and retirement expenditures to replace property and equipment damaged by Hurricane Ike are related to Sea Robin. The Company anticipates partial reimbursement from its property insurance carrier for its damages in excess of its $10 million deductible, except for certain expenditures not reimbursable under the insurance policy terms. See Item 8. Financial Statements and Supplementary Data, Note 14 – Commitments and Contingencies – Other Commitments and Contingencies – 2008 Hurricane Damage for additional related information. Additionally, Sea Robin has implemented a rate surcharge approved by FERC in September 2009, subject to refund, to recover Hurricane Ike related costs not otherwise recovered from insurance proceeds or from other third parties. To the extent the Company’s capital expenditures are not recovered through insurance proceeds or through its hurricane rate surcharge, its net investment in Sea Robin’s property and equipment would increase without necessarily generating additional revenues unless the incremental costs are recovered through future rate proceedings or additional throughput. See Item 8. Financial Statements and Supplementary Data, Note 18 – Regulation and Rates – Panhandle for information related to the surcharge filing. If the amount of the estimated Sea Robin insurance reimbursements are significantly reduced or Sea Robin experiences other adverse developments incrementally impacting the Company’s related net investment or anticipated future cash flows that are not remedied through rate proceedings, the Company could potentially be required to record an impairment of its net investment in Sea Robin.

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 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 $13.6 million in 2010 related to this program and estimates incurring approximately $104.9 million over the next 10 years, after which all service lines, representing about 39 percent of the annual safety program investment, will have been replaced.

Citrus Sponsor Contributions. In 2010, the Company and Citrus’ other shareholder 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. During the first half of 2011, it is expected Citrus will require additional sponsor provided contributions, which may be in the form of loans or equity contributions from each of its shareholders of up to $150 million. Citrus plans to resume cash distributions, which may be in the form of loan repayments or dividends, to its sponsors after the Phase VIII Expansion project is placed in service.

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 $39.4 million and $153.6 million in the year 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.

Financing activities used cash flows of $153.6 million in the year ended December 31, 2009 and provided cash flows of $80.8 million in the same period in 2008. The $234.3 million increase in net financing cash outflows was primarily due to:

·	Payments of $321.5 million under the Company’s revolving credit facilities and retirement of short-term debt obligations in 2009 compared to $278.5 million in borrowings in 2008;

·	Impact of $100 million of cash received by the Company from the issuance of common stock in the 2008 period;

·	Lower net issuances of long-term debt of $316.4 million in the 2009 period versus the 2008 period; and

·	Impact of $115.2 million in the 2008 period related to the purchase of 459,999 shares of the Company’s Preferred Stock.

Debt Refinancing, Repayment and Issuance Activity

8.125% Senior Notes. In June 2009, PEPL issued $150 million in senior notes due June 1, 2019 with an interest rate of 8.125 percent (8.125% Senior Notes). In connection with the issuance of the 8.125% Senior Notes, PEPL incurred underwriting and discount costs totaling approximately $1 million, resulting in approximately $149 million in proceeds to PEPL. These proceeds were used to repay borrowings under the Company’s credit facilities and to repay the $60.6 million of 6.50% Senior Notes that matured on July 15, 2009.

7.00% Senior Notes. In June 2008, PEPL issued $400 million in senior notes due June 15, 2018 with an interest rate of 7.00 percent (7.00% Senior Notes). In connection with the issuance of the 7.00% Senior Notes, PEPL incurred underwriting and discount costs totaling approximately $4.1 million, resulting in approximately $395.9 million in proceeds to PEPL. These proceeds were advanced to Southern Union and used to repay borrowings under its credit facilities. Southern Union repaid PEPL a portion of the advance to retire the $300 million 4.80% Senior Notes in August 2008.

Term Loans. On August 5, 2009, the Company entered into a two-year $150 million term loan (2009 Term Loan) with a syndicate of banks. The proceeds of the 2009 Term Loan were used to repay borrowings under the credit facilities.

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 2009 Term Loan. The 2009 Term Loan had an interest rate of LIBOR plus 3.75 percent. Proceeds received from the 2010 Term Loan were used to refinance the existing indebtedness under the 2009 Term Loan described above, with the remaining proceeds to be used to provide working capital and for general corporate purposes. The balance of the 2010 Term Loan was $250 million with an effective interest rate of 2.39 percent at December 31, 2010. The balance and effective interest rate of the Amended Credit Agreement at February 18, 2011 were $250 million and 2.39 percent, respectively.

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

Credit Facilities. On February 26, 2010, the Company entered into the Sixth Amended and Restated Revolving Credit Agreement with the banks named therein in the amount of $550 million (2010 Revolver). The 2010 Revolver will mature on May 28, 2013. Borrowings on the 2010 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 2010 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 2010 Revolver at December 31, 2010 were LIBOR, plus 275 basis points, and 50 basis points, respectively. The Company’s additional $20 million short-term committed credit facility was renewed in July 2010 for an additional 364-day period.

The 2010 Revolver is a refinancing of the Company’s $400 million Fifth Amended and Restated Revolving Credit Agreement (Revolver), which was otherwise scheduled to mature on May 28, 2010. Borrowings under the Revolver were available for Southern Union’s working capital and letter of credit requirements and other general corporate purposes. The interest rate for the Revolver was based on LIBOR plus 62.5 basis points.

Balances of $297.1 million and $80 million were outstanding under the Company’s credit facilities at effective interest rates of 3.02 percent and 0.85 percent at December 31, 2010 and 2009, 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 18, 2011, there was a balance of $243.8 million outstanding under the Company’s credit facilities at an average effective interest rate of 3.03 percent.

Common Stock and Equity Units Issuances

On February 8, 2008, the Company remarketed its 4.375% Senior Notes, which yielded no cash proceeds for the Company. The interest rate on the Senior Notes was reset to 6.089 percent per annum effective on and after February 19, 2008. The 6.089% Senior Notes matured on February 16, 2010. On February 19, 2008, the Company issued 3,693,240 shares of common stock for $100 million in cash proceeds in conjunction with the remarketing of the 4.375% Senior Notes.

Retirement of Debt Obligations

The Company repaid the $100 million 6.089% Senior Notes in February 2010 and the $40.5 million 8.25% Senior Notes in April 2010 primarily using draw downs under the credit facilities.

Credit Ratings. As of December 31, 2010, 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. 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 debt obligations could increase annually up to approximately $8.1 million;

·	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 10 – 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.

OTHER MATTERS

Off-Balance Sheet Arrangements and Aggregate Contractual Obligations

The Company does not have any material off-balance sheet arrangements. The following table summarizes the Company’s expected contractual obligations by payment due date as of December 31, 2010.

	Contractual Obligations
													2016 and
	Total		2011		2012		2013		2014		2015		thereafter
	(In thousands)

Long-term debt (1)(2)	$	3,519,258	$	1,083	$	816,216	$	500,797	$	772	$	751	$	2,199,639
Short-term borrowing,
including credit facilities (1)		297,051		297,051		-		-		-		-		-
Natural gas purchases (3)		96,712		65,869		4,288		3,306		3,202		3,112		16,935
Missouri Gas Energy
Safety Program		104,876		12,103		11,197		11,309		11,422		11,536		47,309
Transportation contracts		294,301		81,732		76,372		49,632		12,841		11,244		62,480
Natural gas storage
contracts (4)		261,022		44,576		38,862		35,571		30,981		27,394		83,638
Operating lease payments		154,277		17,765		12,904		15,520		14,670		13,627		79,791
Interest payments on debt (5)		3,840,169		188,934		183,769		178,940		160,328		160,328		2,967,870
Fractionation contract		210,971		21,473		22,787		23,082		23,324		23,578		96,727
Other (6)		52,777		45,930		938		533		348		261		4,767
	$	8,831,414	$	776,516	$	1,167,333	$	818,690	$	257,888	$	251,831	$	5,559,156

_________________________

(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, 2010, the Company was in compliance with all of its covenants. See Item 8. Financial Statements and Supplementary Data, Note 7 – Debt Obligations.

(2)	The long-term debt principal payment obligations exclude $2.7 million of unamortized debt premium as of December 31, 2010.

(3)	The Company has purchase natural gas 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, 2010. Includes approximately $2.38 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 14 – Commitments and Contingencies.

Inflation

The Company believes that inflation has caused, and may continue to cause, increases in certain operating expenses, 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 18 – Regulation and Rates.

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 and associated revenues of $54.7 million and $68.5 million, respectively. BG LNG Services (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 18 – Regulation and Rates for information related to the Company’s other rate matters.

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.

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 amount of regulatory assets reflected in the Consolidated Balance Sheet applicable to the Distribution segment are $66.2 million and $72.3 million at December 31, 2010 and 2009, respectively. The aggregate amount of regulatory liabilities reflected in the Consolidated Balance Sheet applicable to the Distribution segment are $5.8 million and $8.5 million at December 31, 2010 and 2009, respectively. For a summary of regulatory matters applicable to the Company, see Item 8. Financial Statements and Supplementary Data, Note 18 – Regulation and Rates. Panhandle and SUGS do not currently apply regulatory accounting standards.

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.

The long-lived assets of Sea Robin were evaluated as of December 31, 2009 because indicators of potential impairment were evident primarily due to the impacts associated with Hurricanes Gustav and Ike. See related information in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Investing Activities – Principal Capital Expenditure Projects – 2008 Hurricane Damage and Potential Sea Robin Impairment.

Goodwill Impairment Evaluation. At December 31, 2010, 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, 2010, 2009 and 2008, and no impairment was indicated in the step one test.

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, 2010, 2009 and 2008, and no impairment was indicated.

Pensions and Other Postretirement Benefits

Effective December 31, 2008, 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 the 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 2010 net periodic benefit cost (before regulatory accounting adjustments) and benefit obligation at the end of 2010 by approximately $770,000 and $19.1 million, respectively, and would correspondingly increase Accumulated other comprehensive loss at the end of 2010 by $19.1 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 2010 net periodic benefit cost (before regulatory accounting adjustments) by approximately $980,000.

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

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 10 – 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 11 – Fair Value Measurement and Note 8 – 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.

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 9 – 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 14 – 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, 2010, the interest rate on 83 percent of the Company’s long-term debt was fixed after considering the impact of interest rate swaps.

At December 31, 2010, $19.7 million is included in Derivative instruments - liabilities and $4.6 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.

At December 31, 2010, a 100 basis point change in the annual interest rate on all outstanding floating-rate long- and short-term debt would correspondingly change the Company’s interest payments by approximately $800,000 for each month during which such change continued. If interest rates changed significantly, the Company may take actions to manage its exposure to the change.

The Company has entered 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.

The change in exposure to loss in earnings and cash flow related to interest rate risk for the year ended December 31, 2010 is not material to the Company.

See Item 8. Financial Statements and Supplementary Data, Note 10 – Derivative Instruments and Hedging Activities and Note 7 - 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 processing spread puts and swaps, and (iii) 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 NGL take-away capacity;

·	reduction in NGL available from wellhead supply;

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

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

·	limitations on NGL fractionation capacity;

·	renegotiation of existing contracts;

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

·	competition for new wellhead supplies; and

·	changes to environmental or other laws and regulations.

The following table summarizes SUGS' principal commodity derivative instruments as of December 31, 2010 (all instruments are settled monthly), which were developed based upon historical and projected operating conditions and processable volumes.

		Average				Fair Value
		Fixed Price		Volumes		of Assets
Instrument Type	Index	(per MMBtu)		(MMBtu/d) (3)		(Liabilities) (4)
						(In thousands)

Natural Gas - Cash Flow Hedges: (1)
Receive-fixed swap	Gas Daily - Waha	$	6.12		13,813	$	9,094
Receive-fixed swap	Gas Daily - El Paso Permian	$	6.12		11,187		7,366
		Total			25,000	$	16,460

Processing Spread - Economic Hedges: (2)
Receive-fixed swap	Gas Daily - Waha (natural gas)
	OPIS - Mt. Belvieu (NGL)	$	5.51		13,813	$	(16,054	)
Receive-fixed swap	Gas Daily - El Paso Permian (natural gas)
	OPIS - Mt. Belvieu (NGL)	$	5.51		11,187		(13,003	)
		Total			25,000	$	(29,057	)

__________________

(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 processing spread swap arrangements, which hedge the pricing differential between NGL volumes and natural gas volumes, are treated as economic hedges. The ratio of NGL product sold per MMBtu is approximately: 34 percent ethane, 32 percent propane, 5 percent isobutane, 14 percent normal butane and 15 percent natural gasoline. The change in fair value is reported in current-period earnings.

(3)	All volumes are applicable to the period January 1, 2011 to December 31,2011.

(4)	See Item 8. Financial Statements and Supplementary Data, Note 10 – Derivative Instruments and Hedging Activities – Commodity Contracts – Gathering and Processing Segment for additional related information.

At December 31, 2010, 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 $1.5 million and $7.4 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, 2010, there were no hedges in place with respect to natural gas price risk associated with the Company’s interstate pipeline operations.

Distribution Segment Economic Hedging Activities. The Company enters into financial instruments to mitigate price volatility of purchased natural gas passed through to customers in the 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, 2010, the fair values of the contracts, which expire at various times through December 2012, are included in the Consolidated Balance Sheet as liabilities, with matching adjustments to deferred cost of natural gas of $37.4 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

Southern Union 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, insurance 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, 2010.

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.

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, 2010.

The Company’s internal control over financial reporting as of December 31, 2010 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 25, 2011

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, 2010 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, 2010 was appropriately reported.

PART III

ITEM 10. Directors, Executive Officers and Corporate Governance.

There is incorporated in this Item 10 by reference the information that will appear in the Company’s definitive proxy statement for the 2011 Annual Meeting of Stockholders under the captions Meetings and Committees of the Board – Board of Directors, 2010 Executive Compensation – Named Executive Officers, Section 16(a) Beneficial Ownership Reporting Compliance, Corporate Governance – Code of Ethics, Meetings and Committees of the Board – Board Committees – Corporate Governance Committee and – Audit Committee.

The Company, by and through the audit committee of its 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 (http://www.sug.com).

ITEM 11. Executive Compensation.

There is incorporated in this Item 11 by reference the information that will appear in the Company’s definitive proxy statement for the 2011 Annual Meeting of Stockholders under the captions Compensation Discussion and Analysis, 2010 Executive Compensation, 2010 Director Compensation, and Meetings and Committees of the Board – Board Committees – Compensation Committee.

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

There is incorporated in this Item 12 by reference the information that will appear in the Company’s definitive proxy statement for the 2011 Annual Meeting of Stockholders under the caption Security Ownership of Certain Beneficial Owners and Management.

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

There is incorporated in this Item 13 by reference the information that will appear in the Company’s definitive proxy statement for the 2011 Annual Meeting of Stockholders under the caption Corporate Governance – Transactions with Related Persons and – Review, Approval or Ratification of Transactions with Related Persons, and Corporate Governance – Director Independence and – Lead Independent Director.

ITEM 14. Principal Accountant Fees and Services.

There is incorporated in this Item 14 by reference the information that will appear in the Company’s definitive proxy statement for the 2011 Annual Meeting of Stockholders under the caption Meetings and Committees of the Board – Board Committees – Audit Committee.

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)

Purchase and Sale Agreement between Southern Union Company and UGI Corporation, dated as of January 26, 2006. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on January 30, 2006 and incorporated herein by reference.)

2(b)

First Amendment to the Purchase and Sale Agreement between Southern Union Company and UGI Corporation, dated as of August 24, 2006. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on August 30, 2006 and incorporated herein by reference.)

2(c)

Purchase and Sale Agreement between Southern Union Company and National Grid USA, dated as of February 15, 2006. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on February 17, 2006 and incorporated herein by reference.)

2(d)

First Amendment to the Purchase and Sale Agreement between Southern Union Company and National Grid USA, dated as of August 24, 2006. (Filed as Exhibit 10.3 to Southern Union’s Current Report on Form 8-K filed on August 30, 2006 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.)

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)

Sixth Amended and Restated Revolving Credit Agreement, dated as of February 26, 2010, among the Company, as borrower, and the lenders party thereto. (Filed as Exhibit 10(a) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2009 and incorporated herein by reference.)

10(b)

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(c)

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.)

