su10q_063010.htm

10-Q 1 su10q_063010.htm FORM 10Q 6-30-2010 su10q_063010.htm

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

June 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 ___

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 August 3, 2010 was 124,482,779.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

FORM 10-Q

June 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.	30

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.	45

ITEM 4. Controls and Procedures.	47

PART II. OTHER INFORMATION:

ITEM 1. Legal Proceedings.	49

ITEM 1A. Risk Factors.	49

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds.	50

ITEM 3. Defaults Upon Senior Securities.	50

ITEM 4. Reserved.	50

ITEM 5. Other Information.	50

ITEM 6. Exhibits.	51

SIGNATURES	56

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

RIDEM Rhode Island Department of Environmental Management

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

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

(UNAUDITED)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	(In thousands, except per share amounts)

Operating revenues (Note 13)	$	573,096		$	453,025		$	1,332,090		$	1,136,888

Operating expenses:
Cost of gas and other energy		246,626			191,917			685,635			571,979
Operating, maintenance and general		118,723			116,539			232,608			245,216
Depreciation and amortization		57,559			53,360			112,753			105,830
Revenue-related taxes		4,806			4,816			21,848			22,022
Taxes, other than on income and revenues		13,638			13,739			28,224			27,480
Total operating expenses		441,352			380,371			1,081,068			972,527

Operating income		131,744			72,654			251,022			164,361

Other income (expenses):
Interest expense		(55,436	)		(48,365	)		(106,312	)		(96,735	)
Earnings from unconsolidated investments		27,542			22,694			46,120			39,267
Other, net		(352	)		132			(63	)		6,094
Total other income (expenses), net		(28,246	)		(25,539	)		(60,255	)		(51,374	)

Earnings before income taxes		103,498			47,115			190,767			112,987

Federal and state income tax expense (Note 9)		28,609			13,835			59,418			33,450


Net earnings		74,889			33,280			131,349			79,537

Preferred stock dividends		(2,170	)		(2,170	)		(4,341	)		(4,341	)
Loss on extinguishment of preferred stock (Note 17)		(3,295	)		-			(3,295	)		-

Net earnings available for common stockholders	$	69,424		$	31,110		$	123,713		$	75,196

Net earnings available for common stockholders per share:
Basic	$	0.56		$	0.25		$	0.99		$	0.61
Diluted		0.55			0.25			0.99			0.61

Dividends declared on common stock per share	$	0.15		$	0.15		$	0.30		$	0.30

Weighted average shares outstanding (Note 4):
Basic		124,474			124,047			124,445			124,046
Diluted		125,244			124,274			125,202			124,123

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

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEET

(UNAUDITED)

ASSETS

	June 30,			December 31,
	2010			2009
	(In thousands)
Current assets:
Cash and cash equivalents	$	2,588		$	10,545
Accounts receivable, net of allowances of
$4,680 and $1,874, respectively		221,144			277,661
Accounts receivable – affiliates		6,430			10,387
Inventories (Note 3)		240,585			290,031
Deferred natural gas purchases		95,364			88,421
Natural gas imbalances - receivable		92,625			127,284
Prepayments and other assets		60,648			57,024
Total current assets		719,384			861,353

Property, plant and equipment:
Plant in service		6,794,595			6,260,188
Construction work in progress		121,344			531,710
		6,915,939			6,791,898
Less accumulated depreciation and amortization		(1,278,079	)		(1,162,685	)
Net property, plant and equipment		5,637,860			5,629,213

Deferred charges:
Regulatory assets		69,312			72,304
Deferred charges		70,061			60,995
Total deferred charges		139,373			133,299

Unconsolidated investments (Note 5)		1,381,871			1,340,048

Goodwill		89,227			89,227

Other		21,400			21,934


Total assets	$	7,989,115		$	8,075,074

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

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEET

(UNAUDITED)

STOCKHOLDERS' EQUITY AND LIABILITIES

	June 30,		December 31,
	2010		2009
	(In thousands)
Stockholders’ equity:
Common stock, $1 par value; 200,000 shares authorized;
125,654 and 125,569 shares issued, respectively	$	125,654	$	125,569
Preferred stock (Note 17)		-		115,000
Premium on capital stock		1,914,930		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: 580
and 659 shares, respectively		(10,462)		(11,769)
Deferred compensation plans		10,462		11,769
Accumulated other comprehensive loss		(40,535)		(56,505)
Retained earnings		496,074		409,698
Total stockholders' equity		2,466,908		2,469,946

Long-term debt obligations (Note 7)		3,421,079		3,421,236

Total capitalization		5,887,987		5,891,182

Current liabilities:
Long-term debt due within one year (Note 7)		880		140,500
Notes payable (Note 7)		156,095		80,000
Preferred stock - redeemable (Note 17)		115,000		-
Accounts payable and accrued liabilities		211,208		246,394
Federal, state and local taxes payable		33,253		4,293
Accrued interest		37,357		40,061
Natural gas imbalances - payable		233,787		322,200
Derivative instruments (Notes 10 and 11)		53,090		97,008
Asset retirement obligations		30,277		45,971
Other		65,397		77,928
Total current liabilities		936,344		1,054,355

Deferred credits		203,949		223,950

Accumulated deferred income taxes		960,835		905,587

Commitments and contingencies (Note 12)

Total stockholders' equity and liabilities	$	7,989,115	$	8,075,074

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

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(UNAUDITED)


	Six Months Ended June 30,
	2010			2009
	(In thousands)
Cash flows provided by (used in) operating activities:
Net earnings	$	131,349		$	79,537
Adjustments to reconcile net earnings to net cash flows
provided by operating activities:
Depreciation and amortization		112,753			105,830
Deferred income taxes		60,087			28,546
Provision for bad debts		9,562			11,109
Unrealized (gain) loss on commodity derivatives		(16,654	)		20,681
Share-based compensation expense		4,454			3,622
Earnings from unconsolidated investments, adjusted for cash distributions		(42,396	)		(39,267	)
Changes in operating assets and liabilities		(16,663	)		171,767
Net cash flows provided by operating activities		242,492			381,825
Cash flows provided by (used in) investing activities:
Additions to property, plant and equipment		(129,379	)		(227,257	)
Plant retirements and other		359			(3,114	)
Net cash flows used in investing activities		(129,020	)		(230,371	)
Cash flows provided by (used in) financing activities:
Increase (decrease) in book overdraft		(12,030	)		2,273
Issuance of long-term debt		857			151,533
Renewal cost for credit facilities and issuance cost of debt		(5,831	)		(1,128	)
Dividends paid on common stock		(37,322	)		(37,208	)
Dividends paid on preferred stock		(4,341	)		(4,341	)
Repayment of long-term debt obligation		(140,723	)		-
Net (payments) borrowings under credit facilities		76,095			(251,459	)
Other		1,866			(210	)
Net cash flows used in financing activities		(121,429	)		(140,540	)
Change in cash and cash equivalents		(7,957	)		10,914
Cash and cash equivalents at beginning of period		10,545			4,318
Cash and cash equivalents at end of period	$	2,588		$	15,232

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

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		-		-			-		-			-			-			-			131,349			131,349
Net change in other
comprehensive income (Note 6)		-		-			-		-			-			-			15,970			-			15,970
Comprehensive income																								147,319
Preferred stock dividends		-		-			-		-			-			-			-			(4,341	)		(4,341	)
Common stock dividends declared		-		-			-		-			-			-			-			(37,337	)		(37,337	)
Share-based compensation		-		-			4,454		-			-			-			-			-			4,454
Restricted stock issuances		8		-			453		-			-			-			-			-			461
Exercise of stock options and SARs		77		-			1,435		(106	)		-			-			-			-			1,406
Contributions to Trust		-		-			-		-			(387	)		387			-			-			-
Disbursements from Trust		-		-			-		-			1,694			(1,694	)		-			-			-
Balance June 30, 2010	$	125,654	$	-		$	1,914,930	$	(29,215	)	$	(10,462	)	$	10,462		$	(40,535	)	$	496,074		$	2,466,908

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.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The accompanying unaudited interim condensed consolidated financial statements of the Company have 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. 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.

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 June 30, 2010.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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. Materials and supplies are primarily comprised of compressor components and parts.

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

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

	Transportation & Storage		Gathering & Processing		Distribution		Total
At June 30, 2010	(In thousands)
Current
Natural gas (1)	$	149,584	$	-	$	54,569	$	204,153
Materials and supplies		15,901		9,204		3,768		28,873
NGL (2)		-		7,559		-		7,559
Total Current		165,485		16,763		58,337		240,585

Non-Current
Natural gas (1)		7,639		-		-		7,639

	$	173,124	$	16,763	$	58,337	$	248,224


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 June 30, 2010 and December 31, 2009 were 30,828,000 MMBtu and 35,039,000 MMBtu, respectively. Natural gas volumes in the Distribution segment at June 30, 2010 and December 31, 2009 were 12,513,000 MMBtu and 11,742,000 MMBtu, respectively.

