10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C.  20549

____________________________

FORM 10-Q

Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended

September 30, 2010

Commission File No. 1-6407

____________________________

SOUTHERN UNION COMPANY

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)	75-0571592 (I.R.S. Employer Identification No.)
5444 Westheimer Road Houston, Texas (Address of principal executive offices)	77056-5306 (Zip Code)

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

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 P 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 P  No___

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 P    Accelerated filer    Non-accelerated filer   (Do not check if smaller reporting company)   Smaller reporting company ___&# 160;

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

Yes No  P                                                                                     

The number of shares of the registrant's Common Stock outstanding on October 29, 2010 was 124,505,118.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

FORM 10-Q

September 30, 2010

Table of Contents

PART I. FINANCIAL INFORMATION:	Page(s)
Glossary	2
ITEM 1. Financial Statements (Unaudited):
Condensed consolidated statement of operations.	3
Condensed consolidated balance sheet.	4-5
Condensed consolidated statement of cash flows.	6
Condensed consolidated statement of stockholders’ equity and comprehensive income.	7
Notes to condensed consolidated financial statements.	8
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.	31
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.	46
ITEM 4. Controls and Procedures.	48
PART II. OTHER INFORMATION:
ITEM 1. Legal Proceedings.	50
ITEM 1A. Risk Factors.	50
ITEM 2.  Unregistered Sales of Equity Securities and Use of Proceeds.	51
ITEM 3.  Defaults Upon Senior Securities.	51
ITEM 4.  Reserved.	51
ITEM 5.  Other Information.	51
ITEM 6.  Exhibits.	52
SIGNATURES	57

1

GLOSSARY

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

Btu                                               British thermal units

CEO                                             Chief Executive Officer

CFO                                             Chief Financial Officer

Citrus                                          Citrus Corp.

Company                                    Southern Union and its subsidiaries

EBIT                                            Earnings before interest and taxes

EITR                                            Effective income tax rate

EPA                                             United States Environmental Protection Agency

Exchange Act                            Securities Exchange Act of 1934

FASB                                          Financial Accounting Standards Board

FERC                                           Federal Energy Regulatory Commission

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

Florida Gas                                 Florida Gas Transmission Company, LLC

GAAP                                         Accounting principles generally accepted in the United States of America

Grey Ranch                                Grey Ranch Plant, LP

HCAs                                          High consequence areas

LNG                                             Liquefied natural gas

LNG Holdings                           Trunkline LNG Holdings, LLC

MADEP                                      Massachusetts Department of Environmental Protection

MDPU                                         Massachusetts Department of Public Utilities

MGPs                                          Manufactured gas plants

MMBtu                                       Million British thermal units

MMBtu/d                                   Million British thermal units per day

MMcf                                          Million cubic feet

MMcf/d                                       Million cubic feet per day

MPSC                                          Missouri Public Service Commission

NGL                                             Natural gas liquids

NMED                                         New Mexico Environment Department

Panhandle                                   Panhandle Eastern Pipe Line Company, LP and its subsidiaries

PCBs                                            Polychlorinated biphenyls

PEPL                                            Panhandle Eastern Pipe Line Company, LP

PRPs                                            Potentially responsible parties

RCRA                                          Resource Conservation and Recovery Act

RFP                                              Request for Proposal

SARs                                           Stock appreciation rights

Sea Robin                                   Sea Robin Pipeline Company, LLC

SEC                                              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

2

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

(UNAUDITED)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(In thousands, except per share amounts)
Operating revenues (Note 13)	$	487,527		$	438,451		$	1,819,617		$	1,575,339
Operating expenses:
Cost of gas and other energy		217,928			165,029			903,563			737,008
Operating, maintenance and general		118,025			113,270			350,633			358,486
Depreciation and amortization		57,305			53,486			170,058			159,316
Revenue-related taxes		4,322			3,560			26,170			25,582
Taxes, other than on income and revenues		13,540			12,931			41,764			40,411
Total operating expenses		411,120			348,276			1,492,188			1,320,803
Operating income		76,407			90,175			327,429			254,536
Other income (expenses):
Interest expense		(55,239	)		(50,234	)		(161,551	)		(146,969	)
Earnings from unconsolidated investments		32,336			24,421			78,456			63,688
Other, net		352			2,277			289			8,371
Total other income (expenses), net		(22,551	)		(23,536	)		(82,806	)		(74,910	)
Earnings before income taxes		53,856			66,639			244,623			179,626
Federal and state income tax expense (Note 9)		16,525			19,720			75,943			53,170
Net earnings		37,331			46,919			168,680			126,456
Preferred stock dividends		(699	)		(2,171	)		(5,040	)		(6,512	)
Loss on extinguishment of preferred stock (Note 17)		-			-			(3,295	)		-
Net earnings available for common stockholders	$	36,632		$	44,748		$	160,345		$	119,944
Net earnings available for common stockholders per share:
Basic	$	0.29		$	0.36		$	1.29		$	0.97
Diluted		0.29			0.36			1.28			0.97
Dividends declared on common stock per share	$	0.15		$	0.15		$	0.45		$	0.45
Weighted average shares outstanding  (Note 4):
Basic		124,484			124,057			124,458			124,050
Diluted		125,160			124,568			125,106			124,273

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

3

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEET

(UNAUDITED)

ASSETS

	September 30,			December 31,
	2010			2009
	(In thousands)
Current assets:
Cash and cash equivalents	$	17,122		$	10,545
Accounts receivable, net of allowances of
$3,562 and $1,874, respectively		187,898			277,661
Accounts receivable – affiliates		10,425			10,387
Inventories  (Note 3)		193,438			290,031
Deferred natural gas purchases		127,010			88,421
Natural gas imbalances - receivable		72,122			127,284
Prepayments and other assets		78,466			57,024
Total current assets		686,481			861,353
Property, plant and equipment:
Plant in service		6,862,958			6,260,188
Construction work in progress		130,647			531,710
		6,993,605			6,791,898
Less accumulated depreciation and amortization		(1,329,387	)		(1,162,685	)
Net property, plant and equipment		5,664,218			5,629,213
Deferred charges:
Regulatory assets		68,345			72,304
Deferred charges		65,826			60,995
Total deferred charges		134,171			133,299
Unconsolidated investments  (Note 5)		1,419,086			1,340,048
Goodwill		89,227			89,227
Other		19,049			21,934
Total assets	$	8,012,232		$	8,075,074

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

4

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEET

(UNAUDITED)

STOCKHOLDERS' EQUITY AND LIABILITIES

	September 30,			December 31,
	2010			2009
	(In thousands)
Stockholders’ equity:
Common stock, $1 par value; 200,000 shares authorized;
125,666 and 125,569 shares issued, respectively	$	125,666		$	125,569
Preferred stock, no par value; 6,000 shares authorized;
nil and 460 shares issued, respectively (Note 17)		-			115,000
Premium on capital stock		1,917,526			1,905,293
Less treasury stock: 1,176 and 1,171
shares, respectively, at cost		(29,215)			(29,109)
Less common stock held in trust: 589
and 659 shares, respectively		(10,659)			(11,769)
Deferred compensation plans		10,659			11,769
Accumulated other comprehensive loss		(33,919	)		(56,505	)
Retained earnings		514,032			409,698
Total stockholders' equity		2,494,090			2,469,946
Long-term debt obligations  (Note 7)		3,520,877			3,421,236
Total capitalization		6,014,967			5,891,182
Current liabilities:
Long-term debt due within one year  (Note 7)		985			140,500
Notes payable  (Note 7)		180,000			80,000
Accounts payable and accrued liabilities		199,978			246,394
Federal, state and local taxes payable		41,100			4,293
Accrued interest		57,363			40,061
Natural gas imbalances - payable		141,095			322,200
Derivative instruments (Notes 10 and 11)		74,130			97,008
Asset retirement obligations		28,548			45,971
Other		82,122			77,928
Total current liabilities		805,321			1,054,355
Deferred credits		200,935			223,950
Accumulated deferred income taxes		991,009			905,587
Commitments and contingencies  (Note 12)
Total stockholders' equity and liabilities	$	8,012,232		$	8,075,074

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

5

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(UNAUDITED)

	Nine Months Ended September 30,
	2010			2009
	(In thousands)
Cash flows provided by (used in) operating activities:
Net earnings	$	168,680		$	126,456
Adjustments to reconcile net earnings to net cash flows
provided by operating activities:
Depreciation and amortization		170,058			159,316
Deferred income taxes		90,158			93,856
Provision for bad debts		12,586			14,088
Unrealized loss on commodity derivatives		12,589			5,597
Share-based compensation expense		6,967			5,537
Earnings from unconsolidated investments, adjusted for cash distributions		(72,012	)		(63,688	)
Loss on assets		238			5,491
Changes in operating assets and liabilities		(28,831	)		117,760
Net cash flows provided by operating activities		360,433			464,413
Cash flows used in investing activities:
Additions to property, plant and equipment		(209,826	)		(316,880	)
Contributions to unconsolidated investments		(7,500	)		-
Plant retirements and other		(1,244	)		(2,542	)
Net cash flows used in investing activities		(218,570	)		(319,422	)
Cash flows provided by (used in) financing activities:
Increase (decrease) in book overdraft		(11,983	)		3,869
Issuance of long-term debt		100,822			302,582
Renewal cost for credit facilities and issuance cost of debt		(7,051	)		(3,938	)
Dividends paid on common stock		(55,994	)		(55,814	)
Dividends paid on preferred stock		(7,211	)		(6,512	)
Repayment of long-term debt obligation		(140,831	)		(60,623	)
Net borrowings (payments) under credit facilities		100,000			(321,459	)
Redemption of preferred stock		(115,000	)		-
Other		1,962			(377	)
Net cash flows used in financing activities		(135,286	)		(142,272	)
Change in cash and cash equivalents		6,577			2,719
Cash and cash equivalents at beginning of period		10,545			4,318
Cash and cash equivalents at end of period	$	17,122		$	7,037

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

6

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

(UNAUDITED)

														Accumulated
	Common		Preferred			Premium				Common		Deferred		Other				Total
	Stock,		Stock,			on		Treasury		Stock		Compen-		Compre-				Stock-
	$1 Par		No Par			Capital		Stock,		Held		sation		hensive		Retained		holders'
	Value		Value			Stock		at cost		In Trust		Plans		Loss		Earnings		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
Redemption of preferred stock (Note 17)		-		(115,000	)		3,295		-		-		-		-		(3,295)		(115,000	)
Comprehensive income:
Net earnings		-		-			-		-		-		-		-		168,680		168,680
Net change in other
comprehensive income (Note 6)		-		-			-		-		-		-		22,586		-		22,586
Comprehensive income																			191,266
Preferred stock dividends		-		-			-		-		-		-		-		(5,040)		(5,040	)
Common stock dividends declared		-		-			-		-		-		-		-		(56,011)		(56,011	)
Share-based compensation		-		-			6,967		-		-		-		-		-		6,967
Restricted stock issuances		8		-			452		-		-		-		-		-		460
Exercise of stock options and SARs		89		-			1,519		(106)		-		-		-		-		1,502
Contributions to Trust		-		-			-		-		(584)		584		-		-		-
Disbursements from Trust		-		-			-		-		1,694		(1,694)		-		-		-
Balance September 30, 2010	$	125,666	$	-		$	1,917,526	$	(29,215)	$	(10,659)	$	10,659	$	(33,919)	$	514,032	$	2,494,090

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 condensed consolidated financial statements.