10(d)

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(e)

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(f)

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(g)

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 Hypo-Und Vereinsbank AG, New York Branch, as administrative agent, dated as of March 15, 2007. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on March 21, 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).*

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.

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.

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 25, 2011.

	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 25, 2011.

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

SOUTHERN UNION COMPANY AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Financial Statements and Supplementary Data:	Page(s):
Consolidated Statement of Operations	F-2
Consolidated Balance Sheet	F-3 - F-4
Consolidated Statement of Cash Flows	F-5
Consolidated Statement 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-62

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

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF OPERATIONS

	Years Ended December 31,
	2010			2009				2008
	(In thousands, except per share amounts)
Operating revenues (Note 17):
Natural gas gathering and processing	$	1,008,023			$	732,251		$	1,521,041
Natural gas distribution		698,513				692,904			821,673
Natural gas transportation and storage		769,450				749,161			721,640
Other		13,927				4,702			5,800
Total operating revenues		2,489,913				2,179,018			3,070,154

Operating expenses:
Cost of natural gas and other energy		1,243,749				1,060,892			1,774,682
Operating, maintenance and general		463,517				468,721			473,614
Depreciation and amortization		228,637				213,827			199,249
Revenue-related taxes		37,619				36,375			44,259
Taxes, other than on income and revenues		55,776				53,114			48,371
Total operating expenses		2,029,298				1,832,929			2,540,175

Operating income		460,615				346,089			529,979

Other income (expenses):
Interest expense		(216,665	)			(196,800	)		(207,408	)
Earnings from unconsolidated investments		105,415				80,790			75,030
Other, net (Note 21)		312				21,401			2,325
Total other expenses, net		(110,938	)			(94,609	)		(130,053	)

Earnings from continuing operations before income taxes		349,677				251,480			399,926

Federal and state income tax expense (Note 9)		107,029				71,900			104,775

Earnings from continuing operations		242,648				179,580			295,151

Loss from discontinued operations (Note 14)		(18,100	)			-			-

Net earnings		224,548				179,580			295,151

Preferred stock dividends		(5,040	)			(8,683	)		(12,212	)
Loss on extinguishment of preferred stock		(3,295	)			-			(3,527	)

Net earnings available for common stockholders	$	216,213			$	170,897		$	279,412

Net earnings available for common stockholders
from continuing operations per share (Note 4):
Basic	$	1.88			$	1.38		$	2.26
Diluted	$	1.87			$	1.37		$	2.26

Net earnings available for common stockholders per share (Note 4):
Basic	$	1.74			$	1.38		$	2.26
Diluted	$	1.73			$	1.37		$	2.26
Cash dividends declared on common stock per share:	$	0.60			$	0.60		$	0.60

Weighted average shares outstanding (Note 4):
Basic		124,474				124,076			123,446
Diluted		125,191				124,409			123,644

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

F-2

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

ASSETS
	December 31,
	2010			2009
	(In thousands)

Current assets:
Cash and cash equivalents	$	3,299		$	10,545
Accounts receivable
net of allowances of $3,321 and $1,874, respectively		310,006			277,661
Accounts receivable – affiliates		10,747			10,387
Inventories		226,875			290,031
Deferred natural gas purchases		85,138			88,421
Natural gas imbalances - receivable		52,141			127,284
Prepayments and other assets		67,535			57,024
Total current assets		755,741			861,353

Property, plant and equipment (Note 12):
Plant in service		6,957,989			6,260,188
Construction work in progress		120,264			531,710
		7,078,253			6,791,898
Less accumulated depreciation and amortization		(1,373,794	)		(1,162,685	)
Net property, plant and equipment		5,704,459			5,629,213

Deferred charges:
Regulatory assets (Note 3)		66,216			72,304
Deferred charges		66,929			60,995
Total deferred charges		133,145			133,299

Unconsolidated investments (Note 5)		1,538,548			1,340,048

Goodwill		89,227			89,227

Other		17,423			21,934


Total assets	$	8,238,543		$	8,075,074


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

F-3

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

STOCKHOLDERS' EQUITY AND LIABILITIES

	December 31,
	2010			2009
	(In thousands)

Stockholders’ equity (Note 15):
Common stock, $1 par value; 200,000 shares authorized; 125,839
and 125,569 shares issued at December 31, 2010 and 2009	$	125,839		$	125,569
Preferred stock, no par value; 6,000 shares authorized; nil and
460 shares issued at December 31, 2010 and 2009 (Note 16)		-			115,000
Premium on capital stock		1,920,622			1,905,293
Less treasury stock: 1,230 and 1,171 shares, respectively, at cost		(30,532	)		(29,109	)
Less common stock held in trust: 597 and 659 shares, respectively		(10,857	)		(11,769	)
Deferred compensation plans		10,857			11,769
Accumulated other comprehensive loss (Note 6)		(40,157	)		(56,505	)
Retained earnings		551,210			409,698
Total stockholders' equity		2,526,982			2,469,946

Long-term debt obligations (Note 7)		3,520,906			3,421,236

Total capitalization		6,047,888			5,891,182

Current liabilities:
Long-term debt due within one year (Note 7)		1,083			140,500
Notes payable (Note 7)		297,051			80,000
Accounts payable and accrued liabilities		218,531			246,394
Federal, state and local taxes payable		35,235			4,293
Accrued interest		37,464			40,061
Natural gas imbalances - payable		178,087			322,200
Derivative instruments (Note 10 and 11)		67,026			97,008
Other		137,221			123,899
Total current liabilities		971,698			1,054,355

Deferred credits		205,094			223,950

Accumulated deferred income taxes (Note 9)		1,013,863			905,587

Commitments and contingencies (Note 14)

Total stockholders' equity and liabilities	$	8,238,543		$	8,075,074



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

F-4

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS

	Years Ended December 31,
	2010			2009			2008
	(In thousands)

Cash flows provided by (used in) operating activities:
Net earnings	$	224,548		$	179,580		$	295,151
Adjustments to reconcile net earnings to net cash flows
provided by (used in) operating activities:
Depreciation and amortization		228,637			213,827			199,249
Deferred income taxes		107,418			121,210			83,066
Provision for bad debts		8,681			8,601			12,338
Unrealized loss (gain) on commodity derivatives		18,514			44,778			(57,821	)
Loss from discontinued operations		18,100			-			-
Loss (gain) on asset sales or dispositions		1,867			5,563			(581	)
Share-based compensation expense		9,331			7,510			6,468
Earnings from unconsolidated investments,
adjusted for cash distributions		(101,915	)		(80,790	)		2,120
Changes in operating assets and liabilities:
Accounts receivable, billed and unbilled		(41,386	)		45,452			6,168
Accounts payable and accrued liabilities		(8,508	)		12,838			(44,950	)
Deferred natural gas purchase costs		(2,883	)		(73,174	)		9,501
Inventories		(2,964	)		76,098			(65,384	)
Prepaids and other assets		(1,534	)		60,748			21,070
Taxes and other liabilities		17,831			(57,962	)		37,587
Deferred charges		6,891			(266	)		(4,786	)
Deferred credits		(57,957	)		15,200			(12,369	)
Net cash flows provided by operating activities		424,671			579,213			486,827
Cash flows (used in) provided by investing activities:
Additions to property, plant and equipment		(293,022	)		(405,381	)		(588,611	)
Contributions to unconsolidated investments		(100,000	)		(3,250	)		-
Plant retirements and other		531			(10,793	)		19,659
Net cash flows used in investing activities		(392,491	)		(419,424	)		(568,952	)
Cash flows provided by (used in) financing activities:
Increase (decrease) in book overdraft		(14,154	)		8,583			(19,932	)
Issuance of long-term debt		101,019			303,905			403,820
Issuance costs of debt and equity		(7,066	)		(4,011	)		(4,073	)
Issuance of common stock		-			-			100,000
Dividends paid on common stock		(74,668	)		(74,424	)		(73,782	)
Dividends paid on preferred stock		(7,211	)		(8,683	)		(14,382	)
Extinguishment of preferred stock		(115,000	)		-			(115,232	)
Repayment of long-term debt obligation		(140,947	)		(60,623	)		(476,829	)
Net change in revolving credit facilities and short-term debt		217,051			(321,459	)		278,459
Other		1,550			3,150			2,704
Net cash flows provided by (used in) financing activities		(39,426	)		(153,562	)		80,753
Change in cash and cash equivalents		(7,246	)		6,227			(1,372	)
Cash and cash equivalents at beginning of period		10,545			4,318			5,690
Cash and cash equivalents at end of period	$	3,299		$	10,545		$	4,318

Cash paid for interest (net of amounts capitalized)	$	212,442		$	217,437		$	221,152
Cash (received) paid during the period for income taxes		(20,088	)		486			(4,001	)

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

F-5

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT 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, 2007	$	121,102	$	230,000		$	1,784,223		$	(27,839	)	$	(15,085	)	$	15,148		$	(11,594	)	$	109,851		$	2,205,806
Comprehensive income (loss):
Net earnings		-		-			-			-			-			-			-			295,151			295,151
Net change in other
comprehensive loss (Note 6),		-		-			-			-			-			-			(40,920	)		-			(40,920	)
Comprehensive income		-		-			-			-			-			-			-			-			254,231
Effect of changing plan meas-
urement date (Note 8)		-		-			-			-			-			-			1,091			(1,597	)		(506	)
Preferred stock dividends		-		-			-			-			-			-			-			(12,212	)		(12,212	)
Common stock dividends declared		-		-			-			-			-			-			-			(74,384	)		(74,384	)
Issuance of common stock -
\remarketing obligation
(Note 7)		3,693		-			96,307			-			-			-			-			-			100,000
Share-based compensation		-		-			6,468			-			-			-			-			-			6,468
Restricted stock issuances		90		-			(90	)		(165	)		-			-			-			-			(165	)
Exercise of stock options		237		-			3,772			-			-			-			-			-			4,009
Extinguishment of preferred
stock (Note 16)		-		(115,000	)		3,295			-			-			-			-			(3,527	)		(115,232	)
Contributions to Trust		-		-			-			-			(1,096	)		1,096			-			-			-
Disbursements from Trust		-		-			-			-			4,273			(4,336	)		-			-			(63	)
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 6)		-		-			-			-			-			-			(5,082	)		-			(5,082	)
Comprehensive income		-		-			-			-			-			-			-			-			174,498
Preferred stock dividends		-		-			-			-			-			-			-			(8,683	)		(8,683	)
Common stock dividends declared		-		-			-			-			-			-			-			(74,481	)		(74,481	)
Share-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

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

F-6

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT 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, 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 6)			-			-				-			-				-				-				16,348				-				16,348
Comprehensive income			-			-				-			-				-				-				-				-				240,896
Preferred stock dividends			-			-				-			-				-				-				-				(5,040	)			(5,040	)
Common stock dividends declared			-			-				-			-				-				-				-				(74,701	)			(74,701	)
Share-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 16)			-			(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 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.

F-7

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 5,500 miles of natural gas and NGL pipelines, four cryogenic plants with a combined capacity of 415 MMcf/d and five natural gas treating plants with combined capacities of 585 MMcf/d. SUGS is primarily engaged in connecting wells of natural gas producers to its gathering system, treating natural gas to remove impurities to meet pipeline quality specifications, processing natural gas for the removal of NGL, and redelivering natural gas and NGL to a variety of markets. 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.

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. Certain reclassifications have been made to prior years' financial statements to conform to the current year presentation.

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

Property, Plant and Equipment. Ongoing additions of property, plant and equipment are stated at cost. The Company capitalizes all construction-related direct labor and material costs, as well as indirect construction costs. The cost of replacements and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs and replacements of minor property, plant and equipment items is charged to expense as incurred.

When property, plant and equipment is retired within the Company’s Transportation and Storage and Distribution segments, the original cost less salvage value is charged to accumulated depreciation and amortization. When entire regulated operating units of property, plant and equipment are retired or sold or non-regulated properties are retired or sold, the property and related accumulated depreciation and amortization accounts are reduced, and any gain or loss is recorded in earnings. When property, plant and equipment is retired within the Company’s Gathering and Processing segment, the original cost less salvage value and accumulated depreciation and amortization balances are removed, with the resulting gain or loss recorded in earnings.

The Company computes depreciation expense using the straight-line method. Depreciation rates for the utility plants are approved by the applicable regulatory commissions.

F-8

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 12 – 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. The long-lived assets of Sea Robin were evaluated as of December 31, 2009 because indicators of potential impairment were evident primarily due to the impacts associated with Hurricane Ike and due to reductions in the estimated payout from the Company’s insurance carrier for reimbursable expenditures for the repair, retirement or replacement of the Company’s property, plant and equipment damaged by Hurricane Ike, which is more fully discussed in Note 14 – Commitments and Contingencies – Other Commitments and Contingencies – 2008 Hurricane Damage.

As there were no indicators of potential impairment during 2010, the impairment test on Sea Robin was not performed as of December 31, 2010. However, to the extent the Company’s capital expenditures resulting from Hurricane Ike damage are not recovered through insurance proceeds or through Sea Robin’s hurricane rate surcharge, its net investment in Sea Robin’s property and equipment will have increased without necessarily realizing corresponding cash inflows unless the incremental costs are recovered through future rate proceedings or additional throughput. See Note 18 – Regulation and Rates – Sea Robin for information related to the surcharge filing. If the surcharge filing is not ultimately approved by FERC or Sea Robin experiences other adverse developments incrementally impacting the Company’s related net investment or anticipated future cash flows that are not remedied through rate proceedings, the Company could potentially be required to record an impairment of its net investment in Sea Robin.

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, 2010, 2009 and 2008, and no impairment was indicated in the step one test. There were no changes recorded to goodwill for the years ended December 31, 2010, 2009 and 2008.

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, 2010 and 2009, such book overdraft balances classified in accounts payable were approximately $12 million and $26.2 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 17 – Reportable Segments for additional related information.

F-9

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Transportation and Storage Segment Revenues. Revenues from transportation and storage of natural gas and LNG terminalling are based on capacity reservation charges and, to a lesser extent, commodity usage charges. Reservation revenues are based on contracted rates and capacity reserved by the customers and are recognized monthly. Revenues from commodity usage charges are also recognized monthly, based on the volumes received from or delivered for the customer, based on the tariff of that particular Panhandle entity, with any differences in volumes received and delivered resulting in an imbalance. Volume imbalances generally are settled in-kind with no impact on revenues, with the exception of Trunkline, which settles certain imbalances in cash pursuant to its tariff, and records gains and losses on such cashout sales as a component of revenue, to the extent not owed back to customers.

Gathering and Processing Segment Revenues and Cost of Sales Recognition. The business operations of the Gathering and Processing segment consist of connecting wells of natural gas producers to the Company’s gathering system, treating natural gas to remove impurities, processing natural gas for the removal of NGL and then redelivering or marketing the treated natural gas and/or processed NGL to third parties. The terms and conditions of purchase arrangements with producers, including those limited arrangements with the same counterparty, offer various alternatives with respect to taking title to the purchased natural gas and/or NGL. These arrangements include (i) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing in the Company’s plant facilities and (ii) making other direct purchase of natural gas and/or NGL at specified delivery points to meet operational or marketing obligations. Cost of sales primarily includes the cost of purchased natural gas and/or NGL to which the Company has taken title. Operating revenues are derived from the sale of natural gas and/or NGL in the period in which the physical product is delivered to the customer and title is transferred. 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. Unbilled receivables related to the Distribution segment recorded in Accounts receivable in the Consolidated Balance Sheet at December 31, 2010 and 2009 were $51.4 million and $47.3 million, respectively.

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 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.

F-10

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

	Years Ended December 31,
	2010			2009				2008
	(In thousands)

Beginning balance	$	1,874			$	6,003			$	4,144
Additions: charged to cost and expenses		8,681				8,601				12,338
Deductions: write-off of uncollectible accounts		(8,230	)			(14,505	)			(10,560	)
Other		996				1,775				81
Ending balance	$	3,321			$	1,874			$	6,003

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, increased by the assumed conversion of equity units (as applicable for 2008), the assumed exercises of stock options and SARs, and the assumed vesting of restricted stock. See Note 4 – 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 13 – 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) and prior service credits (cost) on pension and other postretirement benefit plans. For more information, see Note 6 – Accumulated Other Comprehensive 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.