(2)	NGL at June 30, 2010 and December 31, 2009 were 9,343,000 gallons and 6,680,000 gallons, respectively.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
	(In thousands)

Weighted average shares outstanding - Basic		124,474		124,047		124,445		124,046
Add assumed vesting of restricted stock		123		64		109		48
Add assumed exercise of stock options and SARs		647		163		648		29
Weighted average shares outstanding - Diluted		125,244		124,274		125,202		124,123

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.

	June 30,
	2010		2009
	(In thousands, except per share amounts)

Options excluded		849		1,662
Exercise price of options excluded	$	24.06 - $28.48	$	16.83 - $28.48
SARs excluded		386		386
Exercise price ranges of SARs excluded	$	28.07 - $28.48	$	28.07 - $28.48
Second quarter weighted-average market price	$	23.70	$	16.56
Year-to-date weighted-average market price	$	23.73	$	15.14

5. Unconsolidated Investments

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

	June 30,		December 31,
	2010		2009
	(In thousands)

Citrus	$	1,353,856	$	1,310,765
Other		28,015		29,283
	$	1,381,871	$	1,340,048

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Equity Investments. Unconsolidated investments at June 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. 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 sets forth summarized financial information for the Company’s equity investments for the periods presented.

	Three Months Ended June 30,
	2010				2009
	Citrus		Other		Citrus		Other
	(In thousands)

Revenues	$	140,572	$	5,823	$	136,781	$	3,717
Operating income		77,323		3,297		77,949		2,010
Net earnings		46,460		3,101		38,092		1,935

	Six Months Ended June 30,
	2010				2009
	Citrus		Other		Citrus		Other
	(In thousands)

Revenues	$	254,711	$	11,684	$	248,223	$	9,107
Operating income		129,694		6,482		132,543		3,920
Net earnings		76,087		6,270		64,514		3,831

Citrus Dividends. Citrus did not pay dividends to the Company during the six-month periods ended June 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 $1.27 billion of capital costs have been recorded as of June 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. A potential shipper election, which would have increased the contracted capacity to 83 percent, was not exercised by the shipper.

Prior to the in-service date of the Phase VIII Expansion project, it is expected Citrus will require equity contributions from each of its sponsors of up to $250 million. It is expected the majority of the estimated sponsor equity contributions to Citrus will be made in the fourth quarter of 2010 and/or first quarter of 2011. Citrus also does not plan to make any cash dividends to its sponsors until after the Phase VIII Expansion project is in service.

Florida Gas Rate Filing. Florida Gas filed a rate case with FERC on October 1, 2009, initially reflecting an annual cost of service of approximately $579 million. Pursuant to a FERC order on rehearing and Florida Gas' motion filing, on April 15, 2010, Florida Gas refiled its rates to be effective April 1, 2010 to remove the impact of certain estimated plant expenditures not in service by February 28, 2010, which reduced the annual cost of service originally filed by approximately $28 million to $551.6 million. Florida Gas by comparison has recorded actual revenues of approximately $511 million for the twelve-month period ended March 31, 2010 under its previously existing rates, including amounts collected from system expansions and certain surcharges. Several parties have intervened and protested Florida Gas’ rate case filing, including protesting various elements of the cost of service. The new rates went into effect on April 1, 2010, subject to refund pending the final outcome of the rate proceeding. A hearing is currently scheduled for August 2010. A $5.8 million provision for estimated refunds through June 30, 2010 has been established for refunds on certain rate schedules for which a refund is potentially applicable, the resolution of which will ultimately be determined by settlement or adjudication.

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 percent 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.

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. The previous judge recused himself and the case was assigned to a new judge in June 2010. 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						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	(In thousands)

Net Earnings	$	74,889		$	33,280		$	131,349		$	79,537
Changes in Other Comprehensive Income (Loss):
Change in fair value of interest rate hedges, net of tax of $(1,308),
$827, $(3,614) and $412, respectively		(1,945	)		1,231			(5,375	)		613
Reclassification of unrealized loss on interest rate hedges into
earnings, net of tax of $2,250, $1,964, $4,554 and $3,576,
respectively		3,357			2,950			6,803			5,379
Change in fair value of commodity hedges, net of tax of $(390),
$(81), $9,613 and $4,507, respectively		(690	)		(143	)		17,061			7,999
Reclassification of unrealized gain on commodity hedges into
earnings, net of tax of $(1,830), $(4,207), $(2,272) and $(8,174),
respectively		(3,247	)		(7,466	)		(4,032	)		(14,506	)
Reclassification of net actuarial loss and prior service credit
relating to pension and other postretirement benefits into
earnings, net of tax of $551, $736, $1,102 and $1,472,
respectively		722			974			1,442			1,946
Change in other comprehensive income (loss) from equity
investments, net of tax of $22, $0, $44 and $0, respectively		35			-			71			-
Total other comprehensive income (loss)		(1,768	)		(2,454	)		15,970			1,431
Total comprehensive income	$	73,121		$	30,826		$	147,319		$	80,968

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.


	June 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	$	403,491	$	359,765	$	389,820
8.25% Senior Notes due 2029		300,000		313,110		300,000		337,800
7.24% to 9.44% First Mortgage Bonds
due 2020 to 2027		19,500		21,253		19,500		21,403
6.089% Senior Notes due 2010		-		-		100,000		100,250
7.20% Junior Subordinated Notes due 2066		600,000		546,000		600,000		510,000
Term Loan due 2011 (1)		150,000		151,469		150,000		150,178
Note Payable		8,359		8,359		7,725		7,725
		1,437,624		1,443,682		1,536,990		1,517,176

Panhandle:
6.05% Senior Notes due 2013		250,000		272,020		250,000		269,733
6.20% Senior Notes due 2017		300,000		322,266		300,000		319,455
8.125% Senior Notes due 2019		150,000		172,082		150,000		173,111
8.25% Senior Notes due 2010		-		-		40,500		41,143
7.00% Senior Notes due 2029		66,305		70,366		66,305		69,866
7.00% Senior Notes due 2018		400,000		439,356		400,000		434,560
Term Loans due 2012		815,391		784,058		815,391		758,108
Net premiums on long-term debt		2,639		2,639		2,550		2,550
		1,984,335		2,062,787		2,024,746		2,068,526

Total Long-Term Debt Obligations		3,421,959		3,506,469		3,561,736		3,585,702

Credit Facilities		156,095		156,093		80,000		78,968
Preferred stock - redeemable (2)		115,000		115,065		-		-

Total consolidated debt obligations		3,693,054	$	3,777,627		3,641,736	$	3,664,670
Less current portion of long-term debt		880				140,500
Less short-term debt		156,095				80,000
Less preferred stock - redeemable (2)		115,000				-
Total long-term debt	$	3,421,079			$	3,421,236

__________________

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

(2)	See Note 17 – Redemption of Preferred Stock for more information.

The fair value of the Company’s term loans and credit facilities as of June 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.

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 June 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.

The fair value of the Company’s preferred stock as of June 30, 2010 was determined using quotes from the New York Stock Exchange.

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 will be 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.

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 the credit facilities.

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 June 30,						Three Months Ended June 30,
	2010			2009			2010			2009
	(In thousands)

Service cost	$	768		$	737		$	793		$	750
Interest cost		2,509			2,524			1,409			1,347
Expected return on plan assets		(2,337	)		(2,070	)		(1,269	)		(772	)
Prior service cost (credit) amortization		138			138			(411	)		(317	)
Actuarial (gain) loss amortization		1,996			2,102			(451	)		(212	)
Sub-total		3,074			3,431			71			796
Regulatory adjustment (1)		52			(125	)		666			666
Net periodic benefit cost	$	3,126		$	3,306		$	737		$	1,462

	Pension Benefits						Other Postretirement Benefits
	Six Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(In thousands)

Service cost	$	1,535		$	1,475		$	1,586		$	1,499
Interest cost		5,019			5,048			2,819			2,695
Expected return on plan assets		(4,674	)		(4,140	)		(2,311	)		(1,544	)
Prior service cost (credit) amortization		276			276			(823	)		(634	)
Actuarial (gain) loss amortization		3,993			4,203			(901	)		(424	)
Sub-total		6,149			6,862			370			1,592
Regulatory adjustment (1)		157			(250	)		1,332			1,332
Net periodic benefit cost	$	6,306		$	6,612		$	1,702		$	2,924

____________________

(1)

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

9. Taxes on Income

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	(In thousands)