7

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The accompanying unaudited interim condensed consolidated financial statements of the Companyhave been prepared pursuant to the rules and regulations of the SEC for quarterly reports on Form 10-Q.  These statements do not include all of the information and annual note disclosures required by GAAP, and should be read in conjunction with the Company’s financial statements and notes thereto for the year ended December 31, 2009, which are included in the Company’s Form 10-K filed with the SEC.  The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with GAAP and reflect adjustments that are, in the opinion of management, necessary for a fair statement of results for the interim period. 
60;The year-end condensed balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.  Due to the seasonal nature of the Company’s operations, the results of operations and cash flows for any interim period are not necessarily indicative of the results that may be expected for the full year.  Certain reclassifications have been made to the prior year’s condensed financial statements to conform to the current year presentation.

1.  Description of Business

Southern Union owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the gathering, treating, processing, transportation, storage and distribution of natural gas in the United States.  The Company operates in three reportable segments:  Transportation and Storage, Gathering and Processing, and Distribution.  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 also provides LNG terminalling and regasification services.  The Gathering and Processing segment is primarily engaged in the gathering, treating, processing and redelivery of natural gas and NGL in West Texas and Southeast New Mexico.  The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts.

2. New Accounting Principles and Other Matters

Accounting Standards 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.

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.

Other Matters.

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.

8

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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.  The analysis as of December 31, 2009 indicated no recoverability issues were evident.

As there were no indicators of potential impairment during 2010, the impairment test was not performed as of September 30, 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 would increase without necessarily generating additional revenues unless the incremental costs are recovered through future rate proceedings or additional throughput.  See Note 14 – Regulation and Rates – Sea Robin for information related to the surcharge filing.  If the amount of the estimated Sea Robin insurance reimbursements are significantly reduced o r 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.

3.  Inventories

In the Transportation and Storage segment, inventories consist of natural gas held for operations and materials and supplies, both of which are stated 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 fractionated NGL, non-fractionated Y-grade NGL and materials and supplies, which are stated at the lower of weighted average cost or market.

In the Distribution segment, inventories consist of natural gas in underground storage and materials and supplies.  The natural gas 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.

9

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

	Transportation & Storage		Gathering & Processing		Distribution		Total
At September 30, 2010	(In thousands)
Current
Natural gas (1)	$	81,066	$	-	$	74,191	$	155,257
Materials and supplies		16,631		9,380		3,986		29,997
NGL (2)		-		8,184		-		8,184
Total Current		97,697		17,564		78,177		193,438
Non-Current
Natural gas (1)		7,272		-		-		7,272
	$	104,969	$	17,564	$	78,177	$	200,710
At 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 September 30, 2010 and December 31, 2009 were 20,705,000 MMBtu and 35,039,000 MMBtu, respectively.  Natural gas volumes in the Distribution segment at September 30, 2010 and December 31, 2009 were 16,983,000 MMBtu and 11,742,000 MMBtu, respectively.

(2)     NGL at September 30, 2010 and December 31, 2009 were 10,484,000 gallons and 6,680,000 gallons, respectively.

4. 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 common stock equivalents from stock options, restricted stock and SARs.  A reconciliation of the shares used in the basic and diluted earnings per share calculations is shown in the following table for the periods presented.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
	(In thousands)
Weighted average shares outstanding - Basic		124,484		124,057		124,458		124,050
Add assumed vesting of restricted stock		154		88		123		61
Add assumed exercise of stock options and SARs		522		423		525		162
Weighted average shares outstanding - Diluted		125,160		124,568		125,106		124,273

10

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
	(In thousands, except per share amounts)
Options excluded		1,212		1,287		1,212		1,625
Exercise price of options excluded	$23.62 - $28.48		$22.68 - $28.48		$23.62 - $28.48		$16.83 - $28.48
SARs excluded		402		386		402		386
Exercise price ranges of SARs excluded	$24.04 - $28.48		$28.07 - $28.48		$24.04 - $28.48		$28.07 - $28.48
Weighted-average market price	$23.23		$19.47		$23.56		$16.61

5. Unconsolidated Investments

Unconsolidated investments at September 30, 2010 and December 31, 2009 included the Company’s 50 percent, 50 percent, 29 percent and 49.9 percent investments in Citrus, Grey Ranch, Lee 8 Partnership and PEI II, LLC, respectively.  The Company accounts for these investments using the equity method.  Citrus’ operations are primarily conducted through Florida Gas, its wholly-owned subsidiary.  The Company’s share of net earnings or loss from these equity investments is recorded in Earnings from unconsolidated investments in the unaudited interim Condensed Consolidated Statement of Operations.

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

	September 30,		December 31,
	2010		2009
	(In thousands)
Citrus	$	1,392,174	$	1,310,765
Other		26,912		29,283
	$	1,419,086	$	1,340,048

11

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

	Three Months Ended September 30,
	2010				2009
	Citrus		Other		Citrus		Other
			(In thousands)
Revenues	$	146,543	$	6,237	$	141,083	$	5,548
Operating income		83,124		3,343		81,599		3,842
Net earnings		55,182		3,354		40,325		3,801

	Nine Months Ended September 30,
	2010				2009
	Citrus		Other		Citrus		Other
			(In thousands)
Revenues	$	401,254	$	17,921	$	389,306	$	14,655
Operating income		212,818		9,825		214,142		7,762
Net earnings		131,269		9,624		104,839		7,632

Citrus Dividends.  Citrus did not pay dividends to the Company during the nine-month periods ended September 30, 2010 and 2009.

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

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 the spring of 2011, at a currently estimated cost of approximately $2.4 billion, including capitalized equity and debt costs.  Approximately $1.74 billion of capital costs have been recorded as of September 30, 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.

Prior to the in-service date of the Phase VIII Expansion project, it is expected Citrus will require sponsor provided contributions from each of its shareholders of up to $250 million.  The majority of the sponsor provided contributions to Citrus will be made in the fourth quarter of 2010 and/or first quarter of 2011.  Citrus plans to resume cash distributions 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 cert ain surcharges.  The new rates went into effect on April 1, 2010, subject to refund pending the final outcome of the rate proceeding.  An $11.8 million provision for estimated refunds through September 30, 2010 has been established for refunds on certain rate schedules for which a refund is potentially applicable.  The ultimate resolution of such refunds will be determined by settlement or adjudication.

On September 3, 2010, Florida Gas filed a proposed settlement with FERC.  The proposed settlement was supported by all parties with the exception of one non-rate provision that was opposed by one party.  It is expected the Administrative Law Judge will issue an order on the proposed settlement during the fourth quarter of 2010, at which time the proposed settlement would go to the full Commission for final action.  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.  In addition, depreciation rates are proposed to be reduced effective April 1, 2010, which if approved, would correspondingly increas e the provision for refund for the period ended September 30, 2010 by approximately $6.5 million.  The proposed settlement is not expected to have a material impact on the Company’s equity investment in Citrus.

12

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 will use the net proceeds to partially fund the Phase VIII Expansion project and for general corporate purposes, which includes the repayment of a portion of Florida Gas’ outstanding debt.  On July 19, 2010, Florida Gas: (i) issued a notice of its election to redeem, on August 19, 2010, its $325 million of 7.625% notes due December 1, 2010, (ii) made a $98.6 million distribution to Citrus, (iii) repaid $83 million that was outstanding under its credit agreements, and (iv) invested the remainder of the proceeds.  The $325 million of 7.625% notes were redeemed on August 19 , 2010.

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.  At a hearing on July 12, 2010, the judge granted the FDOT/FTE motion for reconsideration of certain issues.  The judge also scheduled the trial for the first quarter of 2011.

6.  Comprehensive Income (Loss)

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(In thousands)
Net Earnings	$	37,331		$	46,919		$	168,680		$	126,456
Changes in Other Comprehensive Income (Loss):
Change in fair value of interest rate hedges, net of tax of $(1,459),
$(2,474), $(5,073) and $(2,062), respectively		(2,172	)		(3,681	)		(7,547	)		(3,068	)
Reclassification of unrealized loss on interest rate hedges into
earnings, net of tax of $2,186, $2,257, $6,740 and $5,833,
respectively		3,261			3,388			10,064			8,767
Change in fair value of commodity hedges, net of tax of $4,707,
$(3,496), $14,320 and $1,011, respectively		8,352			(6,205	)		25,413			1,794
Reclassification of unrealized gain on commodity hedges into
earnings, net of tax of $(2,019), $(4,809), $(4,291) and $(12,983),
respectively		(3,584	)		(8,534	)		(7,616	)		(23,040	)
Reclassification of net actuarial loss and prior service credit
relating to pension and other postretirement benefits into
earnings, net of tax of $549, $736, $1,651 and $2,208,
respectively		723			974			2,165			2,920
Change in other comprehensive income (loss) from equity
investments, net of tax of $22, $(1,646), $66 and $(1,646),
respectively		36			(2,661	)		107			(2,661	)
Total other comprehensive income (loss)		6,616			(16,719	)		22,586			(15,288	)
Total comprehensive income	$	43,947		$	30,200		$	191,266		$	111,168

13

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

7. Debt Obligations

The following table sets forth the debt obligations of Southern Union and applicable units of Panhandle under their respective notes and bonds at the dates indicated.

	September 30, 2010				December 31, 2009
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
Long-Term Debt Obligations:
Southern Union:
7.60% Senior Notes due 2024	$	359,765	$	419,169	$	359,765	$	389,820
8.25% Senior Notes due 2029		300,000		351,009		300,000		337,800
7.24% to 9.44% First Mortgage Bonds
due 2020 to 2027		19,500		22,576		19,500		21,403
6.089% Senior Notes due 2010		-		-		100,000		100,250
7.20% Junior Subordinated Notes due 2066  (1)		600,000		546,378		600,000		510,000
Term Loan due 2011 (2)		250,000		249,943		150,000		150,178
Note Payable		8,216		8,216		7,725		7,725
		1,537,481		1,597,291		1,536,990		1,517,176
Panhandle:
6.05% Senior Notes due 2013		250,000		272,418		250,000		269,733
6.20% Senior Notes due 2017		300,000		330,834		300,000		319,455
8.125% Senior Notes due 2019		150,000		182,532		150,000		173,111
8.25% Senior Notes due 2010		-		-		40,500		41,143
7.00% Senior Notes due 2029		66,305		72,773		66,305		69,866
7.00% Senior Notes due 2018		400,000		455,368		400,000		434,560
Term Loans due 2012		815,391		795,988		815,391		758,108
Net premiums on long-term debt		2,685		2,685		2,550		2,550
		1,984,381		2,112,598		2,024,746		2,068,526
Total Long-Term Debt Obligations		3,521,862		3,709,889		3,561,736		3,585,702
Credit Facilities		180,000		182,924		80,000		78,968
Total consolidated debt obligations		3,701,862	$	3,892,813		3,641,736	$	3,664,670
Less current portion of long-term debt		985				140,500
Less short-term debt		180,000				80,000
Total long-term debt	$	3,520,877			$	3,421,236

____________________

(1)   Effective November 1, 2011, the Company can elect to redeem this debt obligation at par.  If the Company elects to not 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.