F-11

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

	Transportation &		Gathering &
	Storage		Processing		Distribution		Total
	(In thousands)
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

December 31, 2009
Current
Natural gas (1)	$	198,712	$	-	$	56,125	$	254,837
Materials and Supplies		15,995		9,307		3,926		29,228
NGL (2)		-		5,966		-		5,966
Total Current		214,707		15,273		60,051		290,031

Non-Current
Natural gas (1)		8,831		-		-		8,831
	$	223,538	$	15,273	$	60,051	$	298,862

____________________

(1)

Natural gas volumes held for operations in the Transportation and Storage segment at December 31, 2010 and 2009 were 30,598,000 MMBtu and 35,039,000 MMBtu, respectively. Natural gas volumes held for operations in the Distribution segment at December 31, 2010 and 2009 were 12,517,000 MMBtu and 11,742,000 MMBtu, respectively.

(2)	NGL at December 31, 2010 and 2009 were 12,061,000 gallons and 6,680,000 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 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 5 – 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 3 – Regulatory Assets.

F-12

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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;

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, 2010 and 2009.

See Note 11 – Fair Value Measurement and Note 8 – 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.

F-13

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. Effective November 2008, Trunkline LNG entered into a settlement with its customer that provides for monthly reimbursement of actual fuel usage costs, resulting in Trunkline LNG no longer having a fuel tracker. 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, 2010, 2009 and 2008 was $6.6 million, $25.7 million and $19 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 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 10 – Derivative Instruments and Hedging Activities and Note 11 – Fair Value Measurement for additional related information.

F-14

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 20 – 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 8 – 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 14 – Commitments and Contingencies.

New Accounting Principles

Accounting Principles Recently Adopted. In June 2009, the FASB issued authoritative guidance that changes how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly affect the entity’s economic performance. The guidance is effective as of the beginning of the first annual reporting period, and for interim periods within that first period, after November 15, 2009, with early adoption prohibited. This guidance did not materially impact the Company’s consolidated financial statements.

F-15

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In January 2010, the FASB issued authoritative guidance to improve disclosure requirements related to fair value measurements. This guidance requires new disclosures associated with the three-tier fair value hierarchy for transfers in and out of Levels 1 and 2 and for activity within Level 3. It also clarifies existing disclosure requirements related to the level of disaggregation and disclosures about certain inputs and valuation techniques. This guidance is effective for interim or annual financial periods beginning after December 15, 2009, except for the disclosures related to activity within Level 3, which is effective for interim or annual financial periods beginning after December 15, 2010. This guidance did not materially impact the Company’s consolidated financial statements.

3. 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,
	2010		2009
	(In thousands)

Pension and Other Postretirement Benefits	$	18,140	$	24,777
Environmental		38,384		40,617
Missouri Safety Program		1,147		2,228
Other		8,545		4,682
	$	66,216	$	72,304

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. The Company expects that the $17.4 million of regulatory assets at December 31, 2010 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, 2009 relating to Distribution segment operations that are being recovered through current rates totaled $43.7 million. The remaining recovery period associated with these assets ranged from 3 months to 84 months.

F-16

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

4. Earnings Per Share

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


	Years Ended December 31,
	2010			2009			2008
	(In thousands, except per share amounts)

Net earnings from continuing operations	$	242,648		$	179,580		$	295,151
Loss from discontinued operations		(18,100	)		-			-
Preferred stock dividends		(5,040	)		(8,683	)		(12,212	)
Loss on extinguishment of preferred stock		(3,295	)		-			(3,527	)
Net earnings available for common stockholders	$	216,213		$	170,897		$	279,412

Weighted average shares outstanding - Basic		124,474			124,076			123,446
Weighted average shares outstanding - Diluted		125,191			124,409			123,644

Basic earnings per share:
Net earnings available for common stockholders
from continuing operations	$	1.88		$	1.38		$	2.26
Loss from discontinued operations		(0.14	)		-			-
Net earnings available for common stockholders	$	1.74		$	1.38		$	2.26

Diluted earnings per share:
Net earnings available for common stockholders
from continuing operations	$	1.87		$	1.37		$	2.26
Loss from discontinued operations		(0.14	)		-			-
Net earnings available for common stockholders	$	1.73		$	1.37		$	2.26

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,
	2010		2009		2008
	(In thousands)

Weighted average shares outstanding - Basic		124,474		124,076		123,446
Add assumed vesting of restricted stock		134		68		10
Add assumed exercise of stock options and SARs		583		265		188
Weighted average shares outstanding - Diluted		125,191		124,409		123,644

For the years ended December 31, 2010, 2009 and 2008, no adjustments were required in Net earnings available for common stockholders in the diluted EPS calculations.

F-17

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2010, 2009 or 2008.

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,
	2010		2009			2008
	(In thousands, except per share amounts)

Options excluded		1,433			1,892			1,127
Exercise price ranges of options excluded	$	24.06 - 28.48		$	21.64 - 28.48		$	23.62 - 28.48
SARs excluded		738			804			416
Exercise price ranges of SARs excluded	$	24.04 - 28.48		$	21.64 - 28.48		$	28.07 - 28.48
Year-to-date weighted-average market price	$	23.81		$	17.70		$	22.85

F-18

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5. Unconsolidated Investments

Unconsolidated investments at December 31, 2010 and 2009 include the Company’s 50 percent investment in Citrus and 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,
	2010		2009
	(In thousands)

Citrus	$	1,510,847		$	1,310,765
Other		27,701			29,283
	$	1,538,548		$	1,340,048

F-19

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following tables present the summarized financial information for the Company’s equity investments.

	December 31,
	2010					2009
			Other Equity						Other Equity
	Citrus		Investments			Citrus			Investments
	(In thousands)

Balance Sheet Data:
Current assets	$	107,108		$	14,106		$	365,414		$	13,855
Non-current assets		5,453,583			44,602			3,877,135			52,813
Current liabilities		316,952			2,139			529,136			7,722
Non-current liabilities		3,512,350			185			2,365,719			347

		Years Ended December 31,
	2010						2009						2008
				Other Equity						Other Equity						Other Equity
	Citrus			Investments			Citrus			Investments			Citrus			Investments
	(In thousands)
Statement of Operations Data:
Revenues		$	517,158		$	22,492		$	508,416		$	20,395		$	504,819		$	14,291
Operating income			269,789			12,323			271,897			13,765			275,245			3,019
Net earnings			180,927			12,273			129,683			13,680			126,942			1,850

Citrus

Dividends. Citrus did not pay dividends to the Company during the year ended December 31, 2010. During the year ended December 31, 2009, Citrus paid dividends of $77.2 million to the Company. Retained earnings at December 31, 2010 and 2009 included undistributed earnings from Citrus of $181.1 million and $81.5 million, respectively.

F-20

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 $649 million and $640 million as of December 31, 2010 and 2009, 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, 2010.

	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		67,741
Net investment in excess of underlying equity	$	649,085

_____________________

(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 2010, the Company and Citrus’ other shareholder 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. During the first half of 2011, it is expected Citrus will require additional sponsor provided contributions, which may be in the form of loans or equity contributions from each of its shareholders of up to $150 million. Citrus plans to resume cash distributions, which may be in the form of loan repayments or dividends, to its sponsors after the Phase VIII Expansion project is placed in service.

Florida Gas Rate Filing. Florida Gas filed a rate case with FERC on October 1, 2009, initially reflecting an annual cost of service of approximately $579 million. Pursuant to a FERC order on rehearing and Florida Gas' motion filing, on April 15, 2010, Florida Gas refiled its rates to be effective April 1, 2010 to remove the impact of certain estimated plant expenditures not in service by February 28, 2010, which reduced the annual cost of service originally filed by approximately $28 million to $551.6 million. Florida Gas, by comparison, has recorded actual revenues of approximately $511 million for the twelve-month period ended March 31, 2010 under its previously existing rates, including amounts collected from system expansions and certain surcharges. The new rates went into effect on April 1, 2010, subject to refund pending the final outcome of the rate proceeding.

F-21

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On September 3, 2010, Florida Gas filed a proposed settlement with FERC. The proposed 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. A $30.8 million provision for estimated refunds through December 31, 2010 has been established based on the proposed settlement rates and includes the impact of reduced depreciation rates effective April 1, 2010, which increased the provision for refund for the period ended December 31, 2010 by approximately $9.8 million. The proposed settlement was supported by all parties with the exception of one non-rate provision that was initially opposed by one party. The Administrative Law Judge certified the proposed settlement on December 21, 2010. In January 2011, the one opposing party withdrew its protest, making the settlement uncontested. The proposed settlement was approved by FERC on February 24, 2011.

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.

Citrus Construction Loan Agreement. On February 5, 2008, Citrus entered into a $500 million unsecured construction and term loan agreement (Construction Loan Agreement) with a wholly-owned subsidiary of FPL Group, Inc. Citrus invested the proceeds of this loan into Florida Gas primarily to finance a portion of the Phase VIII Expansion. The Construction Loan Agreement has a fixed interest rate of 9.393 percent.

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, 2010 were $21.7 million and $9.4 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, the jury awarded Florida Gas $82.7 million and rejected all damage claims by the FDOT/FTE. The judge has not ruled on issues associated with the width of the easement for the pipelines, permissible encroachments, and other matters including a request by the FDOT that the 18 inch pipeline in the FDOT/FTE right-of-way be replaced or reconditioned. In addition, the FDOT/FTE has filed a request for a new trial and a motion asking the Court to disregard the jury’s verdict and find in favor of the FDOT/FTE. Amounts ultimately received would primarily reduce Florida Gas’ property, plant and equipment costs.

F-22

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2010, Florida Gas had completed approximately 87 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.

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.

F-23

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

6. Accumulated Other Comprehensive Loss

The table below provides an overview of Comprehensive income (loss) for the periods presented.

	Years Ended December 31,
	2010			2009			2008
	(In thousands)
Net Earnings	$	224,548		$	179,580		$	295,151
Changes in Other Comprehensive Income (Loss):
Change in fair value of interest rate hedges, net of tax of $(5,237),
$(3,051) and $(8,436), respectively		(7,790	)		(4,538	)		(12,726	)
Reclassification of unrealized loss (gain) on interest rate hedges
into earnings, net of tax of $9,019, $8,222 and $(2,287), respectively		13,463			12,350			(3,268	)
Change in fair value of commodity hedges, net of tax of $14,093,
$3,773 and $13,549, respectively		25,012			6,696			24,045
Reclassification of unrealized (gain) loss on commodity hedges into
earnings, net of tax of $(6,787), $(16,231) and $(2,466), respectively		(12,046	)		(28,804	)		(4,375	)
Actuarial gain (loss) relating to pension and other postretirement
benefits, net of tax of $(4,472), $6,535 and $(23,763), respectively		(5,319	)		8,185			(41,784	)
Prior service cost relating to pension and other postretirement
benefit plan amendments, net of tax of $0, $(151) and $(3,691),
respectively		-			(186	)		(5,677	)
Reclassification of net actuarial loss and prior service credit
relating to pension and other postretirement benefits into
earnings, net of tax of $2,205, $2,814 and $2,034, respectively		2,886			4,035			2,865
Change in other comprehensive income (loss) from equity
investments, net of tax of $88, $(1,744) and $0, respectively		142			(2,820	)		-
Total other comprehensive income (loss)		16,348			(5,082	)		(40,920	)
Total comprehensive income	$	240,896		$	174,498		$	254,231

The table below provides an overview of the components in Accumulated other comprehensive loss as of the
dates indicated.

	December 31,
	2010			2009
	(In thousands)

Interest rate hedges, net	$	(17,232	)		$	(22,905	)
Commodity hedges, net		10,528				(2,438	)
Benefit plans:
Net actuarial loss and prior service costs, net - pensions		(32,982	)			(34,234	)
Net actuarial gain and prior service credit, net - other postretirement benefits		2,207				5,892
Equity investments, net		(2,678	)			(2,820	)
Total Accumulated other comprehensive loss, net of tax	$	(40,157	)		$	(56,505	)

F-24

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

7. Debt Obligations

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


	December 31, 2010				December 31, 2009
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)

Long-Term Debt Obligations:

Southern Union:
7.60% Senior Notes due 2024	$	359,765	$	392,144	$	359,765	$	389,820
8.25% Senior Notes due 2029		300,000		332,922		300,000		337,800
7.24% to 9.44% First Mortgage Bonds
due 2020 to 2027		19,500		21,473		19,500		21,403
6.089% Senior Notes due 2010		-		-		100,000		100,250
7.20% Junior Subordinated Notes due 2066 (1)		600,000		609,743		600,000		510,000
Term Loan due 2013 (2)		250,000		249,915		150,000		150,178
Note Payable		8,297		8,297		7,725		7,725
		1,537,562		1,614,494		1,536,990		1,517,176

Panhandle:
6.05% Senior Notes due 2013		250,000		268,988		250,000		269,733
6.20% Senior Notes due 2017		300,000		322,893		300,000		319,455
8.125% Senior Notes due 2019		150,000		169,671		150,000		173,111
8.25% Senior Notes due 2010		-		-		40,500		41,143
7.00% Senior Notes due 2029		66,305		69,911		66,305		69,866
7.00% Senior Notes due 2018		400,000		442,120		400,000		434,560
Term Loans due 2012		815,391		799,084		815,391		758,108
Net premiums on long-term debt		2,731		2,731		2,550		2,550
		1,984,427		2,075,398		2,024,746		2,068,526

Total Long-Term Debt Obligations		3,521,989		3,689,892		3,561,736		3,585,702

Credit Facilities		297,051		301,312		80,000		78,968

Total consolidated debt obligations		3,819,040	$	3,991,204		3,641,736	$	3,664,670
Less current portion of long-term debt		1,083				140,500
Less short-term debt		297,051				80,000
Total long-term debt	$	3,520,906			$	3,421,236

____________________

(1)	Effective November 1, 2011, the Company can elect to redeem this debt obligation at par. If the Company does not elect to redeem this debt obligation, the interest rate will change to a variable rate based upon the three-month LIBOR rate plus 3.0175 percent, reset quarterly.

(2)	As more fully described in the 2010 Term Loan discussion below, the term loan maturity date was extended to 2013.

F-25

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value of the Company’s term loans and credit facilities as of December 31, 2010 and 2009, and the Short-Term Facility as of December 31, 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 that type and size.

The fair value of the Company’s other long-term debt as of December 31, 2010 and 2009 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 $3.52 billion of long-term debt, including net premiums of $2.7 million, recorded at December 31, 2010, of which $1.1 million is current. Debt of $2.91 billion is at fixed rates ranging from 5.60 percent to 9.44 percent. Southern Union also has floating rate debt totaling $610.4 million, bearing an interest rate of 0.81 to 2.39 percent as of December 31, 2010.

As of December 31, 2010, the Company has scheduled long-term debt payments, excluding net premiums on debt, as follows:

															2016
	2011		2012			2013			2014			2015			and thereafter
	(In thousands)

Southern Union Company	$	1,083		$	825		$	250,797		$	772		$	751		$	1,283,334
Panhandle		-			815,391			250,000			-			-			916,305

Total	$	1,083		$	816,216		$	500,797		$	772		$	751		$	2,199,639

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.

8.125% Senior Notes. In June 2009, PEPL issued $150 million in senior notes due June 1, 2019 with an interest rate of 8.125 percent (8.125% Senior Notes). The proceeds were used to repay borrowings under the Company’s credit facilities and to repay the $60.6 million of 6.50% Senior Notes that matured on July 15, 2009.

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 2009 Term Loan. The 2009 Term Loan had an interest rate of LIBOR plus 3.75 percent. Proceeds received from the 2010 Term Loan were used to refinance the existing indebtedness under the 2009 Term Loan described above, with the remaining proceeds to be used to provide working capital and for general corporate purposes. The balance of the 2010 Term Loan was $250 million with an effective interest rate of 2.39 percent at December 31, 2010. The balance and effective interest rate of the 2010 Term Loan at February 18, 2011 were $250 million and 2.39 percent, respectively.

F-26

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 tied to 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 Term Loan was $455 million at December 31, 2010 and 2009. See Note 10 – Derivative Instruments and Hedging Activities – Interest Rate Swaps for information regarding interest rate swaps.