Income tax expense	$	28,609		$	13,835		$	59,418		$	33,450
Effective tax rate		28	%		29	%		31	%		30	%

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.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

10. Derivative Instruments and Hedging Activities

The Company is exposed to certain risks in its ongoing business operations. The primary risks managed by using derivative instruments are interest rate risk and commodity price risk. Interest rate swaps and treasury rate locks are the principal derivative instruments used by the Company to manage interest rate risk associated with its long-term borrowings, although other interest rate derivative contracts may also be used from time to time. Natural gas price swaps and NGL processing spread swaps are the principal derivative instruments used by the Company to manage commodity price risk associated with purchases and/or sales of natural gas and/or NGL, although other commodity derivative contracts may also be used from time to time. The Company recognizes all derivative instruments as assets or liabilities at fair value in the 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 June 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 June 30, 2010, approximately $11.3 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 June 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 June 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 June 30, 2010, the Company had outstanding receive-fixed natural gas price swaps with a total notional amount of 8,280,000 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 June 30, 2010, approximately $8 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.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

NGL Processing Spread Swaps. As of June 30, 2010, the Company had outstanding receive-fixed NGL processing spread swaps with a total notional amount of 7,360,000 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 price swaps to manage the exposure to changes in the cost of forecasted purchases 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 June 30, 2010, the Company had outstanding pay-fixed natural gas price swaps with total notional amounts of 8,760,000 MMBtus, 15,920,000 MMBtus and 1,650,000 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.

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.

	Balance Sheet	Asset Derivative Instruments (1)
	Location	Fair Value (2)
		June 30, 2010		December 31, 2009
		(In thousands)
Cash Flow Hedges:
Commodity contracts - Gathering and Processing:
Natural gas price swaps	Prepayments and other assets	$	12,348	$	-
Other noncurrent assets			4,211		-
Deferred credits			-		314
		$	16,559	$	314
Economic Hedges:
Commodity contracts - Gathering and Processing:
NGL processing spread swaps	Prepayments and other assets	$	903	$	-
Other noncurrent assets			1,195		-
Deferred credits			179		-
Other derivative instruments	Prepayments and other assets		-		5
Derivative instruments-liabilities			51		166

Commodity contracts - Distribution:
Natural gas price swaps	Derivative instruments-liabilities		60		582
Deferred credits			33		15
		$	2,421	$	768
Other:
Commodity contracts - Gathering and Processing:
Other derivative instruments	Prepayments and other assets	$	284	$	162

Total		$	19,264	$	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.

(2)	See Note 11 – Fair Value Measurement for information related to the framework used by the Company to measure the fair value of its derivative instruments as of June 30, 2010.

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.

	Balance Sheet	Liability Derivative Instruments (1)
	Location	Fair Value (2)
		June 30, 2010		December 31, 2009
		(In thousands)
Cash Flow Hedges
Interest rate contracts:
Interest rate swaps	Derivative instruments-liabilities	$	18,441	$	18,754
Deferred credits			12,529		13,975

Commodity contracts - Gathering and Processing:
Natural gas price swaps	Derivative instruments-liabilities		-		4,126
		$	30,970	$	36,855
Economic Hedges
Commodity contracts - Gathering and Processing:
NGL processing spread swaps	Prepayments and other assets	$	8,515	$	-
Other noncurrent assets			426		-
Derivative instruments-liabilities			1,538		34,477
Deferred credits			-		10,410

Other derivative instruments	Derivative instruments-liabilities		279		193

Commodity contracts - Distribution:
Natural gas price swaps	Derivative instruments-liabilities		32,944		40,206
Deferred credits			3,042		3,991
		$	46,744	$	89,277
Other
Commodity contracts - Gathering and Processing:
Other derivative instruments	Prepayments and other assets	$	2	$	30

Total		$	77,716	$	126,162

_____________

(1)

(2)	See Note 11 – Fair Value Measurement for information related to the framework used by the Company to measure the fair value of its derivative instruments as of June 30, 2010.

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						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Cash Flow Hedges: (1)	(In thousands)
Interest rate contracts:
Change in fair value - increase (decrease) in Accumulated other
comprehensive loss, excluding tax expense effect
of $1,308, $(827), $3,614 and $(412), respectively	$	3,253		$	(2,058	)	$	8,989		$	(1,025	)
Reclassification of unrealized loss from Accumulated other
comprehensive loss - increase of Interest expense, excluding tax
expense effect of $2,250, $1,964, $4,554 and $3,576, respectively		5,607			4,914			11,357			8,955
Commodity contracts - Gathering and Processing:
Change in fair value - (increase) decrease in Accumulated other
comprehensive loss, excluding tax expense effect
of $(390), $(81), $9,613 and $4,507, respectively		(1,080	)		(224	)		26,674			12,506
Reclassification of unrealized gain from Accumulated other
comprehensive loss - increase of Operating Revenues,
excluding tax expense effect of $1,830, $4,207,
$2,272 and $8,174, respectively		5,077			11,673			6,304			22,680

Economic Hedges:
Commodity contracts - Gathering and Processing:
Change in fair value of strategic hedges - (increase) decrease in
Operating revenues (2)		(21,597	)		14,127			(14,672	)		34,649
Change in fair value of other hedges - (increase) decrease
in Operating revenues		(375	)		(365	)		186			481
Commodity contracts - Distribution:
Change in fair value - decrease in Deferred natural gas purchases		23,947			29,797			7,707			21,721

Other:
Commodity contracts - Gathering and Processing:
Change in fair value - (increase) decrease in Operating revenues		259			451			(150	)		162

_________________

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

(2)

Includes $9 million and $20 million of the cash settlement impact for previously recognized unrealized losses in the three-month and six-month periods ended June 30, 2010, respectively. Includes $14.6 million and $29.2 million of the cash settlement impact for previously recognized unrealized gains in the three-month and six-month periods ended June 30, 2009, respectively. Additionally, includes $22.3 million and $16.6 million of unrealized mark-to-market gains recorded in the three-month and six-month periods ended June 30, 2010, respectively, and $5.6 million and $21.1 million of unrealized mark-to-market losses recorded in the three-month and six-month periods ended June 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 request immediate payment. The aggregate fair value of all derivative instruments with credit risk-related contingent features that are in a net liability position at June 30, 2010 is $22.4 million.

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 June 30, 2010
			Using Fair Value Hierarchy
			Quoted Prices in
	Fair Value		Active Markets for		Significant Other
	as of		Identical Assets		Observable Inputs
	June 30, 2010		(Level 1)		(Level 2)
	(In thousands)
Assets:
Commodity derivatives (1)	$	9,998	$	-	$	9,998
Long-term investments		867		867		-
Total	$	10,865	$	867	$	9,998

Liabilities:
Commodity derivatives (1)	$	37,480	$	256	$	37,224
Interest-rate derivatives (1)		30,970		-		30,970
Total	$	68,450	$	256	$	68,194

__________________

(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. 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 June 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 damages to property, employees, other persons and the environment resulting from current or past operations may result in significant expenditures and liabilities in the future. The Company engages in a process of updating and revising its procedures for the ongoing evaluation of its operations to identify potential environmental exposures and enhance compliance with regulatory requirements.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

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

	June 30,		December 31,
	2010		2009
	(In thousands)

Current	$	5,736	$	7,745
Noncurrent		16,592		16,964
Total environmental liabilities	$	22,328	$	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. The most recent extension by the EPA sets the SPCC rule compliance date as November 10, 2010, permitting owners and operators of facilities to prepare or amend and implement SPCC plans in accordance with previously enacted modifications to the regulations. The Company is currently reviewing the impact of the modified regulations on its operations in its Transportation and Storage and Gathering and Processing segments and may incur costs for tank integrity testing, alarms and other associated corrective actions as well as potential upgrades to containment structures. Costs associated with such activities cannot be estimated with certainty at this time, but the Company believes such costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Air Quality Control. In February 2009, EPA proposed 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). The rule is scheduled to be finalized in August 2010 with compliance required in 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 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.

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

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

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

Gathering and Processing Segment Environmental Matters

Gathering and Processing Systems. SUGS is responsible for environmental remediation at certain sites on its gathering and processing systems, resulting primarily from releases of hydrocarbons. SUGS has a program to remediate such contamination. The remediation typically involves the management of contaminated soils and may involve remediation of groundwater. Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements and complexity. The ultimate liability and total costs associated with these sites will depend upon many factors. These sites are generally managed in the normal course of business or operations. The Company believes the outcome of these matters will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Air Quality Control. SUGS is currently negotiating settlements to certain enforcement actions by the NMED and the TCEQ. The only currently assessed penalty amount is pending settlement and has been reduced by the NMED from $247,000 to approximately $51,000. 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.