The fair value of the Company’s term loans and credit facilities as of September 30, 2010 and December 31, 2009 was 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.

14

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The fair value of the Company’s other long-term debt as of September 30, 2010 and December 31, 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. 

2010 Term Loan.  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 and may be prepaid without penalty at any time.  The 2010 Term Loan amended, restated and upsized that certain $150 million Credit Agreement, which was issued in 2009 and was scheduled to mature on August 5, 2011 (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 existi ng indebtedness under the 2009 Term Loan described above, with the remaining proceeds to be used to provide working capital and for general corporate purposes.

Retirement of 2010 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 its credit facilities.

15

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

8. Employee Benefits

Components of Net Periodic Benefit Cost.The following table sets forth the components of net periodic benefit cost of the Company’s pension and postretirement benefit plans for the periods presented below.

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended September 30,						Three Months Ended September 30,
	2010			2009			2010			2009
	(In thousands)
Service cost	$	767		$	738		$	792		$	749
Interest cost		2,510			2,524			1,410			1,348
Expected return on plan assets		(2,337	)		(2,069	)		(1,270	)		(771	)
Prior service cost (credit) amortization		138			138			(412	)		(317	)
Actuarial (gain) loss amortization		1,997			2,101			(450	)		(212	)
Sub-total		3,075			3,432			70			797
Regulatory adjustment  (1)		52			(125	)		667			667
Net periodic benefit cost	$	3,127		$	3,307		$	737		$	1,464

	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
	(In thousands)
Service cost	$	2,302		$	2,213		$	2,378		$	2,248
Interest cost		7,529			7,572			4,229			4,043
Expected return on plan assets		(7,011	)		(6,209	)		(3,581	)		(2,315	)
Prior service cost (credit) amortization		414			414			(1,235	)		(951	)
Actuarial (gain) loss amortization		5,990			6,304			(1,351	)		(636	)
Sub-total		9,224			10,294			440			2,389
Regulatory adjustment  (1)		209			(375	)		1,999			1,999
Net periodic benefit cost	$	9,433		$	9,919		$	2,439		$	4,388

____________________

(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 determined by the applicable utility commission.

9. Taxes on Income

The following table summarizes the Company’s income taxes for the periods presented.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(In thousands)
Income tax expense	$	16,525		$	19,720		$	75,943		$	53,170
Effective tax rate		31	%		30	%		31	%		30	%

16

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

In March 2010, the Patient Protection and Affordable Care Act (PPACA) and the Health Care and Education Reconciliation Act of 2010 were signed into law.  The PPACA changed the tax treatment of federal Medicare Part D subsidies paid to sponsors of retiree health benefit plans.  As a result of this legislation, the Company’s tax deduction associated with retiree health benefit plans will be reduced by Medicare Part D subsidies received in tax years beginning after December 31, 2012. Accordingly, the Company recorded $4.2 million of additional tax expense in the first quarter of 2010, resulting in an increase to the EITR for the first quarter of 2010.

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 li abilities at fair value in the Condensed Consolidated Balance Sheet.

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 September 30, 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 September 30, 2010, approximately $11.9 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 September 30, 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 September 30, 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 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 September 30, 2010, the Company had outstanding receive-fixed natural gas price swaps with a total notional amount of 4,140,000 MMBtus and 9,125,000 MMBtus for the remainder of 2010 and 2011, respectively.   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 September 30, 2010, ap proximately $13.1 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.

17

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

NGL Processing Spread Swaps.  As of September 30, 2010, the Company had outstanding receive-fixed NGL processing spread swaps with a total notional amount of 3,680,000 MMBtu and 9,125,000 MMBtu equivalents for the remainder of 2010 and 2011, respectively.  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.

Natural Gas Price Swaps.  As of September 30, 2010, the Company had outstanding pay-fixed natural gas price swaps with total notional amounts of 4,870,000 MMBtus, 19,560,000 MMBtus and 7,640,000 MMBtus for the remainder of 2010, 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.

18

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 Condensed Consolidated Balance Sheet at the dates indicated.

		Asset Derivative Instruments (1)
	Balance Sheet	Fair Value
	Location	September 30, 2010		December 31, 2009
		(In thousands)
Cash Flow Hedges:
Commodity contracts - Gathering and Processing:
Natural gas price swaps	Prepayments and other assets	$	17,335	$	-
	Other noncurrent assets		3,682		-
	Derivative instruments-liabilities		2,997		-
	Deferred credits		-		314
		$	24,014	$	314
Economic Hedges:
Commodity contracts - Gathering and Processing:
Other derivative instruments	Prepayments and other assets	$	-	$	5
	Derivative instruments-liabilities		34		166
Commodity contracts - Distribution:
Natural gas price swaps	Derivative instruments-liabilities		17		582
	Deferred credits		86		15
		$	137	$	768
Other:
Commodity contracts - Gathering and Processing:
Other derivative instruments	Prepayments and other assets	$	227	$	162
Total		$	24,378	$	1,244

_____________

(1) The Company has master netting arrangements with certain of its counterparties, which permit applicable obligations of the parties to be settled on a net versus gross basis.  In those instances where a right of offset exists, the fair value amounts for the derivative instruments are reported in the Condensed Consolidated Balance Sheet on a net basis and disclosed herein on a gross basis.

19

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

		Liability Derivative Instruments (1)
Balance Sheet		Fair Value
Location		September 30, 2010		December 31, 2009
		(In thousands)
Cash Flow Hedges
Interest rate contracts:
Interest rate swaps	Derivative instruments-liabilities	$	19,897	$	18,754
Deferred credits			9,489		13,975
Commodity contracts - Gathering and Processing:
Natural gas price swaps	Derivative instruments-liabilities		-		4,126
		$	29,386	$	36,855
Economic Hedges
Commodity contracts - Gathering and Processing:
NGL processing spread swaps	Prepayments and other assets	$	14,444	$	-
Other noncurrent assets			1,797		-
Derivative instruments-liabilities			12,128		34,477
Deferred credits			1,362		10,410
Other derivative instruments	Derivative instruments-liabilities		237		193
Commodity contracts - Distribution:
Natural gas price swaps	Derivative instruments-liabilities		44,916		40,206
Deferred credits			4,994		3,991
		$	79,878	$	89,277
Other
Commodity contracts - Gathering and Processing:
Other derivative instruments	Prepayments and other assets	$	-	$	30
Total		$	109,264	$	126,162

_____________

(1) The Company has master netting arrangements with certain of its counterparties, which permit applicable obligations of the parties to be settled on a net versus gross basis.  In those instances where a right of offset exists, the fair value amounts for the derivative instruments are reported in the Condensed Consolidated Balance Sheet on a net basis and disclosed herein on a gross basis.

20

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The following table summarizes the location and amount of derivative instrument gains and losses for the periods presented.

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2010		2009			2010			2009
Cash Flow Hedges:  (1)	(In thousands)
Interest rate contracts:
Change in fair value - increase in Accumulated other
comprehensive loss, excluding tax expense effect
of $1,459, $2,474, $5,073 and $2,062, respectively	$	3,631	$	6,155		$	12,620		$	5,130
Reclassification of unrealized loss from Accumulated other
comprehensive loss - increase of Interest expense, excluding tax
expense effect of $2,186, $2,257, $6,740 and $5,833, respectively		5,447		5,645			16,804			14,600
Commodity contracts - Gathering and Processing:
Change in fair value - (increase) decrease in Accumulated other
comprehensive loss, excluding tax expense effect
of $4,707, $(3,496), $14,320 and $1,011, respectively		13,059		(9,701	)		39,733			2,805
Reclassification of unrealized gain from Accumulated other
comprehensive loss - increase of Operating Revenues,
excluding tax expense effect of $2,019, $4,809,
$4,291 and $12,983, respectively		5,603		13,343			11,907			36,023
Economic Hedges:
Commodity contracts - Gathering and Processing:
Change in fair value of strategic hedges - (increase) decrease in
Operating revenues (2)		29,180		(1,851	)		14,508			32,799
Change in fair value of other hedges - (increase) decrease
in Operating revenues		279		(461	)		465			20
Commodity contracts - Distribution:
Change in fair value - (increase) decrease in Deferred natural gas
purchases		(13,914)		25,682			(6,207)			47,403
Other:
Commodity contracts - Gathering and Processing:
Change in fair value - (increase) decrease in Operating revenues		54		595			(96	)		757

_________________

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

(2)   Includes $7.7 million and $27.7 million of the cash settlement impact for previously recognized unrealized losses in the three-month and nine-month periods ended September 30, 2010, respectively. Includes $15.6 million and $44.8 million of the cash settlement impact for previously recognized unrealized gains in the three-month and nine-month periods ended September 30, 2009, respectively.  Additionally, includes $29.2 million and $12.6 million of unrealized mark-to-market losses recorded in the three-month and nine-month periods ended September 30, 2010, respectively, and $15.1 million of unrealized mark-to-market gains and $6 million of unrealized mark-to-market losses recorded in the three-month and nine-month periods ended September 30, 2009, respectively.

Derivative Instrument Contingent Features

Certain of the Company’s derivative instruments contain provisions that require the Company’s debt to be maintained at an investment grade credit rating from each of the major credit rating agencies.  If the Company’s debt were to fall below investment grade, the Company would be in violation of these provisions, and the counterparties to the derivative instruments could potentially require the Company to post collateral for certain of the derivative instruments.  The aggregate fair value of all derivative instruments with credit risk-related contingent features that are in a net liability position at September 30, 2010 is $38.2 million.

21

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

11. Fair Value Measurement

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

			Fair Value Measurements at September 30, 2010
			Using Fair Value Hierarchy
			Quoted Prices in
	Fair Value		Active Markets for		Significant Other
	as of		Identical Assets		Observable Inputs
	September 30, 2010		(Level 1)		(Level 2)
	(In thousands)
Assets:
Commodity derivatives  (1)	$	5,003	$	-	$	5,003
Long-term investments		865		865		-
Total	$	5,868	$	865	$	5,003
Liabilities:
Commodity derivatives  (1)	$	60,503	$	211	$	60,292
Interest-rate derivatives  (1)		29,386		-		29,386
Total	$	89,889	$	211	$	89,678

__________________

(1)   See related information in Note 10 – Derivative Instruments and Hedging Activities.

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 using pricing models based on an income approach that discounts future cash flows to a present value amount.  The significant pricing model inputs for natural gas and NGL processing spread swap derivatives include published NYMEX forward index prices for delivery of natural gas at Henry Hub, Permian Basin and Waha, and NGL at Mont Belvieu.  The significant pricing model inputs for interest-rate swaps include published rates for U.S. Dollar LIBOR interest rate swaps. 0; The pricing models also adjust for nonperformance risk associated with the counterparty or Company, as applicable, through the use of credit risk adjusted discount rates based on published default rates.  The Company did not have any Level 3 instruments measured at fair value using significant unobservable inputs at September 30, 2010 or December 31, 2009.