On December 1, 2006, LNG Holdings, as borrower, and PEPL and CrossCountry Citrus, LLC, as guarantors, entered into the $465 million 2006 Term Loan due April 4, 2008. 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 $360.4 million and $360.4 million at effective interest rates of 0.81 percent and 0.78 percent at December 31, 2010 and 2009, respectively. The balance and effective interest rate of the Amended Credit Agreement at February 18, 2011 were $360.4 million and 0.81 percent, respectively.

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

Balances of $297.1 million and $80 million were outstanding under the Company’s credit facilities at effective interest rates of 3.02 percent and 0.85 percent at December 31, 2010 and 2009, 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 18, 2011, there was a balance of $243.8 million outstanding under the Company’s credit facilities at an average effective interest rate of 3.03 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.

F-27

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 2010 Revolver, the consolidated debt to total capitalization ratio, as defined therein, cannot exceed 65 percent;

b)	Under the Company’s 2010 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

d)	All of the Company’s major borrowing agreements contain cross-defaults if the Company defaults on an agreement involving at least $2 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 repaid its $100 million 6.089% Senior Notes in February 2010 and $40.5 million 8.25% Senior Notes in April 2010 primarily using draw downs under its credit facilities.

8. 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.

F-28

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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,
	2010			2009			2010			2009
	(In thousands)

Change in benefit obligation:
Benefit obligation at beginning of period	$	177,235		$	172,063		$	98,055		$	91,119
Service cost		3,251			2,778			3,064			2,970
Interest cost		10,172			9,955			5,612			5,481
Benefits paid, net		(10,546	)		(10,089	)		(3,224	)		(2,611	)
Medicare Part D subsidy receipts		-			-			305			186
Actuarial loss and other		13,574			2,528			5,956			572
Plan amendments		-			-			-			338
Benefit obligation at end of period	$	193,686		$	177,235		$	109,768		$	98,055

Change in plan assets:
Fair value of plan assets at beginning of period	$	115,863		$	102,395		$	68,903		$	51,030
Return on plan assets and other		15,195			19,018			8,808			10,501
Employer contributions		6,488			4,539			27,659			9,983
Benefits paid, net		(10,546	)		(10,089	)		(3,224	)		(2,611	)
Fair value of plan assets at end of period	$	127,000		$	115,863		$	102,146		$	68,903

Amount underfunded at end of period	$	(66,686	)	$	(61,372	)	$	(7,622	)	$	(29,152	)

Amounts recognized in the Consolidated
Balance Sheet consist of:
Noncurrent assets	$	-		$	-		$	6,279		$	1,898
Current liabilities		(13	)		(13	)		(170	)		(79	)
Noncurrent liabilities		(66,673	)		(61,359	)		(13,731	)		(30,971	)
	$	(66,686	)	$	(61,372	)	$	(7,622	)	$	(29,152	)

Amounts recognized in Accumulated other
comprehensive loss (pre-tax basis) consist of:
Net actuarial loss (gain)	$	51,365		$	51,686		$	(246	)	$	(4,174	)
Prior service cost (credit)		2,551			3,104			1,074			(573	)
	$	53,916		$	54,790		$	828		$	(4,747	)

F-29

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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,
	2010			2009			2010			2009
	(In thousands)

Projected benefit obligation		$	193,686		$	177,235			N/A			N/A
Accumulated benefit obligation			183,529			169,564		$	82,287		$	94,442
Fair value of plan assets			127,000			115,863			68,385			63,392

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,
	2010			2009			2008			2010			2009			2008
	(In thousands)
Net Periodic Benefit Cost:
Service cost	$	3,251		$	2,778		$	2,596		$	3,064		$	2,970		$	2,525
Interest cost		10,172			9,955			9,972			5,612			5,481			5,415
Expected return on plan assets		(9,348	)		(8,577	)		(11,501	)		(4,918	)		(3,123	)		(3,246	)
Prior service cost (credit)
amortization		552			552			560			(1,647	)		(1,260	)		(1,521	)
Actuarial loss (gain)
amortization		8,048			8,405			6,867			(1,862	)		(847	)		(1,006	)
		12,675			13,113			8,494			249			3,221			2,167
Regulatory adjustment (1)		(4	)		54			2,728			2,665			2,665			2,665
Net periodic benefit cost	$	12,671		$	13,167		$	11,222		$	2,914		$	5,886		$	4,832

________________________________

(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 2011 are $7.9 million and $587,000, 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 2011 are $(1.6) million and $(1.8) million, respectively.

F-30

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,
	2010			2009			2010			2009
Discount rate		5.35	%		5.82	%		5.36	%		5.85	%
Rate of compensation increase		3.02	%		3.24	%		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,
	2010			2009			2008			2010			2009			2008
Discount rate		5.82	%		6.05	%		6.24	%		5.85	%		6.05	%		6.52	%
Expected return on assets:
Tax exempt accounts		8.25	%		8.50	%		8.75	%		7.00	%		7.00	%		7.00	%
Taxable accounts		N/A			N/A			N/A			5.00	%		5.00	%		5.00	%
Rate of compensation increase		3.24	%		3.24	%		3.47	%		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 for measurement purposes with respect to the Company’s other postretirement benefit plans are shown in the table below.

	December 31,
	2010			2009

Health care cost trend rate assumed for next year		9.00	%		8.50	%
Ultimate trend rate		4.75	%		4.85	%
Year that the rate reaches the ultimate trend rate		2019			2017

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		$	879		$	(824	)
Effect on accumulated postretirement benefit obligation			10,480			(9,378	)

F-31

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 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		$	-


	Fair Value				Fair Value Measurements at December 31, 2009
	as of				Using Fair Value Hierarchy
	December 31, 2009				Level 1			Level 2			Level 3
		(In thousands)
Asset Category:
Cash and cash
equivalents		$	9,726			$	9,726		$	-		$	-
Mutual fund			96,514	(1)			-			96,514			-
Multi-strategy
hedge funds			9,623	(2)			-			9,623			-
Total		$	115,863			$	9,726		$	106,137		$	-

___________________

(1)

This comingled fund invests primarily in a diversified portfolio of equity and fixed income funds. 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. As of December 31, 2009, the fund was primarily comprised of approximately 30 percent large-cap U.S. equities, 9 percent multi-cap U.S. equities, 5 percent small-cap U.S. equities, 20 percent international equities, 30 percent fixed income securities, 3 percent cash, and 3 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.

F-32

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 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		$	-		$	-


		Fair Value			Fair Value Measurements at December 31, 2009
		as of			Using Fair Value Hierarchy
	December 31, 2009				Level 1			Level 2			Level 3

		(In thousands)
Asset Category:
Cash and Cash
Equivalents		$	2,172			$	2,172		$	-		$	-
Mutual fund			66,731	(1)			66,731			-			-
Total		$	68,903			$	68,903		$	-		$	-

___________________

(1)

This fund of funds primarily invests in a combination of equity, fixed income and short-term mutual funds. 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. As of December 31, 2009, the fund was primarily comprised of approximately 16 percent large-cap U.S. equities, 3 percent small-cap U.S. equities,10 percent international equities, 57 percent fixed income securities, 10 percent cash, and 4 percent in other investments.

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

In 2010, the Company made a one-time $16.4 million catch-up contribution to Missouri Gas Energy’s other postretirement benefit plan in accordance with its approved rate case effective February 28, 2010. The Company expects to contribute approximately $14.2 million to its pension plans and approximately $10.7 million to its other postretirement plans in 2011. The Company funds the cost of the plans in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.

F-33

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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)
2011		$	11,044		$	4,372		$	614
2012			11,715			5,031			653
2013			11,860			5,788			719
2014			12,308			6,623			820
2015			12,096			7,391			945
2016 - 2020			65,174			45,414			5,826

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.

Health Care Reform

In March 2010, the Patient Protection and Affordable Care Act and the Health Care Education and Affordability Reconciliation Act (the Acts) were signed into law. The Acts contain provisions that could impact the Company’s retiree medical benefits in future periods. However, the extent of that impact, if any, cannot be determined until additional interpretations of the Acts become available. Based on the analysis to date, the impact of provisions in the Acts that are reasonably determinable is not expected to have a material impact on the Company’s other postretirement benefit plans. Accordingly, a remeasurement of the Company’s postretirement benefit obligation is not required at this time. The Company will continue to assess the provisions of the Acts and may consider plan amendments in future periods to better align these plans with the provisions of the Acts.

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 2008 through 2010 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, 2010, 2009 and 2008 were $7.4 million, $7 million and $5.2 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, 2010, 2009 and 2008 were $7.9 million, $7.9 million and $7.4 million, respectively.

F-34

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

9. 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,
	2010		2009		2008
				(In thousands)
Current:
Federal	$	1,963	$	(44,060)	$	22,267
State		(2,352)		(5,250)		(558)
		(389)		(49,310)		21,709

Deferred:
Federal		93,330		108,956		68,370
State		14,088		12,254		14,696
		107,418		121,210		83,066

Total federal and state income tax
expense from continuing operations	$	107,029	$	71,900	$	104,775

Effective tax rate		31%		29%		26%

F-35

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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,
	2010			2009
	(In thousands)
Deferred income tax assets:
Alternative minimum tax credit	$	36,526		$	27,894
Other postretirement benefits		20,206			31,159
Pension benefits		23,491			16,162
Derivative financial instruments (interest rates)		13,571			16,152
Derivative financial instruments (commodities)		4,836			19,114
Other		34,409			38,541
Total deferred income tax assets		133,039			149,022

Deferred income tax liabilities:
Property, plant and equipment		(1,032,473	)		(929,424	)
Unconsolidated investments (Citrus)		(19,177	)		(11,640	)
Goodwill		(16,952	)		(18,249	)
Environmental reserve		(9,374	)		(13,844	)
Other		(32,296	)		(39,611	)
Total deferred income tax liabilities		(1,110,272	)		(1,012,768	)
Net deferred income tax liability		(977,233	)		(863,746	)
Less current income tax assets (liabilities)		36,630			41,841
Accumulated deferred income taxes	$	(1,013,863	)	$	(905,587	)

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,
	2010			2009			2008
	(In thousands)

Computed statutory income tax expense at 35%	$	122,387		$	88,018		$	139,974
Changes in income taxes resulting from:
Dividends received deduction		-			-			(24,142	)
Reduction in deferred tax liability related to
unconsolidated investments		-			-			(20,720	)
Earnings from unconsolidated investments related to
anticipated receipt of dividends		(26,973	)		(20,300	)		-
State income taxes, net of federal income tax benefit		7,878			4,553			9,190
Other		3,737			(371	)		473
Actual income tax expense from continuing operations	$	107,029		$	71,900		$	104,775

Income tax expense in 2008 includes a benefit of $20.7 million resulting from a reduction in the Company’s deferred income tax liability in 2008 associated with the dividends received deduction for anticipated dividends from the Company’s unconsolidated investment in Citrus. Due to the anticipated increase in dividends from Citrus after the completion 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.

F-36

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

	Years ended December 31,
	2010			2009		2008
	(In thousands)

Beginning of the year	$	12,864		$	7,210	$	570

Additions:
Tax positions taken in prior years		-			2,195		4,427
Tax positions taken in current year		3,146			3,459		2,783

Reductions:
Settlements		(173	)		-		-
Lapse of statute of limitations		-			-		(570	)
End of year	$	15,837		$	12,864	$	7,210

As of December 31, 2010, the Company has unrecognized tax benefits for capitalization policies and state filing positions of $2.3 million and $13.5 million, respectively. However, only the $13.5 million ($8.8 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 $791,000 ($514,000, 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 2010, the Company recognized interest and penalties of $779,000 ($702,000, net of tax). At December 31, 2010, the Company has interest and penalties accrued of $1.4 million ($1.1 million, net of tax).

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.

10. 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 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.

F-37

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Interest Rate Contracts

The Company enters 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 enters 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. As of December 31, 2010, the Company had outstanding pay-fixed interest rate swaps with a total notional amount of $455 million applicable to the LNG Holdings $455 million term loan issued in 2007. 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, 2010, approximately $11.8 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. Any ineffective portion of the cash flow hedge is reported in current-period earnings.

Treasury Rate Locks. As of December 31, 2010, 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, 2010, 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.

Commodity Contracts – Gathering and Processing Segment

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

Natural Gas Price Swaps. As of December 31, 2010, the Company had outstanding receive-fixed natural gas price swaps with a total notional amount of 9,125,000 MMBtus for 2011. 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, 2010, approximately $10.5 million of net after-tax gains in Accumulated other comprehensive loss related to these natural gas price swaps is 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 Processing Spread Swaps. As of December 31, 2010, the Company had outstanding receive-fixed NGL processing spread swaps with a total notional amount of 9,125,000 MMBtu equivalents for 2011. These processing spread swaps are accounted for as economic hedges, with changes in their fair value recorded in Operating revenues.

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.

F-38

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Natural Gas Price Swaps. As of December 31, 2010, the Company had outstanding pay-fixed natural gas price swaps with total notional amounts of 20,910,000 MMBtus and 10,130,000 MMBtus for 2011 and 2012, respectively. These natural gas price swaps are accounted for as economic hedges, with changes in their fair value recorded to Deferred natural gas purchases.

Summary Financial Statement Information

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

	Fair Value (1)
	December 31,
Balance Sheet Location	2010		2009
	(In thousands)
Cash Flow Hedges:
Commodity contracts - Gathering and Processing:
Natural gas price swaps
Derivative instruments-liabilities	$	16,459	$	-
Deferred credits		-		314
	$	16,459	$	314
Economic Hedges:
Commodity contracts - Gathering and Processing:
Other derivative instruments
Prepayments and other assets	$	133	$	167
Derivative instruments-liabilities		-		166
Commodity contracts - Distribution:
Natural gas price swaps
Derivative instruments-liabilities		234		582
Deferred credits		105		15
	$	472	$	930

Total	$	16,931	$	1,244

_____________

(1)	See Note 11 – Fair Value Measurement for information related to the framework used by the Company to measure the fair value of its derivative instruments as of December 31, 2010.

F-39

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

	Fair Value (1)
	December 31,
Balance Sheet Location	2010		2009
	(In thousands)
Cash Flow Hedges:
Interest rate contracts
Derivative instruments-liabilities	$	19,694	$	18,754
Deferred credits		4,652		13,975
Commodity contracts - Gathering and Processing:
Natural gas price swaps
Derivative instruments-liabilities		-		4,126
	$	24,346	$	36,855
Economic Hedges:
Commodity contracts - Gathering and Processing:
NGL processing spread swaps
Derivative instruments-liabilities	$	29,057	$	34,477
Deferred credits		-		10,410
Other derivative instruments
Prepayments and other assets		-		30
Derivative instruments-liabilities		-		193

Commodity contracts - Distribution:
Natural gas price swaps
Derivative instruments-liabilities		34,968		40,206
Deferred credits		2,806		3,991
	$	66,831	$	89,307

Total	$	91,177	$	126,162

_____________

(1)	See Note 11 – Fair Value Measurement for information related to the framework used by the Company to measure the fair value of its derivative instruments as of December 31, 2010.

F-40

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,
	2010			2009			2008
	(In thousands)
Cash Flow Hedges: (1)
Interest rate contracts:
Change in fair value - increase in Accumulated other comprehensive
loss, excluding tax expense effect of $5,237, $3,051 and $8,436, respectively	$	13,028		$	7,589		$	21,162
Reclassification of unrealized gain (loss) from Accumulated other
comprehensive loss - decrease (increase) of Interest expense, excluding tax
expense effect of $(9,019), $(8,222) and $2,287, respectively		(22,483	)		(20,572	)		5,555
Commodity contracts - Gathering and Processing:
Change in fair value - increase/(decrease) in Accumulated other comprehensive
loss, excluding tax expense effect of $(14,093), $(3,773) and $(13,549),
respectively		(39,105	)		(10,469	)		(37,594	)
Reclassification of unrealized gain from Accumulated other comprehensive
loss - increase of Operating revenues, excluding tax expense effect of $6,787,
$16,231 and $2,466, respectively		18,833			45,035			6,841

Economic Hedges:
Commodity contracts - Gathering and Processing:
Change in fair value - (increase)/decrease in Operating revenues (2)		31,437			88,787			(49,399	)
Commodity contracts - Distribution:
Change in fair value - increase/(decrease) in Deferred gas purchases		(6,166	)		(49,083	)		70,335

_________________

(1)	See Note 6 – Accumulated Other Comprehensive Loss for additional related information.