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 MGPs and sites associated with the operation and disposal activities of former MGPs that produced a fuel known as “town gas”. Some byproducts of the historic manufactured gas process may be regulated substances under various federal and state environmental laws. To the extent these byproducts are present in soil or groundwater at concentrations in excess of applicable standards, investigation and remediation may be required. The sites include properties that are part of the Company’s ongoing operations, sites formerly owned or used by the Company and sites owned by third parties. Remediation typically involves the management of contaminated soils and may involve removal of old MGP structures and remediation of groundwater. Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements, complexity and sharing of responsibility; some contamination may be unrelated to former MGPs. The ultimate liability and total costs associated with these sites will depend upon many factors. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, the Company could potentially be held responsible for contamination caused by other parties. In some instances, the Company may share liability associated with contamination with other PRPs and may also benefit from insurance policies or contractual indemnities that cover some or all of the cleanup costs. These sites are generally managed in the normal course of business or operations. The Company believes the outcome of these matters will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

North Attleboro MGP Site in Massachusetts (North Attleboro Site). In November 2003, the MADEP issued a Notice of Responsibility to New England Gas Company, acknowledging receipt of prior notifications and investigative reports submitted by New England Gas Company, following the discovery of suspected coal tar material at the North Attleboro Site. Subsequent sampling in the adjacent river channel revealed sediment impacts necessitating the investigation of off-site properties. Assessment activities continue at the remaining areas on-site and at the off-site properties. It is estimated that the Company will spend approximately $9 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 requirements under the federal Emergency Planning and Community Right to Know Act (EPCRA) relating to the 2004 incident. Trial commenced on September 22, 2008, and on October 15, 2008, the jury acquitted Southern Union on the EPCRA count and one of the two RCRA counts and found the Company guilty on the other RCRA count. On October 2, 2009, the 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 its Notice of Appeal to the U.S. Court of Appeals for the First Circuit on October 7, 2009. On February 16, 2010 the Company filed its Brief of the appeal with the First Circuit. The U.S. Attorney filed its opposing Brief on April 7, 2010. The Company filed a reply brief on June 10, 2010 and a Citation to Supplemental Authority on July 22, 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.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Will Price. Will Price, an individual, filed actions in U.S. District Court for the District of Kansas for damages against a number of companies, including Panhandle, alleging mis-measurement of natural gas volumes and Btu content, resulting in lower royalties to mineral interest owners. On September 19, 2009, the Court denied plaintiffs’ request for class certification. Plaintiffs have filed a motion for reconsideration, which the Court denied on March 31, 2010. Panhandle believes that its measurement practices conformed to the terms of its FERC natural gas tariffs, which were filed with and approved by FERC. As a result, the Company believes that it has meritorious defenses to the Will Price lawsuit (including FERC-related affirmative defenses, such as the filed rate/tariff doctrine, the primary/exclusive jurisdiction of FERC, and the defense that Panhandle complied with the terms of its tariffs) 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 Harris County, Texas. Trial is set for September 2010. 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.

Energy Resources Technology. Energy Resources Technology (ERT) filed suit against Sea Robin on November 9, 2009 alleging breach of contract due to delays in repairs of damages to Sea Robin’s subsea pipeline suffered during Hurricane Ike. The parties have executed a settlement. The settlement did not have a material adverse effect on the Company’s 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.

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 six-month periods ended June 30, 2010 and 2009.

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					Six Months Ended
	June 30,					June 30,
	2010		2009			2010		2009
	(In thousands)
Revenues from external customers:
Transportation and Storage	$	187,090	$	172,615		$	373,765	$	364,910
Gathering and Processing		282,707		175,084			543,567		343,389
Distribution		99,711		104,532			407,972		426,556
Total segment operating revenues		569,508		452,231			1,325,304		1,134,855
Corporate and other activities		3,588		794			6,786		2,033
Total consolidated revenues from external
customers	$	573,096	$	453,025		$	1,332,090	$	1,136,888

Depreciation and amortization:
Transportation and Storage	$	30,896	$	28,483		$	60,073	$	56,346
Gathering and Processing		17,971		16,543			35,291		32,956
Distribution		7,967		7,808			15,923		15,479
Total segment depreciation and amortization		56,834		52,834			111,287		104,781
Corporate and other activities		725		526			1,466		1,049
Total depreciation and amortization expense	$	57,559	$	53,360		$	112,753	$	105,830

Earnings from unconsolidated investments:
Transportation and Storage	$	25,748	$	21,984		$	42,994	$	37,768
Gathering and Processing		1,395		498			2,380		1,026
Corporate and other activities		399		212			746		473
	$	27,542	$	22,694		$	46,120	$	39,267

Segment performance:
Transportation and Storage EBIT	$	111,246	$	97,922		$	213,671	$	191,144
Gathering and Processing EBIT		40,526		(1,523	)		47,081		(12,956	)
Distribution EBIT		6,865		(291	)		35,710		31,347
Total segment EBIT		158,637		96,108			296,462		209,535
Corporate and other activities		297		(628	)		617		187
Interest expense		55,436		48,365			106,312		96,735
Federal and state income tax expense		28,609		13,835			59,418		33,450
Net earnings		74,889		33,280			131,349		79,537
Preferred stock dividends		2,170		2,170			4,341		4,341
Loss on extinguishment of preferred stock		3,295		-			3,295		-
Net earnings available for common stockholders	$	69,424	$	31,110		$	123,713	$	75,196

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

	June 30,		December 31,
	2010		2009
	(In thousands)
Total assets:
Transportation and Storage	$	5,081,314	$	5,138,042
Gathering and Processing		1,688,072		1,666,935
Distribution		1,045,143		1,109,492
Total segment assets		7,814,529		7,914,469
Corporate and other activities		174,586		160,605
Total consolidated assets	$	7,989,115	$	8,075,074

	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
	(In thousands)
Expenditures for long-lived assets:
Transportation and Storage	$	25,886	$	52,176	$	56,257	$	129,888
Gathering and Processing		15,823		5,300		41,706		16,518
Distribution		9,151		16,706		16,255		23,268
Total segment expenditures for
long-lived assets		50,860		74,182		114,218		169,674
Corporate and other activities		4,166		10,087		6,281		17,003
Total consolidated expenditures for
long-lived assets (1)	$	55,026	$	84,269	$	120,499	$	186,677

_______________________

(1)

Includes net period changes in capital accruals totaling $7.9 million and $10.4 million for the three-month periods ended June 30, 2010 and 2009, respectively. Includes net period changes in capital accruals totaling $(7.9) million and $20.3 million for the six-month periods ended June 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 March 1, 2010, Sea Robin submitted its semiannual filing related to the surcharge which reflected updated costs incurred of $60 million, net of insurance recoveries, which were reflected in the surcharge rate effective April 1, 2010, subject to refund. A hearing was held in July 2010. 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 related earnings in Missouri. The new rates became effective February 28, 2010. Judicial review of the MPSC’s Report and Order is being sought by the Office of the Public Counsel, with respect to rate structure issues, and by Missouri Gas Energy, with respect to cost of capital issues. Those judicial review proceedings are not expected to be complete until 2011, and the results of those judicial review proceedings are not expected to have a material adverse impact on the Company’s consolidated financial position, results of operations or cash flows.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

New England Gas Company. 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)

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 six-month period ended June 30, 2009 totaling $6.1 million consists primarily of $5.7 million of settlements with an insurance company related to certain environmental matters. During 2009, the Company entered into a settlement agreement with an insurance company releasing the insurance company from certain potential future environmental claim obligations.

17. Redemption of Preferred Stock

As of June 30, 2010 and December 31, 2009, the Company had outstanding 4,600,013 Depository 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) and having an aggregate value of approximately $115 million. As of June 30, 2010 and December 31, 2009, six million shares of Preferred Stock were authorized, with approximately 460,000 shares of Preferred Stock issued and outstanding.

On June 29, 2010, the Company announced that it had called for redemption on July 30, 2010 all outstanding Depositary Shares representing interests in its Preferred Stock at $25 per share plus accrued and unpaid dividends. Accordingly, the Company reclassified the $115 million balance previously reported as Preferred stock in the Condensed Consolidated Balance Sheet to Current liabilities – Preferred stock - redeemable and recognized a $3.3 million non-cash loss adjustment charged to Retained earnings related to the write-off of issuance costs that reduced Net earnings available for common stockholders.

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 capital 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.