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

12. 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 damage s 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.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The Company’s environmental remediation activities are undertaken in cooperation with and under the oversight of appropriate regulatory agencies, enabling the Company under certain circumstances to take advantage of various voluntary cleanup programs in order to perform the remediation in the most effective and efficient manner.  The costs incurred by the Company while performing such remediation is included in the estimates associated with probable environmental response actions.

The Company is allowed to recover environmental remediation expenditures through rates 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 at the dates indicated to cover probable environmental response actions.

	September 30,		December 31,
	2010		2009
	(In thousands)
Current	$	6,176	$	7,745
Noncurrent		15,916		16,964
Total environmental liabilities	$	22,092	$	24,709

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 believ es such costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

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.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 gen erally 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.

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.  SUGS settled four NMED enforcement actions that were originally assessed at approximately $340,000 by the NMED for approximately $12,000.  The Company believes the outcome of this matter will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

24

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Distribution Segment Environmental Matters

The Company is responsible for environmental remediation at various contaminated sites that are primarily associated with former MGPsand 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 manageme nt 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 $9.3 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 Condensed Consolidated Balance Sheet.

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 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 alleging violation of permitting requirements under the federal RCRA and notification re quirements 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 Court imposed a fine of $6 million and a payment of $12 million in community service.  The sentence has been suspended while the Company pursues an appeal of the conviction and the sentence.  The Company filed a Notice of Appeal to the U.S. Court of Appeals for the First Circuit and oral argument was held on October 6, 2010.  The Company believes the outcome of this matter will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

25

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 lawsui t (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) and 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.

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 Harr is County, Texas.  The trial date is currently set for the first quarter of 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 2010 Debt Obligations for information related to the Company’s debt maturing in 2010.  

Regulation and Rates.  See Note 14 – Regulation and Rates for potential contingent matters associated with the Company’s regulated operations.

13. 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.

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.

26

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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.

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.

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 three- and nine-month periods ended September 30, 2010 and 2009.

27

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2010			2009		2010		2009
	(In thousands)
Revenues from external customers:
Transportation and Storage	$	186,563		$	176,093	$	560,328	$	541,003
Gathering and Processing		214,893			189,557		758,460		532,946
Distribution		82,141			71,393		490,113		497,949
Total segment operating revenues		483,597			437,043		1,808,901		1,571,898
Corporate and other activities		3,930			1,408		10,716		3,441
Total consolidated revenues from external
customers	$	487,527		$	438,451	$	1,819,617	$	1,575,339
Depreciation and amortization:
Transportation and Storage	$	31,191		$	28,338	$	91,264	$	84,684
Gathering and Processing		17,151			16,733		52,442		49,689
Distribution		8,216			7,880		24,139		23,359
Total segment depreciation and amortization		56,558			52,951		167,845		157,732
Corporate and other activities		747			535		2,213		1,584
Total depreciation and amortization expense	$	57,305		$	53,486	$	170,058	$	159,316
Earnings from unconsolidated investments:
Transportation and Storage	$	30,768		$	22,715	$	73,762	$	60,483
Gathering and Processing		1,017			1,338		3,397		2,364
Corporate and other activities		551			368		1,297		841
	$	32,336		$	24,421	$	78,456	$	63,688
Segment performance:
Transportation and Storage EBIT	$	112,099		$	101,120	$	325,770	$	292,264
Gathering and Processing EBIT		(11,366	)		7,734		35,715		(5,222	)
Distribution EBIT		6,299			5,103		42,009		36,450
Total segment EBIT		107,032			113,957		403,494		323,492
Corporate and other activities		2,063			2,916		2,680		3,103
Interest expense		55,239			50,234		161,551		146,969
Federal and state income tax expense		16,525			19,720		75,943		53,170
Net earnings		37,331			46,919		168,680		126,456
Preferred stock dividends		699			2,171		5,040		6,512
Loss on extinguishment of preferred stock		-			-		3,295		-
Net earnings available for common stockholders	$	36,632		$	44,748	$	160,345	$	119,944

28

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

	September 30,			December 31,
	2010			2009
	(In thousands)
Total assets:
Transportation and Storage	$	5,059,808		$	5,138,042
Gathering and Processing		1,670,539			1,666,935
Distribution		1,085,485			1,109,492
Total segment assets		7,815,832			7,914,469
Corporate and other activities		196,400			160,605
Total consolidated assets	$	8,012,232		$	8,075,074
	Three Months Ended					Nine Months Ended
	September 30,					September 30,
		2010			2009		2010		2009
	(In thousands)
Expenditures for long-lived assets:
Transportation and Storage	$	58,363		$	75,966	$	114,620	$	205,854
Gathering and Processing		15,580			12,887		57,286		29,405
Distribution		11,796			11,244		28,051		34,512
Total segment expenditures for
long-lived assets		85,739			100,097		199,957		269,771
Corporate and other activities		(2,185	)		7,179		4,096		24,182
Total consolidated expenditures for
long-lived assets  (1)	$	83,554		$	107,276	$	204,053	$	293,953

­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­__________________________________

(1)   ­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­ Related cash impact includes the net reduction in capital accruals totaling $0.8 million and $8.8 million for the three-month periods ended September 30, 2010 and 2009, respectively.  Related cash impact includes the net reduction in capital accruals totaling $8.7 million and $19.2 million for the nine-month periods ended September 30, 2010 and 2009, respectively.

14. Regulation and Rates

Sea Robin.  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 in surance and surcharge recoveries, which were reflected in the updated surcharge rate effective October 1, 2010, subject to refund.  The ultimate outcome of this matter is pending a FERC decision.

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 rel ated 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.

29

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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.  On October 8, 2010, the MDPU issued an order seeking com ments 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.  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 November 13, 2009, New England Gas Company made a filing with the MDPU, seeking recovery of approximately $1.7 million, or 50 percent of the amount by which its 2008 earnings deficiency 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.  By order issued in February 2010, the MDPU will hold this matter in abeyance pending judicial resolution of the issues pertaining to an appeal of a similar filing regarding an earnings deficiency in 2007.

15. Stockholders’ Equity

Dividends.  The table below presents the amount of cash dividends declared and paid on the dates indicated:

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

16. Other Income and Expense Items

Other, net income for the three-month period ended September 30, 2009 totaling $2.3 million consists primarily of the collection of a $1.8 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.

Other, net income for the nine-month period ended September 30, 2009 totaling $8.4 million consists primarily of $5.7 million related to an insurance settlement the Company entered into with an insurance company releasing the insurance company from certain potential future environmental claim obligations and collection of a $1.8 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.

17. Redemption of Preferred Stock

On July 30, 2010, the Company redeemed all outstanding 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 $25 per share, which totaled $115 million.  The Company recognized a $3.3 million loss adjustment charged to Retained earnings related to the write-off of issuance costs that reduced Net earnings available for common stockholders.

30

ITEM 2.                        Management’s Discussion and Analysis of Financial Condition and Results of Operations.

INTRODUCTION

Management’s Discussion and Analysis of Financial Condition and Results of Operations is provided as a supplement to the accompanying unaudited interim condensed consolidated financial statements and notes to help provide an understanding of the Company’s financial condition, changes in financial condition and results of operations.  The following section includes an overview of the Company’s business as well as recent developments that management of the Company believes are important in understanding its results of operations and 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 ca pital resources, quantitative and qualitative disclosures about market risk and other matters.

OVERVIEW

The Company’s business purpose is to provide gathering, treating, 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.  The Company operates in three reportable segments:  Transportation and Storage, Gathering and Processing, and Distribution.

RESULTS OF OPERATIONS

Overview

The Company evaluates operational and financial segment performance using several factors, of which the primary financial measure is EBIT, which is a non-GAAP measure.  For additional information related to the Company’s use of EBIT as its primary financial measure for its reportable segments, see Part I, Item I. Financial Statements (Unaudited), Note 13 – Reportable Segments.

31

The following table provides a reconciliation of EBIT (by segment) to Net earnings available for common stockholders for the periods presented.

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2010			2009		2010		2009
	(In thousands)
EBIT:
Transportation and storage segment	$	112,099		$	101,120	$	325,770	$	292,264
Gathering and processing segment		(11,366	)		7,734		35,715		(5,222	)
Distribution segment		6,299			5,103		42,009		36,450
Corporate and other activities		2,063			2,916		2,680		3,103
Total EBIT		109,095			116,873		406,174		326,595
Interest		55,239			50,234		161,551		146,969
Earnings before income taxes		53,856			66,639		244,623		179,626
Federal and state income taxes		16,525			19,720		75,943		53,170
Net earnings		37,331			46,919		168,680		126,456
Preferred stock dividends		699			2,171		5,040		6,512
Loss on extinguishment of preferred stock		-			-		3,295		-
Net earnings available for common stockholders	$	36,632		$	44,748	$	160,345	$	119,944

Three-month period ended September 30, 2010 versus the three-month period ended September 30, 2009.  The Company’s $8.1 million decrease in Net earnings available for common stockholders was primarily due to:

·   Lower EBIT contribution of $19.1 million from the Gathering and Processing segment primarily resulting from a $46.7 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 the impact of a net hedging loss of $23.9 million in the 2010 period versus a net hedging gain of $15.1 million in the 2009 period, partially offset by higher operating revenues of $64.3 million, excluding hedging gains and losses, attributable to higher market-driven realized average natural gas and NGL prices; and

·   Higher interest expense of $5 million primarily attributable to the impact of the lower level of interest costs capitalized attributable to lower average capital project balances outstanding.

These reductions in earnings were partially offset by:

·   Higher EBIT contribution of $11 million from the Transportation and Storage segment mainly due to higher equity earnings of $8.1 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 $2.9 million primarily due to higher operating revenue of $10.5 million, partially offset by higher operating, maintenance and general expenses of $4.2 million and higher depreciation and amortization expense of $2.9 million;

·   Higher EBIT contribution of $1.2 million from the Distribution segment primarily due to higher net operating revenues at Missouri Gas Energy of $4.4 million largely attributable to the impact of the new customer rates effective February 28, 2010, partially offset by higher operating, maintenance and general expenses of $2.9 primarily attributable to higher pension costs; and

·   Lower federal and state income tax expense of $3.2 million primarily due to lower pre-tax earnings of $12.8 million in 2010.