(2)

Includes $34.5 million, $59.7 million and nil of the cash settlement impact for previously recognized unrealized losses in the year ended December 31, 2010 and unrealized gains in the years ended December 31, 2009 and 2008, respectively. Additionally, includes $18.6 million, $44.9 million and $59.7 million of unrealized mark-to-market losses recorded in the years ended December 31, 2010 and 2009 and unrealized mark-to-market gains recorded in the year ended December 31, 2008, 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, 2010 was $29.7 million.

F-41

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

11. 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, 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		$	-



	Fair Value			Fair Value Measurements at December 31, 2009
	as of			Using Fair Value Hierarchy
	December 31, 2009			Level 1			Level 2			Level 3

	(In thousands)
Assets:
Commodity derivatives		$	137		$	-		$	137		$	-
Long-term investments			867			867			-			-
Total		$	1,004		$	867		$	137		$	-

Liabilities:
Commodity derivatives		$	92,326		$	171		$	92,155		$	-
Interest-rate swap derivatives			32,729			-			32,729			-
Total		$	125,055		$	171		$	124,884		$	-

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 processing spread swap derivatives and interest-rate swap derivatives that are valued based on pricing models where significant inputs are observable. The Company reclassified certain of its processing spread swap derivatives and interest-rate swap derivatives from Level 3 to Level 2 during 2009 as it obtained additional observable market data to corroborate all significant inputs to the models used to measure the fair value of these liabilities.

F-42

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table provides a reconciliation of the change in the Company’s Level 3 assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs for the periods presented.

	Level 3 Financial Assets and Liabilities
	Assets				Liabilities
	Commodity				Commodity				Interest-rate
	Derivatives				Derivatives				Derivatives
	(In thousands)

Balance at January 1, 2009		$	964			$	(94	)		$	43,630
Total gains or losses (realized and unrealized):
Included in operating revenues (1)			290				61				-
Included in other comprehensive income			-				-				4,787
Purchases and settlements, net			-				(206	)			(12,696	)
Transfers out of Level 3			(1,254	)			239				(35,721	)
Balance at December 31, 2009		$	-			$	-			$	-

___________________

(1)	The amounts included in operating revenues for the year ended December 31, 2009 attributable to the change in unrealized gains or losses relating to commodity derivative assets and commodity derivative liabilities held at December 31, 2009 were gains of $725,000 and $221,000, respectively.

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

F-43

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

12. 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)		2010 (2)		2009 (2)
			(In thousands)
Regulated Operations:
Distribution plant		30-60	$	1,001,032	$	974,116
Gathering and processing plant		26		183,548		188,927
Transmission plant		5-46		2,239,762		2,130,978
General - LNG		5-40		1,117,418		626,853
Underground storage plant		5-46		314,744		310,963
General plant and other		2-50		283,737		276,422
Construction work in progress				52,800		499,435
				5,193,041		5,007,694
Less accumulated depreciation and amortization				1,074,161		926,811
				4,118,880		4,080,883
Non-regulated Operations:
Distribution plant		5-40		59,749		54,637
Gathering and processing plant		1-50		1,740,725		1,685,960
General plant and other		3-15		17,274		11,333
Construction work in progress				67,464		32,275
				1,885,212		1,784,205
Less accumulated depreciation and amortization				299,633		235,875
				1,585,579		1,548,330
Net property, plant and equipment			$	5,704,459	$	5,629,213

_________________

(1)	The composite weighted-average depreciation rates for the years ended December 31, 2010, 2009 and 2008 were 3.5 percent, 3.5 percent and 3.5 percent, respectively.

(2)	Includes capitalized computerized software cost totaling:

Unamortized computer software cost	$	131,182	$	125,495
Less accumulated amortization		79,637		70,238
Net capitalized computer software costs	$	51,545	$	55,257

Amortization expense of capitalized computer software costs for the years ended December 31, 2010, 2009 and 2008 was $11.4 million, $13.1 million and $12.1 million, respectively. Computer software costs are amortized between one and fifteen years.

13. 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 share-based compensation expense in future periods. Additionally, the expected dividend yield is considered for each grant on the date of grant. The Company’s expected term of stock options and SARs granted was derived from the average midpoint between vesting and the contractual term. 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.

F-44

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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,
	2010	2009	2008

Expected volatility	32.79% to 34.98%	32.22% to 33.69%		30.57%
Expected dividend yield	2.45% to 2.47%	2.37% to 2.45%		2.19%
Risk-free interest rate	1.78% to 2.40%	2.34% to 2.72%		1.71%
Expected life	4.75 to 6 years	4.75 to 6 years	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, 2007	1,531,675	$	24.74	536,702	$	13.28
Granted	792,934		12.55	-		-
Exercised	(12,725)		16.83	(224,593)		12.71
Forfeited	(773)		16.83	-		-
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

Exercisable December 31, 2008	769,216		22.66	312,109		13.70
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

F-45

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes information about stock options outstanding under the Third Amended 2003 Plan and the 1992 Plan at December 31, 2010.



		Options Outstanding				Options Exercisable
			Weighted-Average Remaining Contractual Life	Weighted-Average Exercise Price			Weighted-Average Exercise Price

Range of Exercise Prices		Number of Options				Number of Options

Third Amended 2003 Plan:
	12.55 - 15.00	792,934	7.96 years	$	12.55	528,622	$	12.55
	15.01 - 20.00	278,696	5.08 years		16.88	278,696		16.88
	20.01 - 25.00	1,731,563	7.99 years		23.29	731,592		22.96
	25.01 - 28.48	793,678	7.19 years		28.20	275,629		28.48
		3,596,871	7.58 years	$	21.51	1,814,539	$	19.83

1992 Plan:
	14.65	39,159	0.42 years	$	14.65	39,159	$	14.65
		39,159	0.42 years	$	14.65	39,159	$	14.65

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, 2007		415,773		$	28.35
Granted		784,779			12.55
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

Exercisable December 31, 2008		183,115			28.28
Exercisable December 31, 2009		494,775			22.06
Exercisable December 31, 2010		900,965			20.53

F-46

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

The following table summarizes information about SARs outstanding under the Third Amended 2003 Plan at December 31, 2010.

		SARs Outstanding				SARs Exercisable
			Weighted-Average Remaining Contractual Life	Weighted-Average Exercise Price			Weighted-Average Exercise Price
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	629,903	7.96 years	$	12.55	389,705	$	12.55
	17.51 - 25.00	775,269	9.42 years		23.11	132,476		21.64
	25.01 - 28.48	378,784	6.65 years		28.35	378,784		28.35
		1,783,956	8.32 years	$	20.50	900,965	$	20.53

The weighted-average remaining contractual life of options and SARs outstanding under the Third Amended 2003 Plan and the 1992 Plan at December 31, 2010 was 7.83 and 0.42 years, respectively. The weighted-average remaining contractual life of options and SARs exercisable under the Third Amended 2003 Plan and the 1992 Plan at December 31, 2010 was 6.86 and 0.42 years, respectively. The aggregate intrinsic value of total options and SARs outstanding and exercisable at December 31, 2010 was $21.6 million and $14.1 million, respectively.

As of December 31, 2010, there was $13.2 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 2.31 years. The total fair value of options and SARs vested as of December 31, 2010 was $16.9 million. Compensation expense recognized related to stock options and SARs totaled $6.3 million ($4.0 million, net of tax), $5.4 million ($3.5 million, net of tax) and $3.9 million ($2.7 million, net of tax) for the years ended December 31, 2010, 2009 and 2008, respectively. Cash received from the exercise of stock options was $1.9 million for the year ended December 31, 2010.

The intrinsic value of options and SARs exercised during the year ended December 31, 2010 was approximately $581,000. The Company realized an additional tax benefit of approximately $276,000 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.

F-47

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2007		201,170		$	28.00
Granted		252,066			14.99
Released		(90,051	)		28.10
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

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, 2007		213,302		$	28.35
Granted		418,583			13.88
Released		(82,431	)		28.31
Forfeited		(815	)		28.48
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

As of December 31, 2010, there was $16.3 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 2.13 years. The total fair value of restricted stock equity and liability units that were released during the year ended December 31, 2010 was $8.4 million. Compensation expense recognized related to restricted stock equity and liability units totaled $8.8 million ($5.5 million, net of tax), $6.8 million ($4.3 million, net of tax) and $3.7 million ($2.3 million, net of tax) for the years ended December 31, 2010, 2009 and 2008, respectively.

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

F-48

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

14. Commitments and Contingencies

Environmental

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

The Company is allowed to recover environmental remediation expenditures through rates in certain jurisdictions within its Distribution segment. Although significant charges to earnings could be required prior to rate recovery for jurisdictions that do not have rate recovery mechanisms, management does not believe that environmental expenditures will have a material adverse effect on the Company's consolidated financial position, results of operations or cash flows.

The table below reflects the amount of accrued liabilities recorded in the Consolidated Balance Sheet at the dates indicated to cover probable environmental response actions.

	December 31,
	2010			2009
	(In thousands)

Current		$	10,648		$	7,745
Noncurrent			11,920			16,964
Total environmental liabilities		$	22,568		$	24,709

During the years ended December 31, 2010, 2009 and 2008, the Company had $4.5 million, $12 million and $12 million of expenditures related to environmental cleanup programs, respectively.

SPCC Rules. In October 2007, the EPA proposed amendments to the SPCC rules with the stated intention of providing greater clarity, tailoring requirements and streamlining requirements. On October 7, 2010, EPA amended the compliance date for certain facilities from November 10, 2010 to November 10, 2011. The Company is currently reviewing the impact of the modified regulations on its operations in its Transportation and Storage and Gathering and Processing segments and may incur costs for tank integrity testing, alarms and other associated corrective actions as well as potential upgrades to containment structures. Costs associated with such activities cannot be estimated with certainty at this time, but the Company believes such costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

F-49

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Air Quality Control. In August 2010, 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. EPA lowered the ozone standard to seventy-five parts per billion (ppb) in 2008 with compliance anticipated in 2013 to 2015. In January 2010, 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 January 2010, 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 network 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 impact of the August 2010 Area Source National Emissions Standards for Hazardous Air Pollutants rule and proposed rules regarding HAPs and ozone 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. Costs associated with these activities cannot be estimated with any certainty at this time, but the Company believes such costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Transportation and Storage Segment Environmental Matters

Natural Gas Transmission Systems. 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 developed and 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. The Company believes the total PCB remediation costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

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 believes the outcome of these matters will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Air Quality Control. The Kansas Department of Health and Environment set certain contingency measures as part of the agency’s ozone maintenance plan for the Kansas City area. These measures must be revised to conform to the requirements of the EPA ozone standard discussed above. As such, the costs associated with these activities cannot be estimated with any certainty at this time, but the Company believes such costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

F-50

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On December 18, 2009, PEPL received an information request from the EPA under Section 114(a) of the Federal Clean Air Act. The information request sought certain documents and records pertaining to maintenance activities and capital projects associated with combustion emission sources located at eight compressor stations in Illinois and Indiana. The complete responses were provided in February 2010.

Gathering and Processing Segment Environmental Matters

Gathering and Processing Systems. 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. The Company believes the outcome of these matters will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Air Quality Control. SUGS is currently negotiating settlements to certain enforcement actions by the NMED and the TCEQ. The Company believes the outcome of these matters will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Distribution Segment Environmental Matters

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. The Company believes the outcome of these matters will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

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 continue at the remaining areas on-site and at the off-site properties. It is estimated that the Company will spend approximately $9.6 million over the next several years to complete the investigation and 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.

F-51

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Litigation

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, some of which involve substantial amounts. Where appropriate, the Company has established reserves in order to provide for such matters. The Company believes the final disposition of these proceedings will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Mercury Release. In October 2004, New England Gas Company discovered that one of its facilities, formerly associated with discontinued operations which were sold in 2006, had been broken into and that mercury had been released both inside a building and in the immediate vicinity, including a parking lot in a neighborhood several blocks away. Mercury from the parking lot was apparently tracked into nearby apartment units, as well as other buildings. Cleanup was completed at the property and nearby apartment units. The vandals who broke into the facility were arrested and convicted. In October 2007, the U.S. Attorney in Rhode Island filed a three-count indictment against the Company in the U.S. District Court for the District of Rhode Island (District Court) alleging violation of permitting requirements under the federal RCRA and notification requirements under the 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 Court stayed the payment of the fine and community service amounts while the Company pursued an appeal of the conviction and sentence to the United States Court of Appeals for the First Circuit (First Circuit).

On December 22, 2010, a 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. The Company now intends to petition for a writ of certiorari review by the United States Supreme Court. The Government has agreed to stay enforcement of the sentence, including payment of the fine and community service, pending resolution of the Company's petition to the United States Supreme Court.

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. In its petition for rehearing “en banc” by the full First Circuit, the Company argued that the conviction violated the Company’s due process rights, and that the sentence, which went beyond the fine authorized by the jury’s verdict, violated the Company’s jury trial rights under the Sixth Amendment, and is contrary to current Supreme Court precedent and the decisions of two other federal circuits.

In light of the First Circuit's decisions, the Company recorded a charge to earnings of approximately $18.1 million 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, resulting in a reduction in the Company's basic and fully diluted EPS for 2010 of $0.14 and $0.14, respectively.

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 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 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 does not believe the outcome of the Will Price litigation will have a material adverse effect on its consolidated financial position, results of operations or cash flows.

F-52

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 is seeking 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 have filed counterclaims against PEPL for alleged underpayments of approximately $18 million. The matter is pending in state court in Harris County, Texas.

The trial date is currently set for May 2011. The Company does not believe the outcome of this case will have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Other Commitments and Contingencies

Retirement of Debt Obligations. See Note 7 – Debt Obligations – Retirement of Debt Obligations for information related to the Company’s debt maturing in 2011.

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. In late July 2009, during testing to put the remaining offshore facilities back in service, Sea Robin experienced a pipeline rupture in an area where the pipeline had previously been displaced during Hurricane Ike and subsequently re-buried. Sea Robin experienced reduced volumes until January 2010 when the remainder of the damaged facilities was placed back in service.

In 2010, the Company recorded a reduction in Hurricane Ike related expenses of approximately $8.1 million and insurance recoveries of $4.1 million. The Company had previously recorded Hurricane Ike related expenses of approximately $12.3 million and $10.5 million, and insurance recoveries of $2.1 million and nil, in 2009 and 2008, respectively. The capital replacement and retirement expenditure estimates relating to Hurricane Ike have been reduced from $185 million to approximately $150 million and are expected to be completed in 2011. Approximately $134 million, $110 million and $23 million of the capital replacement and retirement expenditures were incurred as of December 31, 2010, 2009 and 2008, 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. The Company received a total of $25.8 million and $36.7 million in 2010 and 2009, respectively, for claims submitted to date 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.

F-53

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Purchase Commitments. At December 31, 2010, the Company had purchase commitments for natural gas transportation services, storage services and certain quantities of natural gas at a combination of fixed, variable and market-based prices that have an aggregate value of approximately $652 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 $13.6 million in 2010 related to this program and estimates incurring approximately $104.9 million over the next 10 years, after which all service lines, representing about 39 percent of the annual safety program investment, will have been replaced.

Regulation and Rates. See Note 18 – Regulation and Rates for potential contingent matters associated with the Company’s regulated operations.

15. Stockholders’ Equity

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

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

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

December 26, 2008	January 9, 2009	$	0.15	$	18,600
September 26, 2008	October 10, 2008		0.15		18,597
June 27, 2008	July 11, 2008		0.15		18,595
March 28, 2008	April 11, 2008		0.15		18,592

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

F-54

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 maintains 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 are exercisable for ten years from the date of grant or such lesser period as may be designated for particular options, and became exercisable after a specified period of time from the date of grant in cumulative annual installments.

For more information on share-based awards, see Note 13 – Stock-Based Compensation.