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

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2010		2009			2010		2009
	(In thousands)
EBIT:
Transportation and storage segment	$	111,246	$	97,922		$	213,671	$	191,144
Gathering and processing segment		40,526		(1,523	)		47,081		(12,956	)
Distribution segment		6,865		(291	)		35,710		31,347
Corporate and other activities		297		(628	)		617		187
Total EBIT		158,934		95,480			297,079		209,722
Interest		55,436		48,365			106,312		96,735
Earnings before income taxes		103,498		47,115			190,767		112,987
Federal and state income taxes		28,609		13,835			59,418		33,450
Net earnings		74,889		33,280			131,349		79,537
Preferred stock dividends		2,170		2,170			4,341		4,341
Loss on extinguishment of preferred stock		3,295		-			3,295		-

Net earnings available for common stockholders	$	69,424	$	31,110		$	123,713	$	75,196

Three-month period ended June 30, 2010 versus the three-month period ended June 30, 2009. The Company’s $38.3 million increase in Net earnings available for common stockholders was primarily due to:

Higher EBIT contribution of $42 million from the Gathering and Processing segment primarily resulting from higher operating revenues of $78.3 million, excluding hedging gains and losses, attributable to higher market-driven realized average natural gas and NGL prices and the impact of $29.3 million of higher gains from hedging activities, partially offset by higher market-driven natural gas and NGL purchase costs of $62.1 million in 2010 versus 2009;

Higher EBIT contributions of $13.3 million from the Transportation and Storage segment mainly due to higher revenues of $20.8 million largely attributable to the LNG terminal infrastructure enhancement construction project placed in service in March 2010, partially offset by lower transportation reservation revenues of $5.4 million primarily due to lower average rates realized on short-term firm capacity; and

·	Higher EBIT contribution of $7.2 million from the Distribution segment primarily due to higher net operating revenues at Missouri Gas Energy of $6.4 million largely attributable to the impact of the new rates effective February 28, 2010.

These improvements in earnings were partially offset by:

·	Higher interest expense of $7.1 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 $14.8 million primarily due to higher pre-tax earnings of $56.4 million in 2010; and

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

Six-month period ended June 30, 2010 versus the six-month period ended June 30, 2009. The Company’s $48.5 million increase in Net earnings available for common stockholders was primarily due to:

Higher EBIT contribution of $60 million from the Gathering and Processing segment primarily resulting from higher operating revenues of $166.6 million, excluding hedging gains and losses, attributable to higher market-driven realized average natural gas and NGL prices and the impact of $33.6 million of higher gains from hedging activities, partially offset by higher market-driven natural gas and NGL purchase costs of $133.5 million in 2010 versus 2009;

Higher EBIT contribution of $22.5 million from the Transportation and Storage segment mainly due to higher revenues of $25.3 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 $16.1 million due to less favorable market conditions and the impact of a provision for repair and abandonment costs of $16.1 million in 2009 for damages to offshore assets resulting from Hurricane Ike; and

Higher EBIT contribution of $4.3 million from the Distribution segment primarily due to higher net operating revenues at Missouri Gas Energy of $7.7 million largely attributable to the impact of the new rates effective February 28, 2010, partially offset by lower revenues of $1.1 million at New England Gas Company primarily due to warmer weather in the 2010 period.

These improvements in earnings were partially offset by:

·	Higher interest expense of $9.6 million primarily attributable to the impact of the lower level of interest costs capitalized attributable to lower average capital project balances outstanding and higher net debt balances outstanding on the Company’s fixed-rate debt obligations;

Higher federal and state income tax expense of $26 million primarily due to higher pre-tax earnings of $77.8 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; and

·	Impact of a $3.3 million loss recorded in the 2010 period related to the Company’s call for 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.

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
	(In thousands)

Operating revenues	$	187,090	$	172,615	$	373,765	$	364,910

Operating, maintenance and general		61,828		59,981		124,906		138,175
Depreciation and amortization		30,896		28,483		60,073		56,346
Taxes other than on income and revenues		8,897		8,313		18,125		17,238
Total operating income		85,469		75,838		170,661		153,151
Earnings from unconsolidated investments		25,748		21,984		42,994		37,768
Other income, net		29		100		16		225
EBIT	$	111,246	$	97,922	$	213,671	$	191,144

Operating information:
Panhandle natural gas volumes transported (TBtu)		333		376		701		803
Florida Gas natural gas volumes transported (TBtu) (1)		214		216		403		403

________________

(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 June 30, 2010 versus the three-month period ended June 30, 2009. The $13.3 million EBIT improvement in the three-month period ended June 30, 2010 versus the same period in 2009 was primarily due to a higher EBIT contribution from Panhandle totaling $9.5 million and higher equity earnings of $3.8 million, mainly from the Company’s unconsolidated investment in Citrus.

Panhandle’s $9.5 million EBIT improvement was primarily due to:

·	Higher operating revenues of $14.5 million primarily due to:

o	Higher LNG revenues of $20.8 million largely attributable to the LNG terminal infrastructure enhancement construction project placed in service in March 2010;

o	Higher transportation commodity revenues of $1.3 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 transportation reservation revenues of $5.4 million primarily due to lower average rates realized on short-term firm capacity on PEPL; and

o	Lower interruptible parking revenues of $2.7 million due to less favorable market conditions.

The operating revenue improvement was partially offset by:

·	Higher operating, maintenance and general expenses of $1.8 million in 2010 versus 2009 primarily attributable to:

o	A $4 million increase in outside service costs related to field operations primarily attributable to the timing of ongoing in-line pipeline integrity testing costs;

o	A $1.3 million increase in electric power costs associated with the LNG terminal operations primarily due to the LNG terminal infrastructure enhancement construction project placed in service in March 2010 and a higher number of LNG cargoes during 2010;

o	A $1.6 million increase in legal costs primarily due to ongoing litigation;

o	Impact of a net reduction of $3.5 million in the 2010 period in the repair and abandonment cost provision for Hurricanes Ike and Gustav resulting from favorable weather conditions experienced and increased project efficiencies; and

o	A $1 million decrease in contract storage primarily due to a contract termination in March 2010; and

Increased depreciation and amortization expense of $2.4 million in 2010 versus 2009 due to a $575.4 million increase in property, plant and equipment placed in service after June 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.

Equity earnings, mainly attributable to the Company’s unconsolidated investment in Citrus, were higher by $3.8 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 $7.5 million largely driven by higher equity AFUDC resulting from Florida Gas’ Phase VIII Expansion project. Due to the increasing levels of capitalized project costs, AFUDC is expected to continue to trend higher until completion of the Phase VIII Expansion project;

Higher operating revenues of $1.9 million primarily due to 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;

Higher debt interest cost of $500,000 primarily due to interest on the $600 million 7.90% Senior Notes issued in May 2009 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, primarily due to higher Phase VIII Expansion project capital expenditures;

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

·	Higher depreciation expense of $1 million primarily due to increased property, plant and equipment placed in service after June 30, 2009; and

·	Higher income taxes of $2.6 million primarily due to higher pretax earnings.

Six-month period ended June 30, 2010 versus the six-month period ended June 30, 2009. The $22.5 million EBIT improvement in the six-month period ended June 30, 2010 versus the same period in 2009 was primarily due to a higher EBIT contribution from Panhandle totaling $17.3 million and higher equity earnings of $5.2 million, principally from the Company’s unconsolidated investment in Citrus.

Panhandle’s $17.3 million EBIT improvement was primarily due to:

·	Lower operating, maintenance and general expenses of $13.3 million in 2010 versus 2009 primarily attributable to:

Impact of a provision for repair and abandonment costs of $16.1 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 $3.5 million primarily due to favorable weather conditions experienced and increased project efficiencies;

o	A $2.7 million decrease in fuel tracker costs primarily due to a net under-recovery in 2009 versus a net over-recovery in 2010;

o	A $4.6 million increase in outside service costs for field operations primarily attributable to offshore operations and the timing of ongoing in-line pipeline integrity testing costs;

o	A $2.5 million increase in administrative outside service costs primarily due to legal costs associated with ongoing litigation; and

o	Higher allocated corporate services costs of $2.5 million primarily due to higher short- and long-term incentive compensation;

·	Higher operating revenues of $8.9 million primarily due to:

o	Higher LNG revenues of $25.3 million primarily due to the LNG terminal infrastructure enhancement construction project placed in service in March 2010;

o	Higher transportation commodity revenues of $3.1 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 $16.1 million due to less favorable market conditions; and

o	Lower transportation reservation revenues of $4.7 million primarily due to lower average rates realized on short-term firm capacity on PEPL, in addition to lower average rates realized on Trunkline; and

Increased depreciation and amortization expense of $3.7 million in 2010 versus 2009 due to a $575.4 million increase in property, plant and equipment placed in service after June 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.

Equity earnings, mainly attributable to the Company’s unconsolidated investment in Citrus, were higher by $5.2 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 $14.7 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 $3.2 million primarily due to 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;

Higher debt interest cost of $3.9 million primarily due to interest on the $600 million 7.90% Senior Notes issued in May 2009 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, primarily due to higher Phase VIII Expansion project capital expenditures;

·	Higher operating expenses of $2.1 million primarily due to higher overall costs experienced in 2010 applicable to corporate service costs, outside services costs and other operating costs;

·	Higher depreciation expense of $2 million primarily due to increased property, plant and equipment placed in service after June 30, 2009; and

·	Higher income taxes of $3.6 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.