32

Nine-month period ended September 30, 2010 versus the nine-month period ended September 30, 2009.  The Company’s $40.4 million increase in Net earnings available for common stockholders was primarily due to:

·   Higher EBIT contribution of $40.9 million from the Gathering and Processing segment primarily resulting from higher operating revenues of $230.9 million, excluding hedging gains and losses, attributable to higher market-driven realized average natural gas and NGL prices, partially offset by a $184.6 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;

·   Higher EBIT contribution of $33.5 million from the Transportation and Storage segment primarily due to an increased contribution from Panhandle of $20.2 million mainly due to higher LNG revenues of $45.4 million largely attributable to the LNG terminal infrastructure enhancement construction project placed in service in March 2010, partially offset by lower interruptible parking revenues of $21.4 million due to less favorable market conditions and the impact of a provision for repair and abandonment costs of $12.3 million in 2009 for damages to offshore assets resulting from Hurricane Ike.  The Transportation and Storage segment was also favorably impacted by higher equity earnings of $13.3 million primarily due to Citrus’ higher other income of $25.5 million largely attributable to higher equity AFUDC resulting from the Florida Gas Ph ase VIII Expansion project, partially offset by higher income tax expense of $8.2 million; and

·   Higher EBIT contribution of $5.6 million from the Distribution segment primarily due to higher net operating revenues at Missouri Gas Energy of $13.3 million largely attributable to the impact of the new customer rates effective February 28, 2010, partially offset by the impact of a $3.5 million settlement in 2009 with an insurance company that released it from certain potential future environmental claim obligations.

These improvements in earnings were partially offset by:

·   Higher interest expense of $14.6 million primarily attributable to the impact of the lower level of interest costs capitalized attributable to lower average capital project balances outstanding;

·   Higher federal and state income tax expense of $22.8 million primarily due to higher pre-tax earnings of $65 million in 2010; and

·   Impact of a $3.3 million loss recorded in the 2010 period related to the Company’s redemption of all of its approximately $115 million of outstanding Preferred Stock.

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.

The Company’s regulated transportation and storage businesses periodically file (or can be required to file) for changes in their rates, which are subject to approval by FERC.  Although a significant portion of the Company’s contracts are discounted or negotiated rate contracts, changes in rates and other tariff provisions resulting from these regulatory proceedings have the potential to impact negatively the Company’s results of operations and financial condition.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
	(In thousands)
Operating revenues	$	186,563	$	176,093	$	560,328	$	541,003
Operating, maintenance and general		65,322		61,127		190,228		199,302
Depreciation and amortization		31,191		28,338		91,264		84,684
Taxes other than on income and revenues		8,731		8,398		26,856		25,636
Total operating income		81,319		78,230		251,980		231,381
Earnings from unconsolidated investments		30,768		22,715		73,762		60,483
Other income, net		12		175		28		400
EBIT	$	112,099	$	101,120	$	325,770	$	292,264
Operating information:
Panhandle natural gas volumes transported (TBtu)		326		331		1,027		1,134
Florida Gas natural gas volumes transported (TBtu) (1)		241		233		644		636

________________

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

Three-month period ended September 30, 2010 versus the three-month period ended September 30, 2009.  The $11 million EBIT improvement in the three-month period ended September 30, 2010 versus the same period in 2009 was primarily due to higher equity earnings of $8.1 million, mainly from the Company’s unconsolidated investment in Citrus and a higher EBIT contribution from Panhandle totaling $2.9 million.

Equity earnings, mainly attributable to the Company’s unconsolidated investment in Citrus, were higher by $8.1 million in 2010 versus 2009 primarily due to the following items, adjusted where applicable to reflect the Company’s proportional equity share:

·   Higher other income of $10.9 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 $2.8 million primarily due to certain higher rates associated with the Florida Gas rate case filing effective April 1, 2010 and higher short-term firm reservation revenues, partially offset by the provision for an estimated rate refund related to the Florida Gas rate case filing and lower transportation commodity revenues due to lower interruptible volumes;

·   Lower debt interest cost of $800,000 primarily due to higher capitalized debt AFUDC, largely attributable to higher Phase VIII Expansion project capital expenditures and lower interest expense resulting from the repayment of the $325 million 7.625% Senior Notes in August 2010, partially offset by higher interest on the $500 million 5.45% Senior Notes and the $350 million 4.00% Senior Notes issued in July 2010, and a higher rate on the $500 million construction and term loan, which was converted to a fixed rate of 9.393 percent in October 2009;

·   Higher operating expenses of $1.2 million primarily due to higher overall costs experienced in 2010 applicable to outside services costs, corporate services costs and other operating costs;

·   Higher depreciation expense of $900,000 primarily due to increased property, plant and equipment placed in service after September 30, 2009; and

·   Higher income tax expense of $4.6 million primarily due to higher pretax earnings.

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Panhandle’s $2.9 million EBIT improvement was primarily due to:

·   Higher operating revenues of $10.5 million primarily due to:

o   Higher LNG revenues of $20.1 million largely attributable to the LNG terminal infrastructure enhancement construction project placed in service in March 2010;

o   Lower transportation reservation revenues of $5.3 million in 2010 versus 2009 primarily due to lower average rates realized on short-term firm capacity on PEPL, in addition to lower average rates realized on Trunkline; and

o   Lower interruptible parking revenues of $5.3 million primarily due to less favorable market conditions resulting in lower rates in 2010.

The operating revenue improvement was partially offset by:

 ·   Higher operating, maintenance and general expenses of $4.2 million in 2010 versus 2009 primarily attributable to:

o   Impact of a net reduction of $3.5 million in the repair and abandonment cost provision for Hurricane Ike in the 2009 period;

o   A $1.1 million increase in administrative outside service costs primarily due to legal costs associated with ongoing litigation;

o   Higher allocated corporate services costs of $1.1 million primarily due to higher short- and long-term corporate incentive compensation;

o   A $900,000 increase in outside service costs for field operations primarily attributable to plant services  related to the LNG terminal infrastructure enhancement construction project placed in service in March 2010; and

o   Impact of a $2.8 million increase in environmental reserves in 2009 primarily attributable to estimated costs to remediate PCBs at the Company’s facilities; and

·   Increased depreciation and amortization expense of $2.9 million in 2010 versus 2009 due to a $582.4 million increase in property, plant and equipment placed in service after September 30, 2009.  Depreciation and amortization expense is expected to continue to increase primarily due to significant capital additions, including capitalized costs associated with the LNG terminal infrastructure enhancement construction project placed in service in March 2010.

Nine-month period ended September 30, 2010 versus the nine-month period ended September 30, 2009.  The $33.5 million EBIT improvement in the nine-month period ended September 30, 2010 versus the same period in 2009 was primarily due to a higher EBIT contribution from Panhandle totaling $20.2 million and higher equity earnings of $13.3 million, principally from the Company’s unconsolidated investment in Citrus.

Panhandle’s $20.2 million EBIT improvement was primarily due to:

·   Higher operating revenues of $19.3 million primarily due to:

o   Higher LNG revenues of $45.4 million largely attributable to the LNG terminal infrastructure enhancement construction project placed in service in March 2010;

o   Higher transportation commodity revenues of $3.2 million primarily due to higher volumes flowing on Sea Robin in 2010 versus in 2009, the 2009 volumes having been adversely impacted by Hurricane Ike;

o   Lower interruptible parking revenues of $21.4 million primarily due to less favorable market conditions resulting in lower rates in 2010; and

o   Lower transportation reservation revenues of $9.9 million in 2010 versus 2009 primarily due to lower average rates realized on short-term firm capacity on PEPL, in addition to lower average rates realized on Trunkline;

·  Lower operating, maintenance and general expenses of $9.1 million in 2010 versus 2009 primarily attributable to:

o   Impact of a provision for repair and abandonment costs of $12.3 million recorded in 2009 for damages to offshore assets resulting from Hurricane Ike and a reduction in 2010 in the repair and abandonment provision for previous hurricane damages of $3.6 million primarily due to project scope reductions resulting from 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 $5.5 million increase in outside service costs for field operations primarily attributable to plant services  related to the LNG terminal infrastructure enhancement construction project placed in service in March 2010 and higher in-line inspection costs;

o   Higher allocated corporate services costs of $3.6 million primarily due to higher short- and long-term corporate incentive compensation; and

o   A $2.6 million increase in legal costs primarily due to ongoing litigation; and

·   Increased depreciation and amortization expense of $6.6 million in 2010 versus 2009 due to a $582.4 million increase in property, plant and equipment placed in service after September 30, 2009.  Depreciation and amortization expense is expected to continue to increase primarily due to significant capital additions, including capitalized costs associated with the LNG terminal infrastructure enhancement construction project placed in service in March 2010.

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Equity earnings, mainly attributable to the Company’s unconsolidated investment in Citrus, were higher by $13.3 million in 2010 versus 2009 primarily due to the following items, adjusted where applicable to reflect the Company’s proportional equity share:

·   Higher other income of $25.5 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 $6 million primarily due to certain higher rates associated with the Florida Gas rate case filing effective April 1, 2010 and higher short-term firm reservation revenues, partially offset by the provision for an estimated rate refund and lower transportation commodity revenues due to lower interruptible volumes;

·   Higher debt interest cost of $3.7 million primarily due to interest on the $600 million 7.90% Senior Notes issued in May 2009, the $500 million 5.45% Senior Notes and $350 million 4.00% Senior Notes issued in July 2010, and a higher rate on the $500 million construction and term loan which was converted to a fixed rate of 9.393 percent in October 2009, partially offset by higher capitalized debt AFUDC, largely attributable to higher Phase VIII Expansion project capital expenditures;

·   Higher operating expenses of $3.3 million primarily due to higher overall costs experienced in 2010 applicable to outside services costs, corporate services costs, transportation, and other operating costs;

·   Higher depreciation expense of $2.9 million primarily due to increased property, plant and equipment placed in service after September 30, 2009; and

·   Higher income tax expense of $8.2 million primarily due to higher pretax earnings.

See Part I, Item I. Financial Statements (Unaudited), Note 5 – Unconsolidated Investments – Citrus for additional information related to Florida Gas.

Gathering and Processing Segment.  The Gathering and Processing segment is primarily engaged in connecting wells of natural gas producers to its gathering system, treating natural gas to remove impurities to meet pipeline quality specifications, processing natural gas for the removal of NGL, and redelivering natural gas and NGL to a variety of markets.  Its operations are conducted through SUGS.  SUGS’ gas supply agreements primarily include fee-based, percent-of-proceeds, minimum margin keep-whole, conditioning fee and wellhead purchase contracts.  These 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 producers, power generating companies, utilities, energy marketers, and industrial end-users located primarily in the Gulf Coast and southwestern United States.  SUGS’ business is not generally seasonal in nature.

The majority of SUGS’ gross margin is derived from the sale of NGL and natural gas equity volumes.  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 Part I, Item I. Financial Statements (Unaudited), Note 10 – Derivative Instruments and Hedging Activities – Commodity Contracts – Gathering and Processing Segment and Part I, Item 3. Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk – Gathering and Processing Segment.