16. Preferred Securities

On October 8, 2003, the Company issued 9,200,000 depositary shares, each representing a 1/10th interest in a share of its 7.55% Noncumulative Preferred Stock, Series A (Liquidation Preference $250 Per Share) (Preferred Stock), at the public offering price of $25 per share, or $230 million in the aggregate.

On May 22, 2008, the Company announced that the finance committee of its Board had authorized a program to repurchase a portion of the depositary shares representing ownership of its Preferred Stock at the Company’s discretion in the open market and/or through privately negotiated transactions, subject to market conditions, applicable legal requirements and other factors. During the year ended December 31, 2008, the Company paid $115.2 million to repurchase 4,599,987 depository shares representing 459,999 shares of Preferred Stock, resulting in a $3.5 million non-cash loss adjustment charged to Retained earnings related to the write-off of issuance costs, which reduced Net earnings available for common stockholders.

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.

17. Reportable Segments

The Company’s reportable business segments are organized based on the way internal managerial reporting presents the results of the Company’s various businesses to its executive management for use in determining the performance of the businesses and in allocating resources to the businesses, as well as based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment. The Company operates in three reportable segments: Transportation and Storage, Gathering and Processing, and Distribution.

F-55

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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;

·	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, 2010, 2009 and 2008.

F-56

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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,
			2010		2009		2008
			(In thousands)
Operating revenues from external customers:
	Transportation and Storage		$	769,450	$	749,161	$	721,640
	Gathering and Processing			1,008,023		732,251		1,521,041
	Distribution			698,513		692,904		821,673
		Total segment operating revenues		2,475,986		2,174,316		3,064,354
	Corporate and other activities			13,927		4,702		5,800
			$	2,489,913	$	2,179,018	$	3,070,154

Depreciation and amortization:
	Transportation and Storage		$	123,009	$	113,648	$	103,807
	Gathering and Processing			70,056		66,690		62,716
	Distribution			32,544		31,269		30,530
		Total segment depreciation and amortization		225,609		211,607		197,053
	Corporate and other activities			3,028		2,220		2,196
			$	228,637	$	213,827	$	199,249

Earnings (loss) from unconsolidated investments:
	Transportation and Storage		$	99,991	$	75,205	$	75,173
	Gathering and Processing			4,145		4,410		(990)
	Corporate and other activities			1,279		1,175		847
			$	105,415	$	80,790	$	75,030

Other income (expense), net:
	Transportation and Storage		$	(87)	$	1,657	$	1,951
	Gathering and Processing			362		(84)		104
	Distribution			(307)		7,447		(1,830)
		Total segment other income (expense), net		(32)		9,020		225
	Corporate and other activities			344		12,381		2,100
			$	312	$	21,401	$	2,325

			Years Ended December 31,
			2010		2009		2008

			(In thousands)
Segment performance:
	Transportation and Storage EBIT		$	458,273	$	411,935	$	404,834
	Gathering and Processing EBIT			41,756		(40,470)		145,363
	Distribution EBIT			63,692		67,302		61,418
		Total segment EBIT		563,721		438,767		611,615
	Corporate and other activities			2,621		9,513		(4,281)
	Interest expense			216,665		196,800		207,408
	Federal and state income taxes			107,029		71,900		104,775
	Loss from discontinued operations			18,100		-		-
	Net earnings			224,548		179,580		295,151
	Preferred stock dividends			5,040		8,683		12,212
	Loss on extinguishment of preferred stock			3,295		-		3,527
		Net earnings available for common stockholders	$	216,213	$	170,897	$	279,412



			December 31,
			2010		2009

			(In thousands)
Total assets:
	Transportation and Storage		$	5,224,992	$	5,138,042
	Gathering and Processing			1,700,598		1,666,935
	Distribution			1,135,352		1,109,492
		Total segment assets		8,060,942		7,914,469
	Corporate and other activities			177,601		160,605
	Total assets		$	8,238,543	$	8,075,074


			Years Ended December 31,
			2010		2009		2008

			(In thousands)
Expenditures for long-lived assets:
	Transportation and Storage		$	145,674	$	247,097	$	434,004
	Gathering and Processing			95,577		70,221		67,317
	Distribution			41,484		46,090		41,125
		Total segment expenditures for long-lived assets		282,735		363,408		542,446
	Corporate and other activities			4,690		30,141		9,345
		Total expenditures for long-lived assets (1)	$	287,425	$	393,549	$	551,791

_______________________

(1)	Related cash impact includes the net reduction in capital accruals totaling $9.5 million, $22 million and $21.9 million for the years ended December 31, 2010, 2009 and 2008, respectively.

F-57

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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,
	2010		2009		2008		2010		2009		2008

BG LNG Services	29	%	22	%	23	%	9	%	8	%	6	%
ProLiance	13		13		12		4		4		3
Other top 10 customers	23		26		26		7		9		7
Remaining customers	35		39		39		11		13		9
Total percentage	100	%	100	%	100	%	31	%	34	%	25	%

	Percent of Gathering and						Percent of Consolidated
	Processing Segment Revenues						Company Total Operating Revenues
	Years Ended December 31,						Years Ended December 31,
	2010		2009		2008		2010		2009		2008

ConocoPhillips Company	54	%	7	%	8	%	22	%	2	%	4	%
Louis Dreyfus Energy Services, LP	12		12		11		5		4		6
Other top 10 customers	24		48		41		10		17		20
Remaining customers	10		33		40		5		12		17
Total percentage	100	%	100	%	100	%	42	%	35	%	47	%

_____________

(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.

18. 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, will be 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, with initial accumulated net costs of approximately $38 million included in the filing. 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. On August 31, 2010, Sea Robin submitted its semiannual filing related to the surcharge which reflected updated costs incurred of approximately $46 million, net of insurance and surcharge recoveries, which were reflected in the updated surcharge rate effective October 1, 2010, subject to refund. The Administrative Law Judge issued an initial decision on December 13, 2010, approving the surcharge for recovery from all shippers, including discounted and non-discounted shippers, over a recovery period of 21.4 years and including applicable carrying charges. The Company, as well as other parties, have filed briefs for exception on certain aspects of the decision. The ultimate outcome of this matter is pending a final FERC decision.

F-58

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2010, the Company had completed approximately 90 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 $10 million to $20 million per year through 2012.

Missouri Gas Energy. 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 not expected to be complete until 2011, and the results of those judicial review 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 16, 2010, New England Gas Company made a filing with the MDPU seeking to implement an annual base rate increase of approximately $6.2 million. The filing includes a proposed implementation of a revenue decoupling mechanism, which mitigates conservation and weather impacts. The filing also includes a proposed Targeted Infrastructure Replacement Factor, which will permit recovery of capital costs associated with certain aged facilities without the requirement to make a filing with the MDPU to request an increase in the annual base rate. New rates are expected to become effective April 1, 2011. On October 8, 2010, the MDPU issued an order seeking comments as to the appropriateness of dismissing New England Gas Company’s pending rate case filing as a result of certain concerns related to a MDPU required audit of New England Gas Company for 2007. The MDPU has not made a ruling with regard to the potential dismissal of New England Gas Company’s pending rate case filing. New England Gas Company believes that neither the facts nor the law support or permit the issuance of a dismissal order and would, in the event of its issuance, vigorously contest any such dismissal order.

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 February 17, 2009. 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.

F-59

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

19. 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: 2011—$17.8 million; 2012— $12.9 million; 2013—$15.5 million; 2014— $14.7 million; 2015—$13.6 million; and $79.8 million in total thereafter. Rental expense was $20.1 million, $22.7 million and $19.2 million for the years ended December 31, 2010, 2009 and 2008, respectively.

20. Asset Retirement Obligations

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

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

The following table is a general description of ARO and associated long-lived assets at December 31, 2010.

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

Retire offshore platforms and lines	Various	Offshore lines		$	15,114
Other	Various	Mainlines, compressors and gathering plants		$	4,941

As of December 31, 2010, the Company has recorded $159,000 that is legally restricted for the purpose of settling AROs.

F-60

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table is a reconciliation of the carrying amount of the ARO liability for the periods presented.

	Years Ended December 31,
	2010			2009				2008
	(In thousands)

Beginning balance	$	61,667			$	51,641			$	12,762
Incurred		29,872				10,770				33,773
Revisions		(11,395	)			(3,246	)			6,379
Settled		(19,858	)			(1,557	)			(2,141	)
Accretion expense		994				4,059				868
Ending balance	$	61,280			$	61,667			$	51,641

In 2010, additional AROs of $28.6 million were established primarily associated with offshore assets as a result of management assessment of additional information. Also in 2010, the Company recorded revisions of $11.4 million due to project scope adjustments, favorable weather conditions, and realized project efficiencies which resulted in reductions to the ARO liability. The ARO liability 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. See Note 14 – Commitments and Contingencies – Other Commitments and Contingencies – 2008 Hurricane Damage for additional related information.

21. 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.

22. Quarterly Operations (Unaudited)

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		$	0.59
Dilutive earnings per share:
Continuing operations		$	0.44		$	0.56		$	0.29		$	0.45
Available for common stockholders		$	0.43		$	0.55		$	0.29		$	0.45



The following table presents the operating results for each quarter of the year ended December 31, 2009.

	Quarters Ended
	March 31			June 30			September 30			December 31
	(In thousands, except per share amounts)

Operating revenues		$	683,863		$	453,025		$	438,451		$	603,679
Operating income			91,707			72,654			90,175			91,553
Net earnings			46,257			33,280			46,919			53,124
Net earnings available for common
stockholders			44,086			31,110			44,748			50,953
Net earnings per share
available for common stockholders:
Basic		$	0.36		$	0.25		$	0.36		$	0.41
Diluted		$	0.36		$	0.25		$	0.36		$	0.41

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.

F-61

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors

of Southern Union Company:

In our opinion, the accompanying consolidated financial statements listed in the accompanying index on page F-1 present fairly, in all material respects, the financial position of Southern Union Company and its subsidiaries (the "Company") at December 31, 2010 and 2009 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 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, 2010, 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 the accompanying 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 25, 2011

F-62

Citrus Corp. and Subsidiaries

Consolidated Financial Statements

Years ended December 31, 2010, 2009 and 2008

with Report of Independent Registered Public Accounting Firm


Years ended December 31, 2010, 2009 and 2008



	Table of Contents

		Page

Report of Independent Registered Public Accounting Firm		2

Audited Consolidated Financial Statements
	Consolidated Balance Sheets	3
	Consolidated Statements of Income	4
	Consolidated Statements of Shareholders' Equity	5
	Consolidated Statements of Cash Flows	6
	Notes to Consolidated Financial Statements	7 - 25

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, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 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 25, 2011

CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,
	2010			2009
	(In thousands)
ASSETS

Current assets
Cash and cash equivalents	$	39,018		$	305,597
Accounts receivable, billed and unbilled,
less allowances of $17 and $17, respectively		49,985			41,002
Materials and supplies		14,737			14,403
Other		3,368			4,412
Total current assets		107,108			365,414

Property, plant and equipment (Note 10)
Plant in service		4,854,917			4,646,727
Construction work in progress		2,217,174			769,298
		7,072,091			5,416,025
Less accumulated depreciation and amortization		1,667,360			1,574,765
Net property, plant and equipment		5,404,731			3,841,260

Other assets
Unamortized debt expense		19,070			7,824
Regulatory assets (Note 11)		21,725			21,908
Other		8,057			6,143
Total other assets		48,852			35,875

Total assets	$	5,560,691		$	4,242,549


LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities
Current portion of long-term debt	$	21,500		$	346,322
Accounts payable - trade and other		31,703			34,595
Accounts payable - affiliated companies		11,260			10,642
Accrued interest		45,637			29,380
Accrued income taxes		6,539			5,687
Accrued taxes, other than income		13,932			13,680
Capital accruals		133,002			61,342
Provision for rate refunds (Note 3)		30,837			-
Other		22,542			27,488
Total current liabilities		316,952			529,136

Deferred credits
Deferred income taxes, net (Note 9)		895,279			834,522
Regulatory liabilities (Note 12)		9,363			13,681
Other (Note 12)		16,558			16,679
Total deferred credits		921,200			864,882

Long-term debt (Note 7)		2,591,150			1,500,837
Commitments and contingencies (Note 13)

Stockholders' Equity
Common stock, $1 par value; 1,000 shares authorized, issued and outstanding		1			1
Additional paid-in capital		834,271			634,271
Accumulated other comprehensive loss		(5,480	)		(8,248	)
Retained earnings		902,597			721,670
Total stockholders' equity		1,731,389			1,347,694

Total liabilities and stockholders' equity	$	5,560,691		$	4,242,549

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

CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

	Years Ended December 31,
	2010			2009			2008
				(In thousands)


Operating revenues
Transportation of natural gas (Note 3)	$	517,158		$	508,416		$	504,819

Total operating revenues		517,158			508,416			504,819

Operating expenses
Operations and maintenance		64,655			53,714			54,625
Operations and maintenance - affiliate (Note 4)		39,495			37,671			34,689
Depreciation and amortization		107,270			110,384			105,849
Taxes, other than on income		35,949			34,750			34,411

Total operating expenses		247,369			236,519			229,574


Operating income		269,789			271,897			275,245

Other income (expense)
Interest expense and related charges, net		(116,417	)		(118,806	)		(82,830	)
Other, net		139,920			55,021			8,008

Total other income (expense), net		23,503			(63,785	)		(74,822	)

Income before income taxes		293,292			208,112			200,423

Income taxes (Note 9)		112,365			78,429			73,481
Net income	$	180,927		$	129,683		$	126,942

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

CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

	Years Ended December 31,
	2010			2009			2008
				(In thousands)

Common stock
Balance, beginning and end of period	$	1		$	1		$	1

Additional paid-in capital
Balance, beginning of period		634,271			634,271			634,271
Equity contributions (Note 4)		200,000			-			-
Balance, end of period		834,271			634,271			634,271

Accumulated other comprehensive loss
Balance, beginning of period		(8,248	)		(5,246	)		(7,885	)
Net change in other comprehensive income
(loss) (Note 6)		2,768			(3,002	)		2,639
Balance, end of period		(5,480	)		(8,248	)		(5,246	)

Retained earnings
Balance, beginning of period		721,670			591,987			576,745
Net income		180,927			129,683			126,942
Dividends		-			-			(111,700	)
Balance, end of period		902,597			721,670			591,987

Total stockholders' equity	$	1,731,389		$	1,347,694		$	1,221,013

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

CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2010			2009			2008
				(In thousands)
Cash flows provided by (used in) operating activities
Net income	$	180,927		$	129,683		$	126,942
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		107,270			110,384			105,849
Deferred income taxes		60,602			36,216			37,772
Allowance for equity funds used during construction		(86,153	)		(37,060	)		(7,093	)
Allowance for equity funds used during construction - gross up		(53,268	)		(22,990	)		(4,390	)
Other		4,939			5,862			8,232
Changes in operating assets and liabilities:
Accounts receivable		(8,983	)		(694	)		(958	)
Accounts payable		(2,273	)		2,992			517
Accrued provision for rate refunds		30,837			-			-
Accrued interest		16,257			8,462			6,667
Other current assets and liabilities		(3,134	)		12,849			(11,277	)
Other long-term assets and liabilities		(6,512	)		3,938			(680	)
Net cash flows provided by operating activities		240,509			249,642			261,581

Cash flows provided by (used in) investing activities
Capital expenditures		(1,545,526	)		(455,064	)		(521,435	)
Allowance for equity funds used during construction		86,153			37,060			7,093
Net cash flows used in investing activities		(1,459,373	)		(418,004	)		(514,342	)

Cash flows provided by (used in) financing activities
Issuance of long-term debt		850,000			600,000			500,000
Issuance costs of debt		(6,988	)		(5,964	)		(662	)
Premium for redemption of debt		(6,519	)		-			-
Dividends paid		-			-			(154,300	)
Equity contribution		200,000			-			-
Repayment of long-term debt obligation		(346,500	)		(51,500	)		(44,000	)
Net change in revolving credit facilities		262,292			(79,375	)		(31,817	)
Interest rate hedge - settlement		-			(9,234	)		-
Net cash flows provided by financing activities		952,285			453,927			269,221

Change in cash and cash equivalents		(266,579	)		285,565			16,460

Cash and cash equivalents at beginning of period		305,597			20,032			3,572

Cash and cash equivalents at end of period	$	39,018		$	305,597		$	20,032



Cash paid for interest, net of amounts capitalized	$	145,473		$	118,569		$	75,194
Cash paid for income taxes, net of refunds	$	52,955		$	36,311		$	43,570

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

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, 2010, 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.