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	(In thousands)

Operating revenues, excluding impact of
commodity derivative instruments	$	255,917		$	177,624		$	522,627		$	356,001
Realized and unrealized commodity derivatives		26,790			(2,540	)		20,940			(12,612	)
Operating revenues		282,707			175,084			543,567			343,389
Cost of gas and other energy (1)		(205,792	)		(141,269	)		(422,249	)		(284,398	)
Gross margin (2)		76,915			33,815			121,318			58,991
Operating, maintenance and general		18,489			18,123			38,363			37,785
Depreciation and amortization		17,971			16,543			35,291			32,956
Taxes other than on income and revenues		1,331			1,166			2,965			2,506
Total operating income		39,124			(2,017	)		44,699			(14,256	)
Earnings from unconsolidated investments		1,395			498			2,380			1,026
Other expense, net		7			(4	)		2			274
EBIT	$	40,526		$	(1,523	)	$	47,081		$	(12,956	)


Operating Statistics:
Volumes
Avg natural gas processed (MMBtu/d)		436,178			407,777			425,052			414,304
Avg NGL produced (gallons/d)		1,483,284			1,394,504			1,426,420			1,382,674
Avg natural gas wellhead volumes (MMBtu/d)		545,105			600,358			536,927			589,518
Natural gas sales (MMBtu) (3)		20,572,042			23,671,746			40,381,059			45,228,917
NGL sales (gallons) (3)		163,849,470			144,398,030			306,449,086			310,489,377

Average Pricing
Realized natural gas ($/MMBtu) (4)	$	4.07		$	3.06		$	4.58		$	3.27
Realized NGL ($/gallon) (4)		1.04			0.71			1.08			0.65
Natural Gas Daily WAHA ($/MMBtu)		4.13			3.11			4.59			3.26
Natural Gas Daily El Paso ($/MMBtu)		4.04			3.02			4.52			3.17
Estimated plant processing spread ($/gallon)		0.61			0.41			0.64			0.35

________________

(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 June 30, 2010 and 2009, the Company’s operating revenues and related volumes attributable to its buy-sell arrangements for natural gas totaled $11.3 million and $9.8 million, and 2,388,000 MMBtus and 3,088,000 MMBtus, respectively. The Company’s operating revenues and related volumes for the three-month periods ended June 30, 2010 and 2009 attributable to its buy-sell arrangements for NGL totaled $30.8 million and $14.6 million, and 32,418,000 gallons and 22,280,000 gallons, respectively. For the six-month periods ended June 30, 2010 and 2009, the Company’s operating revenues and related volumes attributable to its buy-sell arrangements for natural gas totaled $24.6 million and $21.5 million, and 4,749,000 MMBtus and 6,344,000 MMBtus, respectively. The Company’s operating revenues and related volumes for the six-month periods ended June 30, 2010 and 2009 attributable to its buy-sell arrangements for NGL totaled $57 million and $26.5 million, and 58,359,000 gallons and 43,114,000 gallons, respectively.

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

Three-month period ended June 30, 2010 versus the three-month period ended June 30, 2009. The $42 million EBIT improvement in the three-month period ended June 30, 2010 versus the same period in 2009 was primarily due to the following items:

·	Higher gross margin of $43.1 million primarily as the result of:

Higher operating revenues of $78.3 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 $4.07 per MMBtu and $1.04 per gallon in the 2010 period versus $3.06 per MMBtu and $0.71 per gallon in the 2009 period, respectively, partially offset by the impact of higher fractionation fees related to the change in fractionation provider in 2010;

o	Higher market-driven natural gas and NGL purchase costs of $62.1 million in the 2010 period versus the 2009 period; and

o	Impact of a net hedging gain of $26.8 million in the 2010 period versus a net hedging loss of $2.5 million in the 2009 period (which includes the impact of $22.3 million of unrealized gains recorded in 2010); and

·	Higher depreciation and amortization expense of $1.4 million primarily attributable to a $48.4 million increase in property, plant and equipment placed in service after June 30, 2009.

Six-month period ended June 30, 2010 versus the six-month period ended June 30, 2009. The $60 million EBIT improvement in the six-month period ended June 30, 2010 versus the same period in 2009 was primarily due to the following items:

·	Higher gross margin of $62.3 million primarily as the result of:

Higher operating revenues of $166.6 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 $4.58 per MMBtu and $1.08 per gallon in the 2010 period versus $3.27 per MMBtu and $0.65 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 and higher fractionation fees related to the change in fractionation provider in 2010;

o	Higher market-driven natural gas and NGL purchase costs of $133.5 million in the 2010 period versus the 2009 period; and

o	Impact of a net hedging gain of $20.9 million in the 2010 period versus a net hedging loss of $12.6 million in the 2009 period (which includes the impact of $16.7 million of unrealized gains recorded in 2010);

·	Higher depreciation and amortization expense of $2.3 million primarily attributable to a $48.4 million increase in property, plant and equipment placed in service after June 30, 2009; and

·	Higher equity earnings from unconsolidated investments of $1.4 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.

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 continued 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						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	(In thousands)

Net operating revenues (1)	$	54,955		$	49,246		$	124,239		$	117,434

Operating, maintenance and general		36,558			37,692			65,877			66,921
Depreciation and amortization		7,967			7,808			15,923			15,479
Taxes other than on income and revenues		3,271			3,790			6,512			6,882
Total operating income (loss)		7,159			(44	)		35,927			28,152
Other income (expenses), net		(294	)		(247	)		(217	)		3,195
EBIT	$	6,865		$	(291	)	$	35,710		$	31,347

Operating Information:
Natural Gas sales volumes (MMcf)		7,285			9,166			40,842			38,806
Natural Gas transported volumes (MMcf)		5,613			5,617			14,756			13,966

Weather – Degree Days: (2)
Missouri Gas Energy service territories		287			459			3,174			2,953
New England Gas Company service territories		777			777			3,375			3,747

________________

(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 June 30, 2010 versus the three-month period ended June 30, 2009. The $7.2 million EBIT improvement in the three-month period ended June 30, 2010 versus the same period in 2009 was primarily due to:

Higher net operating revenues of $5.7 million primarily due to $6.4 million of higher net operating revenues at Missouri Gas Energy largely attributable to the impact of the new rates effective February 28, 2010, which eliminated the impact of weather and conservation for the majority of Missouri Gas Energy’s revenues; and

·	Lower operating, maintenance and general expenses of $1.1 million primarily due to a $1.5 million settlement for a previous environmental cost reimbursement claim made by the Company.

Six-month period ended June 30, 2010 versus the six-month period ended June 30, 2009. The $4.4 million EBIT improvement in the six-month period ended June 30, 2010 versus the same period in 2009 was primarily due to:

Higher net operating revenues of $6.8 million primarily due to $7.7 million of higher net operating revenues at Missouri Gas Energy largely attributable to the impact of the new 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 $1.1 million at New England Gas Company primarily due to warmer weather in the 2010 period;

·	Lower other income, net, of $3.4 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

·	Lower operating, maintenance and general expenses of $1 million primarily due to a $1.5 million settlement for a previous environmental cost reimbursement claim made by the Company.

Corporate and Other Activities.

Three-month period ended June 30, 2010 versus the three-month period ended June 30, 2009. The EBIT improvement of $900,000 was primarily due to a higher net sales margin contribution of $2.1 million from PEI Power Corporation largely due to increased electric generation attributable to higher landfill gas volumes, partially offset by higher fuel costs of $700,000 resulting from the increased flow of landfill gas.

Six-month period ended June 30, 2010 versus the six-month period ended June 30, 2009. The EBIT improvement of $400,000 was primarily due to:

·	A higher net sales margin contribution of $3.3 million from PEI Power Corporation largely due to increased electric generation primarily attributable to higher landfill gas volumes, partially offset by higher fuel costs of $1 million resulting from the increased flow of landfill gas; and

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

Interest Expense

Three-month period ended June 30, 2010 versus the three-month period ended June 30, 2009. Interest expense was $7.1 million higher in the period ended June 30, 2010 versus the same period in 2009 primarily due to:

Higher interest expense of $6.1 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 $500,000 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;

·	Higher interest expense of $300,000 associated with borrowings under the Company’s credit facilities primarily due to higher average interest rates and higher average outstanding balances in 2010 compared to 2009; and

Higher net interest expense of $300,000 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 $60.6 million 6.50% Senior Notes in July 2009, the $100 million 6.089% Senior Notes in February 2010 and the $40.5 million 8.25% Senior Notes in April 2010.