 

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(In thousands)
Operating revenues, excluding impact of
commodity derivative instruments	$	238,804		$	174,498		$	761,431		$	530,499
Realized and unrealized commodity derivatives		(23,911	)		15,059			(2,971	)		2,447
Operating revenues		214,893			189,557			758,460			532,946
Cost of gas and other energy (1)		(189,156	)		(142,455	)		(611,405	)		(426,853	)
Gross margin  (2)		25,737			47,102			147,055			106,093
Operating, maintenance and general		19,897			22,736			58,260			60,521
Depreciation and amortization		17,151			16,733			52,442			49,689
Taxes other than on income and revenues		1,388			1,210			4,353			3,716
Total operating income		(12,699	)		6,423			32,000			(7,833	)
Earnings from unconsolidated investments		1,017			1,338			3,397			2,364
Other expense, net		316			(27	)		318			247
EBIT	$	(11,366	)	$	7,734		$	35,715		$	(5,222	)
Operating Statistics:
Volumes
Avg natural gas processed (MMBtu/d)		444,316			357,182			431,544			395,054
Avg NGL produced (gallons/d)		1,521,859			1,162,488			1,458,582			1,308,472
Avg natural gas wellhead volumes (MMBtu/d)		536,724			530,558			536,858			569,649
Natural gas sales (MMBtu) (3)		20,905,163			22,871,214			61,286,222			68,100,131
NGL sales (gallons)  (3)		165,018,837			125,247,667			471,467,923			435,737,044
Average Pricing
Realized natural gas ($/MMBtu)  (4)	$	3.99		$	3.08		$	4.38		$	3.20
Realized NGL ($/gallon)  (4)		0.92			0.81			1.03			0.70
Natural Gas Daily WAHA ($/MMBtu)		4.01			3.08			4.39			3.20
Natural Gas Daily El Paso ($/MMBtu)		3.94			3.05			4.33			3.13
Estimated plant processing spread ($/gallon)		0.56			0.52			0.61			0.41

________________

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

(2)   Gross margin consists of Operating revenues less Cost of natural gas and other energy.  The Company believes that this measure 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 three-month periods ended September 30, 2010 and 2009, the Company’s operating revenues and related volumes attributable to its buy-sell arrangements for natural gas totaled $10.4 million and $8.5 million, and 2,291,000 MMBtus and 2,713,000 MMBtus, respectively.  The Company’s operating revenues and related volumes for the three-month periods ended September 30, 2010 and 2009 attributable to its buy-sell arrangements for NGL totaled $29.2 million and $15.3 million, and 32,598,000 gallons and 19,923,000 gallons, respectively.  For the nine-month periods ended September 30, 2010 and 2009, the Company’s operating revenues and related volumes attributable to its buy-sell arrangements for natural gas totaled $35 milli on and $30 million, and 7,040,000 MMBtus and 9,057,000 MMBtus, respectively.  The Company’s operating revenues and related volumes for the nine-month periods ended September 30, 2010 and 2009  attributable to its buy-sell arrangements for NGL totaled $86.2 million and $41.9 million, and 90,957,000 gallons and 63,037,000 gallons, respectively.

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

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Three-month period ended September 30, 2010 versus the three-month period ended September 30, 2009.  The $19.1 million EBIT reduction in the three-month period ended September 30, 2010 versus the same period in 2009 was primarily due to the following items:

·   Lower gross margin of $21.4 million primarily as the result of:

o   Higher operating revenues of $64.3 million 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 $3.99 per MMBtu and $0.92 per gallon in the 2010 period versus $3.08 per MMBtu and $0.81 per gallon in the 2009 period, respectively;

o   A $46.7 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 $23.9 million in the 2010 period versus a net hedging gain of $15.1 million in the 2009 period (which includes the impact of $29.2 million of unrealized losses recorded in 2010); and

o   Impact of approximately $4.6 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

·   Lower operating, maintenance and general expenses of $2.8 million primarily due to:

o   Impact of a $4.5 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 $1.1 million primarily due to higher short-term and long-term incentive compensation;

o   Higher contract services, chemicals and lubricants, and other operating costs of $500,000 primarily associated with the Mi Vida treater, which was returned to service during the first quarter of 2010.

Nine-month period ended September 30, 2010 versus the nine-month period ended September 30, 2009.  The $40.9 million EBIT improvement in the nine-month period ended September 30, 2010 versus the same period in 2009 was primarily due to the following items:

·   Higher gross margin of $41 million primarily as the result of:

o   Higher operating revenues of $230.9 million 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 $4.38 per MMBtu and $1.03 per gallon in the 2010 period versus $3.20 per MMBtu and $0.70 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 $184.6 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 $3 million in the 2010 period versus a net hedging gain of $2.4 million in the 2009 period (which includes the impact of $12.6 million of unrealized losses recorded in 2010); and

o   Impact of approximately $4.6 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;

·   Lower operating, maintenance and general expenses of $2.3 million primarily due to:

o   Impact of a $4.5 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 $1.9 million primarily due to higher short-term and long-term incentive compensation; and

o   Higher contract services, chemicals and lubricants, and other operating costs of $1.1 million primarily associated with the Mi Vida treater, which was returned to service during the first quarter of 2010;

·   Higher equity earnings from unconsolidated investments of $1 million primarily due to increased fee-based revenues resulting from higher throughput volumes in the 2010 period versus the 2009 period at the Grey Ranch natural gas treatment facility.  The Grey Ranch facility is currently expected to be idled for the majority of the fourth quarter of 2010; and

·   Higher depreciation and amortization expense of $2.8 million primarily attributable to a $59.7 million increase in property, plant and equipment placed in service after September 30, 2009.

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Distribution Segment.  The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts through its 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.  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 cont inued use of a distribution rate structure, first effective in April 2007, 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.  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 at the time the rates went into effect.  The new rates became effective February 28, 2010.

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(In thousands)
Net operating revenues   (1)	$	49,932		$	45,528		$	174,171		$	162,962
Operating, maintenance and general		32,229			29,371			98,106			96,292
Depreciation and amortization		8,216			7,880			24,139			23,359
Taxes other than on income and revenues		3,154			3,047			9,666			9,929
Total operating income (loss)		6,333			5,230			42,260			33,382
Other income (expenses), net		(34	)		(127	)		(251	)		3,068
EBIT	$	6,299		$	5,103		$	42,009		$	36,450
Operating Information:
Natural Gas sales volumes (MMcf)		3,291			3,718			44,132			42,524
Natural Gas transported volumes (MMcf)		5,316			5,033			20,072			18,999
Weather – Degree Days:   (2)
Missouri Gas Energy service territories		25			43			3,199			2,996
New England Gas Company service territories		32			80			3,407			3,827

________________

(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.

Three-month period ended September 30, 2010 versus the three-month period ended September 30, 2009.  The $1.2 million EBIT improvement in the three-month period ended September 30, 2010 versus the same period in 2009 was primarily due to:

·   Higher net operating revenues of $4.4 million primarily due to $5.6 million of higher net operating revenues at Missouri Gas Energy largely attributable to the impact of the new customer rates effective February 28, 2010, which eliminated the impact of weather and conservation for the majority of Missouri Gas Energy’s revenues.  This revenue increase was partially offset by lower revenues of $900,000 at New England Gas Company primarily due to adjustments recorded in 2009 related to certain benefit costs recovered in rates; and

·   Higher operating, maintenance and general expenses of $2.9 million primarily attributable to:

o   Higher pension costs of $1 million, which are recovered in current rates;

o   Higher legal costs of $800,000 primarily due to ongoing litigation; and

o   Higher labor costs of $400,000 largely due to new positions filled and merit and incentive increases in the 2010 period.

39

Nine-month period ended September 30, 2010 versus the nine-month period ended September 30, 2009.  The $5.6 million EBIT improvement in the nine-month period ended September 30, 2010 versus the same period in 2009 was primarily due to:

·   Higher net operating revenues of $11.2 million primarily due to $13.3 million of higher net operating revenues at Missouri Gas Energy largely attributable to the impact of the new customer rates effective February 28, 2010, which eliminated the impact of weather and conservation for the majority of Missouri Gas Energy’s revenues.  This revenue increase was partially offset by lower revenues of $1.9 million at New England Gas Company primarily due to warmer weather in the 2010 period;

·   Lower other income, net, of $3.3 million primarily due to a $3.5 million settlement in 2009 with an insurance company that released it from certain potential future environmental claim obligations; and

·   Higher operating, maintenance and general expenses of $1.8 million primarily attributable to:

o   Higher pension costs of $2.3 million, which are recovered in current rates;

o   Higher labor costs of $1.8 million largely due to new positions filled and merit and incentive increases in the 2010 period;

o   Lower provisions for uncollectible customer accounts of approximately $1.5 million primarily resulting from improved collectability on aged accounts receivables at Missouri Gas Energy; and

o   Impact of a $1.5 million settlement in 2010 for a previous environmental cost reimbursement claim made by the Company.

Corporate and Other Activities.

Three-month period ended September 30, 2010 versus the three-month period ended September 30, 2009.  The EBIT reduction of $900,000 was primarily due to:

·   Collection in the 2009 period of a $1.8 million settlement awarded to the Company related to the Southwest Gas litigation action filed by the Company in 2002 against former Arizona Corporation Commissioner James Irvin; and

·   A higher net sales margin contribution of $1.2 million from PEI Power Corporation largely due to increased electric generation attributable to higher landfill gas volumes.

Nine-month period ended September 30, 2010 versus the nine-month period ended September 30, 2009.  The EBIT reduction of $400,000 was primarily due to:

·   Impact of a settlement gain of $1.9 million in March 2009 with an insurance company related to certain environmental matters;

·   Collection in the 2009 period of a $1.8 million settlement awarded to the Company related to the Southwest Gas litigation action filed by the Company in 2002 against former Arizona Corporation Commissioner James Irvin; and

·   A higher net sales margin contribution of $3.5 million from PEI Power Corporation largely due to increased electric generation primarily attributable to higher landfill gas volumes.

Interest Expense

Three-month period ended September 30, 2010 versus the three-month period ended September 30, 2009.  Interest expense was $5 million higher in the period ended September 30, 2010 versus the same period in 2009 primarily due to:

·   Higher interest expense of $6.5 million primarily due to the impact of the lower level of 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;

·   Higher interest expense of $1.1 million associated with borrowings under the Company’s credit facilities primarily due to higher average rates and higher average outstanding balances in 2010 compared to 2009;

·   Lower net interest expense of $1.9 million primarily due to lower outstanding debt balances resulting from the repayment of the $100 million 6.089% Senior Notes in February 2010, the $40.5 million 8.25% Senior Notes in April 2010, and the $60.6 million 6.50% Senior Notes in July 2009, partially offset by the impact of the $150 million term loan issued in August 2009; and

·   Lower interest expense of $800,000 primarily due to the impact of lower debt issuance cost amortization in 2010 due to repayments of the related debt.

40

Nine-month period ended September 30, 2010 versus the nine-month period ended September 30, 2009.  Interest expense was $14.6 million higher in the period ended September 30, 2010 versus the same period in 2009 primarily due to:

·   Higher interest expense of $12.4 million primarily due to the impact of the lower level of 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;

·   Higher net interest expense of $1.1 million primarily due to higher outstanding debt balances from 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 $100 million 6.089% Senior Notes in February 2010, the $40.5 million 8.25% Senior Notes in April 2010, and the $60.6 million 6.50% Senior Notes in July 2009; and

·   Higher interest expense of $800,000 primarily due to the impact of higher debt issuance cost amortization in 2010 related to additional issuance cost associated with the $150 million term loan issued in August 2009 and an increase in the commitment  availability of the credit facilities in February 2010 from $400 million to $550 million, and lower debt premium amortizations due to repayments of the related debt in 2009.