The Company evaluated subsequent events through February 25, 2011, 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).

Regulatory Accounting. The Company is subject to regulation by certain state and federal authorities. The Company’s accounting policies conform to authoritative guidance which is in accordance with the accounting requirements and ratemaking practices of the 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 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, 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.

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.

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.

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.

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 sheet 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.

Property, Plant and Equipment. 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. The cost of replacements and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs and replacements of minor property, plant and equipment items is charged to expense as incurred.

When property, plant and equipment is retired, the original cost less salvage value is charged to accumulated depreciation and amortization. When entire regulated operating units of property, plant and equipment are retired or sold, the property and related accumulated depreciation and amortization accounts are reduced, and any gain or loss is recorded in income.

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 has provided for depreciation of assets, on a straight-line basis, at an annual composite rate of 2.57 percent, 2.78 percent and 2.75 percent for the years ended December 31, 2010, 2009 and 2008, respectively. In 2010, the depreciation rates decreased effective April 1, 2010 based on the uncontested settlement of Florida Gas’ rate case which is pending final FERC approval; see Note 3 – Regulatory Matters for additional information.

The recognition of an allowance for funds used during construction (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 $50.5 million, $13.2 million and $4.1 million for the years ended December 31, 2010, 2009 and 2008, respectively. The allowance for equity funds used during construction, including related amounts to gross up equity AFUDC to a before tax basis, totaled $139.4 million, $60.0 million and $11.5 million for the years ended December 31, 2010, 2009 and 2008, respectively. AFUDC-equity funds are included in Other income in the accompanying Statements of Income.

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

See Note 13 – Commitment and Contingencies.

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Revenues. Revenues from transportation of natural gas are based on capacity reservation charges and 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 of natural gas delivered.

Because Florida Gas is subject to FERC regulations, revenues collected during the pendency of a rate proceeding may be required by the FERC to be refunded in the final order. Florida Gas establishes reserves for such potential refunds, as appropriate. There was $30.8 million and nil for potential rate refunds at December 31, 2010 and 2009, respectively. See Note 3 – Regulatory Matters.

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, 2010, 2009 and 2008, respectively.

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 53 percent, 54 percent and 55 percent of total revenue for the years ended December 31, 2010, 2009 and 2008, respectively.

	Years Ended December 31,
	2010		2009		2008
	(In thousands)

Florida Power & Light Company	$	209,385	$	199,217	$	197,301
TECO Energy, Inc.		79,228		73,430		78,255

The Company had the following transportation receivables from these customers at the dates indicated:

	December 31,
	2010		2009
	(In thousands)

Florida Power & Light Company	$	16,881	$	15,246
TECO Energy, Inc.		5,969		5,558

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 $1.4 million, and prepayments of $62,000 and $181,000 at December 31, 2010 and 2009, 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.

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Retirement Plans. Employers are required to recognize in their balance sheets the overfunded or underfunded status of defined benefit postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation. 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 through Accumulated other comprehensive loss in stockholders’ equity in the year in which the change occurs. The Company recognized net periodic benefit expense to the extent of amounts recorded in rates with any difference recorded as a regulatory asset or liability. Unrecognized prior service costs (benefits) and gains and/or losses are not recorded as a change to Accumulated other comprehensive loss, but rather as a regulatory asset or regulatory liability, reflecting amounts due from or to customers, respectively.

See Note 8 – Benefits for additional related information.

Derivatives and Hedging Activities. All derivatives are recognized on the consolidated balance sheet at their fair value. On the date the derivative contract is entered into, the Company designates the derivative as (i) a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (a fair value hedge); (ii) a hedge of a forecasted transaction or the variability of cash flows to be received or paid in conjunction with a recognized asset or liability (a cash flow hedge); or (iii) an instrument that is held for trading or non-hedging purposes (a trading or economic hedging instrument). For derivatives treated as a fair value hedge, the effective portion of changes in fair value is recorded as an adjustment to the hedged item. The ineffective portion of a fair value hedge is recognized in earnings 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. Upon termination of a cash flow hedge, the resulting gain or loss is amortized to earnings through the maturity date of the hedged forecasted transactions. 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. As of December 31, 2010 and 2009, the Company does not have any hedges in place; it is only amortizing previously terminated cash flow hedges.

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

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

See Note 8 – Benefits – Postretirement Benefit Plans – Plan Assets for additional information regarding the assets of the Company measured on a non-recurring basis.

Asset Retirement Obligations (ARO). 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 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. The Company records ARO accretion and amortization expenses (in excess of current recoveries) as a regulatory asset based on the probability of recovery in rates in future rate cases.

For more information, see Note 5 – 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 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 income 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.

New Accounting Principles

Accounting Principles Recently Adopted. In June 2009, the Financial Accounting Standards Board (FASB) issued authoritative guidance that changes how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly affect the entity’s economic performance. The guidance is effective as of the beginning of the first annual reporting period, and for interim periods within that first period, after November 15, 2009, with early adoption prohibited. This guidance did not materially impact the Company’s consolidated financial statements.

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3. Regulatory Matters

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 high consequence areas (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 assessments, 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, 2010, Florida Gas had completed approximately 87 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.

Florida Gas filed a certificate application on October 31, 2008 with FERC to construct an expansion which will increase its natural gas capacity into Florida by approximately 820 million cubic feet per day (MMcf/d). The Phase VIII Expansion includes construction of approximately 500 miles of large diameter pipeline and the installation of approximately 200,000 horsepower of compression. On November 19, 2009, FERC issued a certificate to Florida Gas authorizing the Phase VIII Expansion project. Florida Gas anticipates an in-service date in April 2011.

Florida Gas filed a rate case with FERC on October 1, 2009, initially reflecting an annual cost of service of approximately $579 million. Pursuant to a FERC order on rehearing and Florida Gas’ motion filing, on April 15, 2010, Florida Gas refiled its rates to be effective April 1, 2010 to remove the impact of certain estimated plant expenditures not in service by February 28, 2010, which reduced the annual cost of service originally filed by approximately $28 million to $551.6 million. Florida Gas, by comparison, has recorded actual revenues of approximately $511 million for the twelve-month period ended March 31, 2010 under its previously existing rates, including amounts collected from system expansions and certain surcharges. The new rates went into effect on April 1, 2010, subject to refund pending the final outcome of the rate proceeding.

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On November 29, 2010, FERC notified Florida Gas that it was commencing an audit to evaluate Florida Gas’ compliance with FERC’s accounting and reporting requirements for calculating and accruing AFUDC. The audit will cover January 1, 2008 to the present.

4. Related Party Transactions

Florida Gas purchases transportation services from Southern Natural Gas Company (Southern), a subsidiary of El Paso, in connection with its Phase III Expansion completed in early 1995. Florida Gas is currently contracted for firm capacity of 100,000 Mcf/day on Southern’s system through August 31, 2013. The amount expensed for these services totaled $8.2 million, $7.1 million and $6.8 million in the years ended December 31, 2010, 2009 and 2008, respectively. Florida Gas had net accounts payable to Southern of $645,000 and $600,000 as of December 31, 2010 and 2009, respectively.

The Company has related party activities for operational and administrative services performed by Panhandle Eastern Pipe Line Company, LP (PEPL), an indirect wholly-owned subsidiary of Southern Union, and other related parties, on behalf of the Company, and corporate service charges from Southern Union. Expenses are generally charged based on either actual usage of services or allocated based on estimates of time spent working for the benefit of the various affiliated companies. Amounts expensed by the Company were $31.3 million, $30.6 million and $27.9 million in the years ended December 31, 2010, 2009 and 2008, respectively, and included corporate service charges from Southern Union of $8.8 million, $7.2 million and $6.3 million in the years ended December 31, 2010, 2009 and 2008, respectively. Additionally, the Company receives allocated costs of certain shared business services from PEPL and Southern Union. At December 31, 2010 and 2009, the Company had current net accounts payable to affiliated companies of $10.6 million and $10.0 million, respectively, relating to these services.

No cash dividend was declared and paid to shareholders for the years ended December 31, 2010 and 2009 primarily due to the ongoing Phase VIII Expansion capital requirements. The Company paid cash dividends to its shareholders of $154.3 million during the year ended December 31, 2008. Included in the 2008 dividend payments was a declared dividend in December 2007 of $42.6 million, paid on January 18, 2008. The Company received equity contributions from its shareholders of $200 million during the year ended December 31, 2010.

5. Asset Retirement Obligations

The Company’s recorded AROs are primarily related to owned offshore lines. 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 assets in the Company’s system are subject to agreements or regulations that give rise to an ARO upon the Company’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement.

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

The following table is a general description of ARO and associated long-lived assets at December 31, 2010.

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

Retire lateral lines	Various	Offshore lateral lines	$	1,236
Remove asbestos	Various	Mainlines and compressors	$	489

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2010, the Company has no funds legally restricted for the purpose of settling AROs. The following table is a reconciliation of the carrying amount of the ARO liability for the periods presented.

	Years Ended December 31,
	2010			2009			2008
	(In thousands)

Beginning balance	$	2,585		$	1,819		$	471
Incurred		283			2,064			1,358
Settled		(40	)		(1,450	)		(37	)
Accretion		175			152			27
Ending balance	$	3,003		$	2,585		$	1,819

6. Comprehensive Income

Deferred gains and losses in connection with the termination of the following derivative instruments which were previously accounted for as cash flow hedges form part of other comprehensive income. Such amounts are being amortized over the terms of the hedged debt.

The table below provides an overview of Comprehensive income (loss) for the periods presented.


	Years Ended December 31,
	2010			2009			2008
	(In thousands)

Net Income	$	180,927		$	129,683		$	126,942
Reclassification of realized loss on interest rate hedge of 7.625% $325 million note due 2010 into net income		1,186			1,872			1,873
Reclassification of realized loss on interest rate hedge of 7.000% $250 million note due 2012 into net income		1,228			1,228			1,228
Reclassification of realized gain on interest rate hedge of 9.190% $150 million note due 2024 into net income		(462	)		(462	)		(462	)
Reclassification of realized loss on interest rate hedge of 9.393% $500 million note due 2029, net of tax $176, $40, $0		286			65			-
Settlement of realized loss on interest rate hedge due to debt retirement		530			-			-
Realized loss on settlement of interest rate hedge, net of tax $0, $3.5 million, $0		-			(5,705	)		-
Total other comprehensive income (loss)		2,768			(3,002	)		2,639
Total comprehensive income	$	183,695		$	126,681		$	129,581

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

7. Debt

The following table sets forth the debt obligations at the dates indicated.

	December 31, 2010					December 31, 2009
	Carrying Value			Fair Value		Carrying Value			Fair Value
	(In thousands)
Citrus
Revolving credit agreement due 2012	$	178,500		$	174,632	$	5,208		$	4,899
Construction and term loan agreement due 2029		500,000			711,531		500,000			682,214
Florida Gas
10.110% senior notes due 2013		42,000			47,174		56,000			64,236
9.190% senior notes due 2024		105,000			142,067		112,500			141,109
7.625% senior notes due 2010		-			-		325,000			344,012
7.000% senior notes due 2012		250,000			277,094		250,000			283,057
7.900% senior notes due 2019		600,000			756,398		600,000			731,582
4.000% senior notes due 2015		350,000			366,779		-			-
5.450% senior notes due 2020		500,000			541,841		-			-
Revolving credit agreement due 2012		89,000			87,072		-			-
Total debt outstanding	$	2,614,500		$	3,104,588	$	1,848,708		$	2,251,109
Current portion of long-term debt		(21,500	)				(346,322	)
Unamortized debt discount and swap loss		(1,850	)				(1,549	)
Total long-term debt	$	2,591,150				$	1,500,837

Annual maturities of long-term debt outstanding, excluding unamortized debt discount, as of the date indicated were as follows:

	December 31,
Year	2010
	(In thousands)

2011	$	21,500
2012		539,000
2013		21,500
2014		7,500
2015		371,293
Thereafter		1,653,707
	$	2,614,500

The Florida Gas revolving credit agreement, with a maximum available capacity of $279 million, (2007 Florida Gas Revolver) matures on August 16, 2012. As of December 31, 2010, the amount drawn under the 2007 Florida Gas Revolver was $89 million with a weighted average interest rate of 0.67 percent (based on the London Interbank Offered Rate (LIBOR) plus 0.36 percent) and a facility fee of 0.09 percent.

The Citrus revolving credit facility, with a maximum available capacity of $186 million, (2007 Citrus Revolver) matures on August 16, 2012. As of December 31, 2010, the amount drawn under the 2007 Citrus Revolver was $178.5 million with a weighted average interest rate of 0.67 percent (based on LIBOR plus 0.36 percent), and a facility fee of 0.09 percent.

The estimated fair values of the 2007 Florida Gas Revolver and 2007 Citrus Revolver at December 31, 2010 approximate 98 percent of their carrying values. Estimated fair value amounts of other long-term debt were obtained from independent parties, and are based upon market quotations of similar debt at interest rates currently available. Judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates determined as of December 31, 2010 and 2009 are not necessarily indicative of the amounts the Company could have realized in current market exchanges.

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In May 2009, Florida Gas issued $600 million of 7.90 percent senior notes due May 15, 2019 with an offering price of $99.82 (per $100 principal). Florida Gas utilized the net proceeds to partially fund the Phase VIII Expansion project and for general corporate purposes.

In June 2009, Citrus retired early its remaining $30 million 8.49 percent senior notes which were scheduled to mature in November 2009. The debt retirement included accrued interest of $283,000 and a $900,000 redemption premium.

In July 2009, Citrus entered into a series of forward starting swap rate lock agreements (Swap Rate Lock Agreements) with a total notional amount of $175 million with regard to the expected conversion of Citrus’ $500 million construction and term loan (Construction Loan Agreement). The Swap Rate Lock Agreements were designed to hedge against the potential changes in future cash flows payable under the Construction Loan Agreement upon its conversion to a twenty-year fixed-rate term loan. The Swap Rate Lock Agreements were settled by Citrus in October 2009 for a loss of $9.2 million.

In October 2009, the Construction Loan Agreement, with an initial interest rate based upon LIBOR plus a margin of 5.35 percent, was converted to a twenty-year fixed-rate term loan with a fixed interest rate of 9.393 percent. Interest is payable in semi-annual installments over the next five years. The required semi-annual payments will include principal beginning April 2015, and the loan has a final balloon payment of $300 million in principal on October 8, 2029.

In July 2010, Florida Gas issued $500 million of 5.45 percent senior notes due July 15, 2020 with an offering price of $99.826 (per $100 principal) and $350 million of 4.00 percent senior notes due July 15, 2015 with an offering price of $99.982 (per $100 principal). Florida Gas utilized 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 percent senior notes due December 1, 2010. The debt retirement included accrued interest of $5.4 million and a $6.5 million redemption premium.

Under the terms of its debt agreements, Florida Gas may incur additional debt to refinance maturing obligations if the refinancing does not increase aggregate indebtedness, and thereafter, if Citrus’ and Florida Gas’ consolidated debt does not exceed specific debt to total capitalization ratios, as defined in certain debt instruments. Incurrence of additional indebtedness to refinance the current maturities would not result in a debt to capitalization ratio exceeding these limits.

The agreements relating to Florida Gas’ debt include, among other things, restrictions as to the payment of dividends and maintenance of certain restrictive financial covenants, including a required ratio of funded debt to total capitalization. The Company is subject, under the currently most restrictive debt covenant of a maximum 65 percent of consolidated funded debt to total capitalization, to a limitation of $602.8 million of total additional indebtedness at December 31, 2010.

As of December 31, 2010, Citrus’ debt obligations include the Construction Loan Agreement and $178.5 million outstanding on its revolving credit agreement, in addition to all of Florida Gas’ debt obligations. Florida Gas guarantees the Citrus revolving credit agreement indebtedness; however, Florida Gas’ assets are not pledged as collateral for any of the aforementioned Citrus debt. All of the debt obligations of Citrus and Florida Gas have events of default that contain commonly used cross-default provisions. An event of default by either Citrus or Florida Gas on any of their borrowed money obligations, in excess of certain thresholds which is not cured within defined grace periods, would cause the other debt obligations of Citrus and Florida Gas to be accelerated. As of December 31, 2010, Citrus is not in default of any of its debt obligations.