Six-month period ended June 30, 2010 versus the six-month period ended June 30, 2009. Interest expense was $9.6 million higher in the period ended June 30, 2010 versus the same period in 2009 primarily due to:

Higher interest expense of $5.9 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 $3 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 $60.6 million 6.50% Senior Notes in July 2009, the $100 million 6.089% Senior Notes in February 2010 and the $40.5 million 8.25% Senior Notes in April 2010;

Higher interest expense of $1.6 million 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; and

·	Lower interest expense of $794,000 associated with borrowings under the Company’s credit facilities primarily due to lower average interest rates in 2010 compared to 2009, partially offset by the impact of higher average balances outstanding in 2010 compared to 2009.

Federal and State Income Taxes

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	(In thousands)

Income tax expense	$	28,609		$	13,835		$	59,418		$	33,450
Effective tax rate (1)		28	%		29	%		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 June 30, 2010 versus the three-month period ended June 30, 2009. The $14.8 million increase in federal and state income tax expense was primarily due to higher pre-tax earnings of $56.4 million in 2010.

Six-month period ended June 30, 2010 versus the six-month period ended June 30, 2009. The $26 million increase in federal and state income tax expense was primarily due to higher pre-tax earnings of $77.8 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.

Loss on Extinguishment of Preferred Stock

Three-month period ended June 30, 2010 versus the three-month period ended June 30, 2009. Net earnings available for common stockholders were reduced by $3.3 million in the 2010 period due to the impact of a $3.3 million loss recorded in the 2010 period related to the Company’s call for redemption of all of its approximately $115 million of outstanding Preferred Stock.

Six-month period ended June 30, 2010 versus the six-month period ended June 30, 2009. Net earnings available for common stockholders were reduced by $3.3 million in the 2010 period due to the impact of a $3.3 million loss recorded in the 2010 period related to the Company’s call for redemption of all of its approximately $115 million of outstanding Preferred Stock.

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 June 30, 2010 was $217 million. Additional sources of liquidity for working capital purposes include the use of available credit facilities and may include various equity offerings and debt capital markets and 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

	Six months ended June 30,
	2010			2009
	(In thousands)
Cash flows provided by (used in):
Operating activities	$	242,492		$	381,825
Investing activities		(129,020	)		(230,371	)
Financing activities		(121,429	)		(140,540	)
Increase (decrease) in cash and cash equivalents	$	(7,957	)	$	10,914

Operating Activities

Cash provided by operating activities decreased by $139.3 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 $259.2 million compared with $210.1 million for the 2009 period, an increase of $49.1 million primarily resulting from higher net earnings in 2010. Changes in operating assets and liabilities used cash of $16.7 million in the 2010 period and provided cash of $171.8 million in the 2009 period, resulting in a decrease in cash from changes in operating assets and liabilities of $188.4 million in 2010 compared to 2009. The $188.4 million decrease was primarily due to:

·	Decreased net cash settlements of $52.9 million of commodity derivative instruments in the Gathering and Processing segment in the 2010 period versus the 2009 period;

·	Increased accounts receivables of $48 million in the Distribution segment primarily due to colder weather for Missouri Gas Energy’s nonresidential customers in the 2010 period and the impact of the new rates effective February 28, 2010;

·	Increased accounts receivables of $23.2 million in the Gathering and Processing segment primarily due to higher operating revenues in the 2010 period attributable to higher market-driven realized average natural gas and NGL prices; and

·	Increased Distribution segment inventories of $47.8 million in the 2010 period primarily due to higher natural gas prices.

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 six months ended June 30, 2010 and 2009 were $129 million and $230.4 million, respectively. The $101.4 million decrease in investing cash outflows was primarily due to a $103.3 million decrease in capital expenditures in the Transportation and Storage segment, partially offset by a $23.8 million increase in capital expenditures in the Gathering and Processing segment in the 2010 period.

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.

	Six Months Ended
	June 30,
	2010			2009
	(In thousands)
Transportation and Storage Segment:
LNG Terminal Expansions/Enhancements (1)	$	20,478		$	58,863
Compression Modernization		(304	)		4,887
Other, primarily pipeline integrity, system
reliability, information technology, air
emission compliance and hurricane
expenditures		36,083			66,138
Total		56,257			129,888

Gathering and Processing Segment		41,706			16,518

Distribution Segment:
Missouri Safety Program		4,611			6,348
Other, primarily system replacement
and expansion		11,644			16,920
Total		16,255			23,268

Corporate and other activities		6,281			17,003

Total (2)	$	120,499		$	186,677

_______________

(1)	The Trunkline LNG infrastructure enhancement construction project was placed into service in March 2010. Total construction costs are expected to be approximately $440 million, plus capitalized interest.

(2)	Includes net period changes in capital accruals totaling $(7.9) million and $20.3 million for the six-month periods ended June 30, 2010 and 2009, respectively.

Potential Sea Robin Impairment. Sea Robin, comprised primarily of offshore facilities, suffered damage related to several platforms and gathering pipelines from Hurricane Ike. 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 $135 million of the approximately $185 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 it 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.

Citrus Equity Fundings. Prior to the in-service date of the Phase VIII Expansion project, it is expected Citrus will require equity contributions from each of its sponsors of up to $250 million. It is expected the majority of the estimated sponsor equity contributions to Citrus will be made in the fourth quarter of 2010 and/or first quarter of 2011. Citrus also does not plan to make any cash dividends to its sponsors until after the Phase VIII Expansion project is in service.

Financing Activities

Financing activities used cash of $121.4 million and $140.5 million in the six months ended June 30, 2010 and 2009, respectively. The $19.1 million decrease in net financing cash outflows were primarily due to:

·	Borrowings of $76.1 million under the Company’s credit facilities in the 2010 period compared to $251.5 million in payments in 2009; and

·	Net repayment of $139.9 million of long-term debt in the 2010 period, compared to net issuances of $151.5 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 the credit facilities.

Redemption of Preferred Stock. On June 29, 2010, the Company announced that it had called for redemption on July 30, 2010 all outstanding Depositary Shares representing interests in its Preferred Stock at $25 per share plus accrued and unpaid dividends. Accordingly, the Company reclassified the $115 million balance previously reported as Preferred stock in the Condensed Consolidated Balance Sheet to Current liabilities – Preferred stock – redeemable.

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 will be 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 August 3, 2010, there was a balance of $205.8 million outstanding under the Company’s credit facilities, with an effective interest rate of 3.07 percent.

As of August 3, 2010, the interest rate on the $465 million term loan was 0.88 percent.

Credit Ratings. As of June 30, 2010, both Southern Union’s and Panhandle’s debt were rated BBB- by Fitch Ratings, Baa3 by Moody's Investor Services, Inc. and BBB- by Standard & Poor's. 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," both borrowing costs and the costs of maintaining certain contractual relationships could increase. Lower credit ratings could also adversely affect relationships with state regulators, who may be unwilling to allow the Company to pass along increased debt service costs to natural gas customers.

For additional related information, see Part 1, Item 1. Financial Statements (Unaudited), 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.

Matter Impacting the Company’s Unconsolidated Investment in Citrus

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

Rate Matters

Trunkline LNG Cost and Revenue Study. On July 1, 2009, Trunkline LNG filed a Cost and Revenue Study with respect to the Trunkline LNG facility expansions completed in 2006, in compliance with FERC orders. 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 subject to rehearing.

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

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 June 30, 2010, the interest rate on 85 percent of the Company’s long-term debt was fixed after considering the impact of interest rate swaps.

At June 30, 2010, $18.4 million is included in Derivative instruments – liabilities, and $12.5 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 June 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 $600,000 for each month during which such change continued. If interest rates changed significantly, the Company may take actions to manage its exposure to the change.

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

The change in exposure to loss in earnings and cash flow related to interest rate risk for the six-month period ended June 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.

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 June 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		-	$	3,920
Receive-fixed swap	Gas Daily - Waha	$	6.12		-		13,813		5,229
Receive-fixed swap	Gas Daily - El Paso Permian	$	5.33		20,137		-		3,175
Receive-fixed swap	Gas Daily - El Paso Permian	$	6.12		-		11,187		4,235
		Total			45,000		25,000	$	16,559

Processing Spread - Economic Hedges: (2)
Receive-fixed swap	Gas Daily - Waha (natural gas)
	OPIS - Mt. Belvieu (NGL)	$	5.11		22,100		-	$	(4,774	)
Receive-fixed swap	Gas Daily - Waha (natural gas)
	OPIS - Mt. Belvieu (NGL)	$	5.51		-		13,813		243
Receive-fixed swap	Gas Daily - El Paso Permian (natural gas)
	OPIS - Mt. Belvieu (NGL)	$	5.11		17,900		-		(3,866	)
Receive-fixed swap	Gas Daily - El Paso Permian (natural gas)
	OPIS - Mt. Belvieu (NGL)	$	5.51		-		11,187		197
		Total			40,000		25,000	$	(8,200	)

__________________

(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 July 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.