Federal and State Income Taxes

The following table summarizes the Company’s income taxes for the periods presented.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(In thousands)
Income tax expense	$	16,525		$	19,720		$	75,943		$	53,170
Effective tax rate (1)		31	%		30	%		31	%		30	%

________________

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

Three-month period ended September 30, 2010 versus the three-month period ended September 30, 2009.  The $3.2 million decrease in federal and state income tax expense was primarily due to lower pre-tax earnings of $12.8 million in 2010.

Nine-month period ended September 30, 2010 versus the nine-month period ended September 30, 2009.  The $22.8 million increase in federal and state income tax expense was primarily due to higher pre-tax earnings of $65 million in 2010 and the impact of $4.2 million of higher income tax expense resulting from the elimination of the Medicare Part D tax subsidy in the PPACA legislation signed into law in March 2010.  The Company expects the EITR will be approximately 31 percent for 2010.

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Preferred Stock Dividends and Loss on Extinguishment of Preferred Stock

Three and nine-month periods ended September 30, 2010 versus the three and nine-month periods ended September 30, 2009. The $1.5 million reduction in preferred stock dividends for the three- and nine-month periods ended September 30, 2010 versus the same periods in 2009 was due to the Company’s redemption of all of its approximately $115 million of outstanding Preferred Stock in the third quarter of 2010 (Preferred Stock Redemption).  Net earnings available for common stockholders were also reduced by $3.3 million in the nine-month period ended September  30, 2010 due to the impact of a $3.3 million loss related to the Preferred Stock Redemption.

See Item 1. Financial Statements (Unaudited), Note 17 – Redemption of Preferred Stock for additional related information.

 LIQUIDITY AND CAPITAL RESOURCES

The Liquidity and Capital Resources information contained herein should be read in conjunction with the related information set forth in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources of the Company’s Form 10-K for the year ended December 31, 2009.

Cash generated from internal operations constitutes the Company’s primary source of liquidity.  The Company’s working capital deficit at September 30, 2010 was $118.8 million.  Additional sources of liquidity for working capital purposes include the use of available credit facilities and may include various equity offerings, debt capital markets, bank 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

	Nine months ended September 30,
	2010			2009
	(In thousands)
Cash flows provided by (used in):
Operating activities	$	360,433		$	464,413
Investing activities		(218,570	)		(319,422	)
Financing activities		(135,286	)		(142,272	)
Increase (decrease) in cash and cash equivalents	$	6,577		$	2,719

Operating Activities

Cash provided by operating activities decreased by $104 million in the 2010 period versus the same period in 2009.  Cash flows provided by operating activities before changes in operating assets and liabilities for the 2010 period were $389.3 million compared with $346.7 million for the 2009 period, an increase of $42.6 million primarily resulting from higher net earnings in 2010. Changes in operating assets and liabilities used cash of $28.8 million in the 2010 period and provided cash of $117.8 million in the 2009 period, resulting in a decrease in cash from changes in operating assets and liabilities of $146.6 million in 2010 compared to 2009.  The $146.6 million decrease was primarily due to:

·   Decreased net cash settlements of $70.8 million of commodity derivative instruments in the Gathering and Processing segment in the 2010 period versus the 2009 period;

·   A decrease of $58.7 million in the Distribution segment primarily due to the timing of cash receipts from revenues, resulting in increased accounts receivable; and

·   An increase in cash used to purchase inventories of $53.9 million in the Distribution segment in the 2010 period primarily due to higher natural gas prices.

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Investing Activities

The Company’s business strategy includes making prudent capital expenditures across its base of gathering, processing, transmission, storage 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 nine months ended September 30, 2010 and 2009 were $218.6 million and $319.4 million, respectively.  The $100.9 million decrease in investing cash outflows was primarily due to a $109.4 million decrease in capital expenditures in the Transportation and Storage segment.

The following table presents a summary of additions to property, plant and equipment by segment, including additions related to major projects for the periods presented.

	Nine Months Ended
	September 30,
	2010			2009
	(In thousands)
Transportation and Storage Segment:
LNG Terminal Expansions/Enhancements	$	21,980		$	75,995
Compression Modernization		(256	)		6,462
Other, primarily pipeline integrity, system
reliability, information technology, air
emission compliance and hurricane
expenditures		92,896			123,397
Total		114,620			205,854
Gathering and Processing Segment		57,286			29,405
Distribution Segment:
Missouri Safety Program		8,422			10,259
Other, primarily system replacement
and expansion		19,629			24,253
Total		28,051			34,512
Corporate and other activities		4,096			24,182
Total  (1)	$	204,053		$	293,953

_______________

(1)   Related cash impact includes the net reduction in capital accruals totaling $8.7 million and $19.2million for the nine-month periods ended September 30, 2010 and 2009, respectively.

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 1. Financial Statements (Unaudited), Note 2 – New Accounting Principles and Other Matters – Other Matters for information related to the Company’s analysis of the Sea Robin assets for potential impairment as of December 31, 2009.  The Company currently estimates that approximately $130 million of the approximately $170 million total estimated capital replacement and retirement expenditures to replace property and equipment damaged by Hurricane Ike are related to Sea Robin.  This estimate is subject to further revision as certain work, primarily retirements, is ongoing. 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.  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 1. Financial Statements (Unaudited), Note 14 – Regulation and Rates – Sea Robin 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.

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Citrus Equity Fundings. Prior to the in-service date of the Phase VIII Expansion project, it is expected Citrus will require sponsor provided contributions from each of its shareholders of up to $250 million.  The majority of the sponsor provided contributions to Citrus will be made in the fourth quarter of 2010 and/or first quarter of 2011.  Citrus plans to resume cash distributions to its sponsors after the Phase VIII Expansion project is placed in service.

Financing Activities

Financing activities used cash of $135.3 million and $142.3 million in the nine months ended September 30, 2010 and 2009, respectively.  The $7 million decrease in net financing cash outflows were primarily due to:

·   Borrowings of $100 million under the Company’s credit facilities in the 2010 period compared to $321.5 million in payments in 2009;

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

·   Net repayments of $40 million of long-term debt in the 2010 period, compared to net issuances of $242 million in the 2009 period.

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 its credit facilities.   

Redemption of Preferred Stock.  On July 30, 2010, the Company redeemed all outstanding Depositary Shares representing interests in its Preferred Stock at $25 per share plus accrued and unpaid dividends.

2010 Term Loan.  On August 3, 2010, the Company, entered into the 2010 Term Loan, maturing on August 3, 2013.  The 2010 Term Loan bears interest at a rate of LIBOR plus 2.125 percent and may be prepaid without penalty at any time.  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.

Floating-Rate Debt Obligations.  The Company has $570 million available under its committed credit facilities.  As of October 29, 2010, there was a balance of $160 million outstanding under the Company’s credit facilities, with an effective interest rate of 3.04 percent.

As of October 29, 2010, the interest rate on the $465 million term loan was 0.81 percent.

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Credit Ratings. As of September 30, 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 $6 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 information related to the Company’s debt obligations, see Part 1, Item 1. Financial Statements (Unaudited), Note 7 – Debt Obligations and Note 10 – Derivative Instruments and Hedging Activities – Derivative Instrument Contingent Features.

OTHER MATTERS

Contingencies

See Part I, Item 1.  Financial Statements (Unaudited), Note 12 – Commitments and Contingencies, in this Quarterly Report on Form 10-Q.

Recently Issued Accounting Standards

See Part I, Item 1.  Financial Statements (Unaudited), Note 2 – New Accounting Principles and Other Matters, in this Quarterly Report on Form 10-Q.

Inflation

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

New England Gas Company Union Contract

On April 30, 2010, UWUA Local 369 ratified a three-year successor collective bargaining agreement with New England Gas Company.  The collective bargaining agreement will expire on May 4, 2013.

                 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.  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 parties’ resources on a Natural Gas Act section 5 proceeding at this time.  The order is final and not subject to rehearing.

See Part I, Item I. Financial Statements (Unaudited), Note 14 – Regulation and Rates for information related to the Company’s other rate matters.

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ITEM 3.  Quantitative and Qualitative Disclosures About Market Risk.

The information contained in Item 3 updates, and should be read in conjunction with, related information set forth in Part II, Item 7A in the Company's Annual Report on Form 10-K for the year ended December 31, 2009, in addition to the unaudited interim condensed consolidated financial statements, accompanying notes, and Management's Discussion and Analysis of Financial Condition and Results of Operations presented in Part I, Items 1 and 2 of this Quarterly Report on Form 10-Q.

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.  Pay-fixed interest rate swaps are used to reduce the risk of increased interest costs during periods of rising interest rates.  Pay-floating interest rate swaps are used to convert the fixed rates of long-term borrowings into short-term variable rates.  At September 30, 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 September 30, 2010, $19.9 million is included in Derivative instruments – liabilities, and $9.5 million is included in Deferred Credits in the unaudited interim Condensed Consolidated Balance Sheet related to the pay-fixed interest rate swaps on the $455 million Term Loan due 2012.

At September 30, 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 $700,000 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 that currently impact interest expense 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 nine-month period ended September 30, 2010 is not material to the Company.

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 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 instruments at fair value, which can be affected by changes in 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 instruments allow the Company to preserve value and protect margins.

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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 hedges utilized by the Company can be unfavorably impacted by:

·   Processing plant outages;

·   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;

  ·   Reduction 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; and

·   Competition for new wellhead supplies.

The following table summarizes SUGS' principal commodity derivative instruments as of September 30, 2010 (all instruments are settled monthly), which were developed based upon historical and projected operating conditions and processable volumes.

			Average		Volumes				Fair Value
			Fixed Price		(MMBtu/d) (3)				of Assets
Instrument Type	Index		(per MMBtu)		2010		2011		(Liabilities) (4)
									(In thousands)
Natural Gas - Cash Flow Hedges:  (1)
Receive-fixed swap	Gas Daily - Waha		$	5.33		24,863		-	$	3,638
Receive-fixed swap	Gas Daily - Waha		$	6.12		-		13,813		9,630
Receive-fixed swap	Gas Daily - El Paso Permian		$	5.33		20,137		-		2,947
Receive-fixed swap	Gas Daily - El Paso Permian		$	6.12		-		11,187		7,799
		Total				45,000		25,000	$	24,014
Processing Spread - Economic Hedges:  (2)
Receive-fixed swap	Gas Daily - Waha (natural gas)
	OPIS - Mt. Belvieu (NGL)		$	5.11		22,100		-	$	(7,121	)
Receive-fixed swap	Gas Daily - Waha (natural gas)
	OPIS - Mt. Belvieu (NGL)		$	5.51		-		13,813		(9,306	)
Receive-fixed swap	Gas Daily - El Paso Permian (natural gas)
	OPIS - Mt. Belvieu (NGL)		$	5.11		17,900		-		(5,767	)
Receive-fixed swap	Gas Daily - El Paso Permian (natural gas)
	OPIS - Mt. Belvieu (NGL)		$	5.51		-		11,187		(7,537	)
		Total				40,000		25,000	$	(29,731	)

__________________

(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 equivalent natural gas volumes, are treated as economic hedges.  The ratio of NGL product sold per MMBtu is approximately: 33 percent ethane, 32 percent propane, 5 percent isobutane, 14 percent normal butane and 16 percent natural gasoline.  The change in fair value is reported in current-period earnings.