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

8. Benefits

Postretirement Benefit Plans

Florida Gas has postretirement health care and life insurance plans (other postretirement plans) that cover substantially all employees. The health care plan generally provides for cost sharing between Florida Gas and its retirees in the form of retiree contributions, deductibles and coinsurance on the amount Florida Gas pays annually to provide future retiree health care coverage under certain of these plans.

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

	Other Postretirement Benefits
	December 31,
	2010			2009
	(In thousands)
Change in benefit obligation:
Benefit obligation at beginning of period	$	17,671		$	16,010
Service cost		658			529
Interest cost		1,044			945
Actuarial (gain) loss and other		1,486			(925	)
Benefits paid, net		(557	)		(346	)
Medicare Part D subsidy receipts		97			83
Plan amendments (1)		-			1,375
Benefit obligation at end of year		20,399			17,671

Change in plan assets:
Fair value of plan assets at beginning of period		10,654			8,243
Return on plan assets and other		1,257			1,722
Employer contributions		1,981			1,035
Benefits paid, net		(557	)		(346	)
Fair value of plan assets at end of period		13,335			10,654


Amount underfunded at end of period (2)	$	7,064		$	7,017

Amounts recognized in the Consolidated Balance Sheet
consist of:
Regulatory assets (Note 11)	$	7,064		$	7,017
Deferred credits - other (Note 12)		(7,064	)		(7,017	)
	$	-		$	-

(1) The Plan was amended to provide an annual increase to the dollar multiplier used to establish initial account balances for employees who retire on or after October 1, 2008. This amendment was adopted in late September 2009. It is required that amendments be measured and recognized at the time of adoption. Accordingly, the amendment was measured at September 30, 2009, the end of the month nearest to the month of adoption.

(2)	Underfunded balance is recognized as a deferred credit-other, offset by a regulatory asset for amounts due from customers, in the consolidated balance sheet.

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Net Periodic Benefit Cost. Net periodic benefit cost of Florida Gas’ other postretirement benefit plan for the periods presented includes the components noted in the table below.

	Other Postretirement Benefits
	Years Ended December 31,
	2010			2009			2008
	(In thousands)
Net Periodic Benefit Cost:
Service cost	$	658		$	529		$	165
Interest cost		1,044			945			545
Expected return on plan assets		(557	)		(441	)		(440	)
Prior service cost amortization		1,195			1,088			351
Actuarial gain amortization		(137	)		-			(218	)
Net periodic benefit cost	$	2,203		$	2,121		$	403

Assumptions

The weighted-average discount rate used in determining benefit obligations was 5.52 percent and 5.97 percent at December 31, 2010 and 2009, respectively.

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

	Years Ended December 31,
	2010			2009			2008

Discount rate		5.97	%		6.14	%	Jan-Aug: 6.09% Sep-Dec: 7.02%
Expected return on plan assets		5.00	%		5.00	%		5.00	%

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

The assumed health care cost trend rates used for measurement purposes are shown in the table below.

	December 31,
	2010			2009

Health care cost trend rate assumed for next year		8.00	%		8.50	%
Ultimate trend rate		4.85	%		4.85	%
Year that the rate reaches the ultimate trend rate		2017			2017

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

	One Percentage Point Increase		One Percentage Point Decrease
	(In thousands)
Effect on total service and interest cost	$	216	$	(203	)
Effect on accumulated postretirement benefit obligation		2,609		(2,367	)

Plan Assets. Florida Gas’ overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing long-term returns while maintaining a high standard of portfolio quality and achieving proper diversification. To achieve diversity within its other postretirement benefit plan asset portfolio, Florida Gas 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 Board of Directors in conjunction with an external investment advisor. On occasion, the asset allocations may fluctuate as compared to these guidelines as a result of the Board of Directors’ actions.

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

	Fair Value as of December 31,
	2010		2009
	(In thousands)
Asset Category:
Cash and cash equivalents	$	1,867	$	959
Mutual fund (1)		11,468		9,695
Total	$	13,335	$	10,654

(1) This fund of funds invests primarily in a diversified portfolio of equity, fixed income and short-term mutual funds. 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. As of December 31, 2009, the fund was primarily comprised of approximately 16 percent large-cap U.S. equities, 3 percent small-cap U.S. equities,10 percent international equities, 57 percent fixed income securities, 10 percent cash, and 4 percent in other investments.

The other postretirement plan assets are classified as Level 1 assets within the fair-value hierarchy as their value is based on active market quotes. See Note 2 – Summary of Significant Accounting Policies and Other Matters – Fair Value Measurement for information related to the framework used by the Company to measure the fair value of its other postretirement plan asset.

Contributions. Florida Gas expects to contribute approximately $2.2 million to its other postretirement benefit plan in 2011 and approximately $2.2 million annually thereafter until modified by future rate case proceedings.

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Years	Expected Benefits Before Effect of Medicare Part D		Payments Medicare Part D Subsidy Receipts		Net
			(In thousands)

2011	$	655	$	94	$	561
2012		787		104		683
2013		896		117		779
2014		998		133		865
2015		1,123		146		977
2016-2020		7,591		1,027		6,564

The Medicare Prescription Drug Act provides 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.

Health Care Reform

In March 2010, the Patient Protection and Affordable Care Act and the Health Care Education and Affordability Reconciliation Act (the Acts) were signed into law. The Acts contain provisions which could impact the Company’s retiree medical benefits in future periods. However, the extent of that impact, if any, cannot be determined until additional interpretations of the Acts become available. Based on the analysis to date, the impact of provisions in the Acts which are reasonably determinable is not expected to have a material impact on the Company’s other postretirement benefit plans. Accordingly, a remeasurement of the Company’s postretirement benefit obligation is not required at this time. The Company will continue to assess the provisions of the Acts and may consider plan amendments in future periods to better align these plans with the provisions of the Acts.

Defined Contribution Plan

Florida Gas sponsors a defined contribution savings plan (Savings Plan) that is available to all employees. Florida Gas provided matching contributions of 100 percent of the first two percent and 50 percent of the next three percent of the participant’s compensation paid into the Savings Plan through December 31, 2008. Effective January 1, 2009, the matching was increased to 100 percent of the first five percent for a maximum of five percent of the participant’s compensation paid into the Savings Plan. Florida Gas’ contributions are 100 percent vested after five years of continuous service. Florida Gas’ contributions to the Savings Plan during the years ended December 31, 2010, 2009 and 2008 were $1.0 million, $1.1 million and $728,000, respectively.

In addition, Florida Gas makes employer contributions to separate accounts, referred to as Profit Sharing Plan, within the defined contribution plan. The contribution amounts are determined as five percent of compensation. Florida Gas’ contributions are 100 percent vested after five years of continuous service. Florida Gas’ contributions to the Profit Sharing Plan during the years ended December 31, 2010, 2009 and 2008 were $1.5 million, $1.4 million and $1.3 million, respectively.

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

9. Income Taxes

The following table provides a summary of the current and deferred components of income tax expense for the periods presented:

	Years Ended December 31,
	2010			2009			2008
	(In thousands)
Current income taxes
Federal	$	45,059		$	38,954		$	34,899
State		6,704			3,259			810
Total current income taxes		51,763			42,213			35,709

Deferred income taxes
Federal		52,291			30,793			33,051
State		8,311			5,423			4,721
Total deferred income taxes		60,602			36,216			37,772
Total income tax expense	$	112,365		$	78,429		$	73,481

Effective tax rate		38.3	%		37.7	%		36.7	%

The actual income tax expense differs from the amount computed by applying the statutory federal tax rate of 35 percent to income before income taxes as follows:

	Years Ended December 31,
	2010			2009			2008
	(In thousands)

Income tax , computed at the statutory rate	$	102,652		$	72,839		$	70,148
Adjustments:
State income tax, net of federal income tax benefit		9,760			5,643			3,595
Permanent differences and other		(47	)		(53	)		(262	)
Total income tax expense	$	112,365		$	78,429		$	73,481

The Company files a consolidated federal income tax return separate from that of its stockholders. Florida Gas is included in the consolidated federal income tax return filed by Citrus. Pursuant to a tax sharing agreement with Citrus, Florida Gas will pay its share of taxes based on its taxable income, which will generally equal the liability that Florida Gas would have incurred as a separate taxpayer.

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The principal components of the Company's deferred tax assets (liabilities) recognized at the dates indicated are as follows:

	December 31,
	2010			2009
	(In thousands)
Deferred income tax asset:
Regulatory and other reserves	$	10,752		$	5,635
Total deferred income tax asset		10,752			5,635

Deferred income tax liabilities:
Depreciation and amortization		(903,085	)		(836,498	)
Deferred charges and other assets		(3,506	)		(3,618	)
Other		560			(41	)
Total deferred income tax liabilities		(906,031	)		(840,157	)

Net deferred income tax liabilities	$	(895,279	)	$	(834,522	)

Effective January 1, 2009, the Company evaluates its tax reserves (unrecognized tax benefits) under the recognition, measurement and derecognition thresholds. The amount of unrecognized tax benefits did not have a material impact to the Company’s consolidated financial statements.

10. Property, Plant and Equipment

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

	Lives in		December 31,
	Years		2010		2009
			(In thousands)

Transmission		20-60	$	3,552,004	$	3,344,407
General		3-40		22,014		22,561
Intangibles (1)		6-10		28,433		27,294
Construction work-in-progress				2,217,174		769,298
Acquisition adjustment		62.5		1,252,466		1,252,465
				7,072,091		5,416,025
Less accumulated depreciation and amortization				1,667,360		1,574,765
Net property, plant and equipment			$	5,404,731	$	3,841,260


(1) Includes capitalized computer software costs totaling:
Computer software cost			$	23,789	$	22,648
Less accumulated amortization				9,856		8,653
Net computer software costs			$	13,933	$	13,995

Amortization expense of capitalized computer software costs for the years ended December 31, 2010, 2009 and 2008 was $2.5 million, $1.7 million and $1.5 million, respectively. Computer software costs are amortized over 10 years.

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

11. Regulatory Assets

The principal components of the Company's regulatory assets at the dates indicated were as follows:

	December 31,
	2010		2009
	(In thousands)

Ramp-up assets, net (1)	$	10,681	$	10,993
Other postretirement benefits (Note 8)		7,064		7,017
Environmental reserve (Note 13)		1,036		1,147
Asset retirement obligations (Note 5)		1,341		1,506
Other miscellaneous		1,603		1,245
Total regulatory assets	$	21,725	$	21,908

(1)	Ramp-up assets are regulatory assets which Florida Gas was specifically allowed to establish in the FERC certificates authorizing the Phase IV and V Expansion projects.

12. Deferred Credits

The principal components of the Company's regulatory liabilities at the dates indicated were as follows:

	December 31,
	2010		2009
	(In thousands)

Balancing tool (1)	$	5,455	$	12,937
Fuel Tracker		3,908		744
Total regulatory liabilities	$	9,363	$	13,681

(1) Balancing tool is a regulatory method by which Florida Gas recovers or refunds the net costs of operational natural gas balancing of the pipeline’s system. The balance can be a deferred charge or credit, depending on timing, rate changes and operational activities.

The principal components of the Company's other deferred credits at the dates indicated were as follows:

	December 31,
	2010		2009
	(In thousands)

Post construction mitigation costs	$	1,071	$	1,247
Other postretirement benefits (Note 8)		7,064		7,017
Environmental reserve		1,120		1,166
Tax reserve		3,297		3,358
Asset retirement obligations (Note 5)		3,003		2,585
Other miscellaneous		1,003		1,306
Total deferred credits - other	$	16,558	$	16,679

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

13. Commitments and Contingencies

Litigation. 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, some of which involve substantial amounts. Where appropriate, the Company has established reserves in order to provide for such matters. The Company believes the final disposition of these proceedings will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Phase VIII Expansion. Florida Gas anticipates an in-service date in April 2011, for the Phase VIII Expansion, at a currently estimated cost of approximately $2.48 billion, including capitalized equity and debt costs. Approximately $2.2 billion of capital costs have been recorded as of December 31, 2010. To date, Florida Gas has entered into firm transportation service agreements with shippers for 25-year terms accounting for approximately 74 percent of the available expansion capacity.

Liquidity and Capital Requirements. The Company plans to finance Florida Gas’ remaining planned capital expenditures for the Phase VIII Expansion and other capital projects with cash flows from operations, utilization of revolving credit facilities, and contributions from its shareholders. In 2010, each shareholder made a $100 million equity contribution to the Company to partially fund the Phase VIII expansion. During the first half of 2011, it is expected that the Company will require additional contributions, which may be in the form of loans or equity contributions, from each of its shareholders of up to $150 million. The Company plans to resume distributions, which may be in the form of loan repayments or dividends, to its shareholders after the Phase VIII Expansion project is placed in-service.

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

Florida Gas conducts assessment, remediation, and ongoing monitoring of soil and groundwater impact which resulted from its past waste management practices at its Rio Paisano and Station 11 facilities. The liability is recognized in other current liabilities and in other deferred credits and in total amounted to $1.4 million and $1.5 million at December 31, 2010 and 2009, respectively. Amounts are not discounted because of uncertainty related to timing. Costs of $0.1 million, $0.1 million and $0.1 million were expensed during the years ended December 31, 2010, 2009 and 2008, respectively. Florida Gas recorded the estimated costs of remediation to be spent after April 1, 2010 as a regulatory asset based on the probability of recovery in rates in its current rate proceeding. The balance of the regulatory asset was $1.0 million and $1.1 million at December 31, 2010 and 2009, respectively (See Note 11 – Regulatory Assets).

Air Quality Control. In August 2010, the United States Environmental Protection Agency (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.

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Florida Gas Pipeline Relocation Costs. The Florida Department of Transportation, Florida’s Turnpike Enterprise (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. A dispute exists with the FDOT/FTE over the rights of Florida Gas under certain easements and other agreements associated with the State Road 91 projects to, among other matters, receive reimbursement for the relocation costs incurred by Florida Gas and the nature and scope of such easements. The first phase of the State Road 91 projects included replacement of approximately 11.3 miles of existing 18- and 24-inch pipelines in Broward County, Florida due to the widening of State Road 91 by the FDOT/FTE. Construction is complete and the new facilities were placed in service in March 2008. The FDOT/FTE plans additional projects that may affect Florida Gas’ pipelines within FDOT/FTE rights-of-way. The total miles of pipe that may ultimately be affected by all of the FDOT/FTE widening projects, and any associated relocation and/or rights-of-way costs, cannot be determined at this time.

Several FDOT/FTE projects are the subject of litigation in Broward County, Florida. On January 27, 2011, the jury awarded Florida Gas $82.7 million and rejected all damage claims by the FDOT/FTE. The judge has not ruled on issues associated with the width of the easement for the pipelines, permissible encroachments and other matters including a request by the FDOT that the 18 inch pipeline in the FDOT/FTE right-of-way be replaced or reconditioned. In addition, the FDOT/FTE has filed a request for a new trial and a motion asking the Court to disregard the jury’s verdict and find in favor of the FDOT/FTE. Amounts ultimately received would primarily reduce Florida Gas’ property, plant and equipment costs.

A 2007 action brought by the FDOT/FTE against Florida Gas in Orange County, Florida, seeking a declaratory judgment that, under existing agreements, Florida Gas is liable for the costs of relocation associated with FDOT/FTE projects, has been stayed pending resolution of the Broward County, Florida action.

Should Florida Gas be denied reimbursement by the FDOT/FTE for relocation expenses, such costs are expected to be covered by operating cash flows and additional borrowings. Florida Gas will continue to seek rate recovery in the future for these types of costs to the extent not reimbursed by the FDOT/FTE. There can be no assurance that Florida Gas will be successful in obtaining complete reimbursement for any such relocation costs from the FDOT/FTE or from its customers or that the timing of such reimbursement will fully compensate Florida Gas for its costs.

See Note 3 – Regulatory Matters for other potential contingent matters applicable to the Company.