(3)   All volumes are applicable to the period October 1, 2010 to December 31, 2010 and January 1, 2011 to December 31, 2011, as applicable.

(4)   See Part I, Item 1. Financial Statements (Unaudited), Note 10 – Derivative Instruments and Hedging Activities – Commodity Contracts – Gathering and Processing Segment for additional related information.

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At September 30, 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 $1.6 million and $6 million, respectively.  Such commodity price risk estimates do not include (i) any effect on demand for the Company’s services that may be caused by, or arise in conjunction with, price changes (e.g., 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), (ii) any effect from changes related to future contracting practices, and (iii) any effect from operating results which deviate from historical averages.

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 operating compression to move the customers’ 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 Comp any.  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 September 30, 2010, there were no hedges in place in respect to natural gas price risk associated with the Company’s interstate pipeline operations.

Distribution Segment.  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 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 unaudited interim Condensed Consolidated Balance Sheet.  As of September 30, 2010 and December 31, 2009, the fair values of the contracts, which expire at various times through September 2012, are included in the unaudited interim Conden sed Consolidated Balance Sheet as liabilities, with matching adjustments to deferred natural gas purchases of $49.8 million and $43.6 million, respectively.

ITEM 4.  Controls and Procedures.

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

The Company has established disclosure controls and procedures to ensure that information required to be disclosed by the Company, including consolidated entities, in reports filed or submitted under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.  The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed in the reports it files or submits under the Exchange Act is accumulated and communicated to management, including the Company’s CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure.  The Company performed an evaluation under the supervision and with the participation of management, including its CEO and CFO, and with the participati on of personnel from its Legal, Internal Audit, Risk Management and Financial Reporting Departments, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this report.  Based on that evaluation, Southern Union’s CEO and CFO concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2010.

Changes in Internal Controls

Management’s assessment of internal control over financial reporting as of December 31, 2009 was included in Southern Union’s Annual Report on Form 10-K filed on March 1, 2010.

There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended September 30, 2010 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This reportcontains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act.  Forward-looking statements are based on management’s beliefs and assumptions.  These forward-looking statements, which address the Company’s expected business and financial performance, among other matters, are identified by terms and phrases such as:  anticipate, believe, intend, estimate, expect, continue, should, could, may, plan, project, predict, will, potential, forecast and similar expressions.  Forward-looking statements involve risks and uncertainties that may or could cause actual results to be materially different from the results predicted.&# 160; 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.

49

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.  These and other risks are described in greater detail in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009 and its other reports filed with the SEC.  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 o f new information, future events or otherwise, except as may be required by law.

PART II.  OTHER INFORMATION

ITEM 1.   Legal Proceedings.

Southern Union is a party to or has property subject to litigation and other proceedings, including matters arising under provisions relating to the protection of the environment, as described in Part I, Item 1. Financial Statements (Unaudited), Note 12 – Commitments and Contingencies, in this Quarterly Report on Form 10-Q and in the Item 8.  Financial Statements and Supplementary Data, Note 18 – Commitments and Contingencies, information included in the Company’s Form 10-K for the year ended December 31, 2009.

Southern Union is subject to federal and state requirements for the protection of the environment, including those for the discharge of hazardous materials and remediation of contaminated sites.  As a result, Southern Union is a party to or has its property subject to various other lawsuits or proceedings involving environmental protection matters.  For information regarding these matters, see Part I, Item 1. Financial Statements (Unaudited), Note 12 – Commitments and Contingencies, in this Quarterly Report on Form 10-Q and in the Item 8.  Financial Statements and Supplementary Data, Note 18 – Commitments and Contingencies, information included in the Company’s Form 10-K for the year ended December 31, 2009.

ITEM 1A.  Risk Factors.

Except for the additional risk factor information described below, there have been no material changes to the risk factors previously disclosed in the Company’s Form 10-K filed with the SEC on March 1, 2010.  The following additional risk factor information should be read in conjunction with the related disclosure in PART I, ITEM 1A. Risk Factors, in Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2009.

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 Mineral Management Service has been fundamentally restructured by the DOI with the intent of providing enhanc ed 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 facili ties, which could adversely affect the Company’s business, financial condition, results of operations and cash flows.

 

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ITEM 2.  Unregistered Sales of Equity Securities and Use of Proceeds.

The following table presents information with respect to purchases during the three months ended September 30, 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 of		Average Price
Period	Shares Purchased (1)		Paid per Share
July 2010		6,394	$	22.13
August 2010		53		23.13
September 2010		4,463		24.27
Total		10,910	$	23.01

__________________

(1)   The total number of shares purchased includes 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 3.  Defaults Upon Senior Securities.

N/A

ITEM 4.  Reserved.

ITEM 5.  Other Information.

All information required to be reported on Form 8-K for the quarter ended September 30, 2010 was appropriately reported.

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ITEM 6.  Exhibits.

The following exhibits are filed as part of this Quarterly Report on Form 10-Q:

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) Limited Settlement Agreement between Southern Union Company, Narragansett Electric Company d/b/a National Grid, the Department of the Attorney General for the State of Rhode Island and the Rhode Island Department of Environmental Management, dated as of August 24, 2006. (Filed as Exhibit 10.2 to Southern Union’s Current Report on Form 8-K filed on August 30, 2006 and incorporated herein by reference.)

2(e) 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.)

3(c) Certificate of Designations, Preferences and Rights re: Southern Union Company’s 7.55% Noncumulative Preferred Stock, Series A. (Filed as Exhibit 4.1 to Southern Union’s Form 8-A/A dated October 17, 2003 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.)

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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 partythereto. (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.)

53

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.) *

54

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) Second Amended and Restated Southern Union Company Executive Incentive Bonus Plan, dated March 25, 2010 (Filed as Appendix I to Southern Union’s proxy statement on Schedule 14A filed on March 26, 2006 and incorporate herein by reference.) *

10(u) 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(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.)

12 Ratio of earnings to fixed charges.  (Filed herewith as Exhibit 12.)

        14 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.)

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.

55

    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.

56

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	SOUTHERN UNION COMPANY
	(Registrant)
Date:  November 4, 2010	By /s/ GEORGE E. ALDRICH
	George E. Aldrich                                                       Senior Vice President and Controller                                                       (authorized officer and principal                                                                                                                                              accountin g officer)

57

EX-12

SOUTHERN UNION COMPANY																Exhibit 12
RATIO OF EARNINGS TO FIXED CHARGES
The following table sets forth the ratio of earnings to fixed charges for Southern Union on a historical basis for the nine months ended September 30, 2010 and the years ended December 31, 2009, 2008, 2007, 2006 and 2005. For the purpose of calculating such ratios, “earnings” consist of pre-tax income from continuing operations before income or loss from equity investees, adjusted to reflect distributed income from equity investments, and fixed charges, less capitalized interest. “Fixed charges” consist of interest costs, amortization of debt discount, premiums and issuance costs and an estimate of interest implicit in rentals. No adjustment has been made to earnings for the amortization of capital interest for the periods presented as such amount is immaterial. Interest on FIN 48 liabilities is excluded from the computation of fixed charges as it is recorded by Southern Union in income tax expense versus interest expense.
	9 Months Ended			Year Ended December 31,
	September 30, 2010			2009			2008			2007			2006			2005
	(In thousands)
FIXED CHARGES:
Interest Expense	$	156,412		$	191,022		$	204,272		$	202,403		$	202,513		$	132,971
Net amortization of debt discount, premium and
issuance expense		5,139			5,778			3,136			743			12,130			2,186
Capitalized Interest		6,316			25,747			18,963			14,708			5,492			8,950
Interest portion of rental expense		5,376			7,576			6,386			6,645			6,234			6,700
Total Fixed Charges	$	173,243		$	230,123		$	232,757		$	224,499		$	226,369		$	150,807
EARNINGS:
Consolidated pre-tax income (loss) from
continuing operations	$	244,623		$	251,480		$	399,926		$	323,970		$	326,330		$	203,148
Earnings of equity investments		(78,456	)		(80,790	)		(75,030	)		(100,914	)		(141,370	)		(70,742	)
Distributed income from equity investments		6,445			-			77,150			103,550			62,637			15,203
Capitalized interest		(6,316	)		(25,747	)		(18,963	)		(14,708	)		(5,492	)		(8,950	)
Total fixed charges (from above)		173,243			230,123			232,757			224,499			226,369			150,807
Earnings Available for Fixed Charges	$	339,539		$	375,066		$	615,840		$	536,397		$	468,474		$	289,466
Ratio of Earnings to Fixed Charges		2.0			1.6			2.6			2.4			2.1			1.9

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

RULES 13A-14(a) AND 15D-14(a) UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, George L. Lindemann, certify that:

(1)    I have reviewed this quarterly report on Form 10-Q of Southern Union Company;

(2)       Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

(3)       Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

(4)       The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

(5)       The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 4, 2010

/s/ GEORGE L. LINDEMANN                                                                      

George L. Lindemann

Chairman of the Board and

Chief Executive Officer

(principal executive officer)

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO

RULES 13A-14(a) AND 15D-14(a) UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Richard N. Marshall, certify that:

(1)    I have reviewed this quarterly report on Form 10-Q of Southern Union Company;

(2)       Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

(3)       Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

(4)       The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

(5)       The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 4, 2010

/s/ RICHARD N. MARSHALL                                                                      

Richard N. Marshall

Senior Vice President and

Chief Financial Officer

(principal financial officer)

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report on Form 10-Q of Southern Union Company (the “Company”) for the quarter ended September 30, 2010, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, George L. Lindemann, Chairman of the Board and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d)of the Securities Exchange Act of 1934, as amended, and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ GEORGE L. LINDEMANN                                                                      

George L. Lindemann

Chairman of the Board and

Chief Executive Officer

November 4, 2010

This Certification is being furnished solely to accompany the Report pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and shall not be incorporated by reference into any filing of the Company under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, whether made before or after the date of this Report, irrespective of any general incorporation language contained in such filing.

A signed original of this written statement required by Section 906, or other documents authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report on Form 10-Q of Southern Union Company (the “Company”) for the quarter ended September 30, 2010, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Richard N. Marshall, Senior Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d)of the Securities Exchange Act of 1934, as amended, and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ RICHARD N. MARSHALL                                                                      

Richard N. Marshall

Senior Vice President and

Chief Financial Officer

November 4, 2010

This Certification is being furnished solely to accompany the Report pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and shall not be incorporated by reference into any filing of the Company under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, whether made before or after the date of this Report, irrespective of any general incorporation language contained in such filing.

A signed original of this written statement required by Section 906, or other documents authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.