At June 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 $4.9 million, respectively. Such commodity price risk estimates do not include any effect on demand for the Company’s services that may be caused by, or arise in conjunction with, price changes. For example, a change in the gross processing spread may cause some ethane to be sold in the natural gas stream, impacting gathering and processing margins, natural gas deliveries and NGL volumes shipped.

Transportation and Storage Segment. The Company is exposed to some commodity price risk with respect to natural gas used in operations by its interstate pipelines. Specifically, the pipelines receive natural gas from customers for use in 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 Company. In addition, there is other indirect exposure to the extent commodity price changes affect customer demand for and utilization of transportation and storage services provided by the Company. At June 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 pay-fixed natural gas price swaps 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 June 30, 2010 and December 31, 2009, the fair values of the contracts, which expire at various times through June 2012, are included in the unaudited interim Condensed Consolidated Balance Sheet as liabilities, with matching adjustments to deferred natural gas purchases of $35.9 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 participation of personnel from its Legal, Internal Audit, Risk Management and Financial Reporting Departments, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this report. Based on that evaluation, Southern Union’s CEO and CFO concluded that the Company’s disclosure controls and procedures were effective as of June 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 June 30, 2010 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Cautionary Statement Regarding Forward-Looking Information

The disclosure and analysis in this Form 10-Q contains some forward-looking statements that set forth anticipated results based on management’s current plans and assumptions. From time to time, the Company also provides forward-looking statements in other materials it releases to the public as well as oral forward-looking statements. Such statements give the Company’s current expectations or forecasts of future events; they do not relate strictly to historical or current facts. Southern Union has tried, wherever possible, to identify such statements by using words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “will” and similar expressions in connection with any discussion of future operating or financial performance. In particular, these include statements relating to future actions, future performance or results of current and anticipated services, expenses, interest rates, the outcome of contingencies, such as legal proceedings, and financial results.

The Company cannot guarantee that any forward-looking statement will be realized, although management believes that the Company has been prudent and reasonable in its plans and assumptions. Achievement of future results is subject to risks, uncertainties and potentially inaccurate assumptions. If known or unknown risks or uncertainties should materialize, or if underlying assumptions should prove inaccurate, actual results could differ materially from past results and those anticipated, estimated or projected. Readers should bear this in mind as they consider forward-looking statements. The Company undertakes no obligation publicly to update forward-looking statements, whether as a result of new information, future events or otherwise. Readers are advised, however, to consult any further disclosures the Company makes on related subjects in its Form 10-K, 10-Q and 8-K reports to the SEC. Also note that Southern Union provides the following cautionary discussion of risks, uncertainties and possibly inaccurate assumptions relevant to its businesses. These are factors that, individually or in the aggregate, management believes could cause the Company’s actual results to differ materially from expected and historical results. Southern Union notes these factors for investors as permitted by the Private Securities Litigation Reform Act of 1995. Readers should understand that it is not possible to predict or identify all such factors. Consequently, readers should not consider the following to be a complete discussion of all potential risks or uncertainties.

Factors that could cause actual results to differ materially from those expressed in the Company’s forward-looking statements include, but are not limited to, the following:

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

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

·	changes in laws or regulations, third-party relations and approvals, decisions of courts, regulators and governmental bodies affecting or involving Southern Union, 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 is introduced to Southern Union’s business and the resulting effect on revenues;

·	the outcome of pending and future litigation;

·	the Company’s ability to comply with or to challenge successfully existing or new environmental regulations;

·	unanticipated environmental liabilities;

·	the Company’s exposure to highly competitive commodity businesses through its Gathering and Processing segment;

·	the Company’s 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 Company’s 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;

·	exposure to customer concentration 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 debt securities of Southern Union or any of its subsidiaries;

·	changes in interest rates and other general capital markets conditions, and in the Company’s ability to continue to access the capital markets;

·	acts of nature, sabotage, terrorism or other acts causing damage greater than the Company’s insurance coverage limits;

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

·	other risks and unforeseen events.

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.

On May 6, 2010, 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 subject to various challenges filed in the U.S. District Court, 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 by a ruling in the U.S. District Court on June 23, 2010. The DOI appealed the ruling to the U.S. Court of Appeals for the 5th Circuit. In July 2010, the DOI issued a separate revised six-month moratorium on new offshore drilling operations. It is expected that this moratorium will also be subject to court challenges. Additionally, the United States Mineral Management Service has been fundamentally restructured by the DOI with the intent of providing enhanced oversight of onshore and offshore drilling operations for regulatory compliance enforcement, energy development and revenue collection. Although it is not possible at this time to predict whether or when new drilling or production operating regulations will be implemented, any additional regulation would likely increase the cost of both offshore and onshore drilling and production operations. The increased cost of drilling operations could result in decreased drilling activity in the areas serviced by the Company. Furthermore, if the drilling moratorium remains intact, the impact of the moratorium could result in offshore drilling companies relocating their offshore drilling operations to regions outside of the United States. Such matters could result in a reduction in the future development and production of natural gas reserves in the vicinity of the Company’s facilities, which could adversely affect the Company’s business, financial condition, results of operations and cash flows.

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 June 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
April 2010		3,300	$	26.23
May 2010		36		21.93
June 2010		3,331		21.99
Total		6,667	$	24.09

__________________

(1)

The total number of shares purchased includes: (i) the surrender to the Company of 875 shares of common stock to satisfy tax withholding obligations in connection with the vesting of restricted stock awards and (ii) 5,792 shares of common stock purchased in open-market transactions and held in various Company employee benefit plan trusts by the trustees using cash amounts deferred by the participants in such plans (and quarterly cash dividends issued by the Company on shares held in such plans.)

ITEM 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 June 30, 2010 was appropriately reported.

On August 3, 2010, the Company, entered into the 2010 Term Loan maturing on August 3, 2013, filed herewith as Exhibit 10(b). 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 will be 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.

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.)

4(e)

Form of Supplemental Indenture No. 1, dated June 11, 2003, between Southern Union Company and JP Morgan Chase Bank, which changed its name to JP Morgan Chase Bank, N.A., the predecessor to The Bank of New York Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A. (Filed as Exhibit 4.5 to Southern Union’s Form 8-A/A dated June 20, 2003 and incorporated herein by reference.)

4(f)

Supplemental Indenture No. 2, dated February 11, 2005, between Southern Union Company and JP Morgan Chase Bank, N.A., the predecessor to The Bank of New York Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A. (Filed as Exhibit 4.4 to Southern Union’s Form 8-A/A dated February 22, 2005 and incorporated herein by reference.)

4(g)

Subordinated Debt Securities Indenture between Southern Union and The Chase Manhattan Bank (National Association), which changed its name to JP Morgan Chase Bank and then to JP Morgan Chase Bank, N.A., which was then succeeded to by The Bank of New York Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A., as Trustee (Filed as Exhibit 4-G to Southern Union’s Registration Statement on Form S-3 (No. 33-58297) and incorporated herein by reference.)

4(h)

Second Supplemental Indenture, dated October 23, 2006, between Southern Union Company and The Bank of New York Trust Company, N.A., now known as The Bank of New York Mellon Trust Company, N.A. (Filed as Exhibit 4.1 to Southern Union’s Form 8-K/A dated October 24, 2006 and incorporated herein by reference.)

4(i)

2006 Series A Junior Subordinated Notes Due November 1, 2066 dated October 23, 2006. (Filed as Exhibit 4.2 to Southern Unions Current Report on Form 8-K/A filed on October 24, 2006 and incorporated herein by reference.)

4(j)

Replacement Capital Covenant, dated as of October 23, 2006 by Southern Union Company, a Delaware corporation with its successors and assigns, in favor of and for the benefit of each Covered Debtor (as defined in the Covenant). (Filed as Exhibit 4.3 to Southern Union’s Current Report on Form 8-K/A filed on October 24, 2006 and incorporated herein by reference.)

4(k)	Southern Union is a party to other debt instruments, none of which authorizes the issuance of debt securities in an amount which exceeds 10% of the total assets of Southern Union. Southern Union hereby agrees to furnish a copy of any of these instruments to the Commission upon request.

10(a)

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

10(b)

Amended and Restated Credit Agreement, dated as of August 3, 2010, among the Company, as borrower, and the lenders party thereto (Filed herewith as Exhibit 10(b).

10(c)

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

10(d)

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

10(e)

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

10(f)

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

10(g)

Credit Agreement between Trunkline LNG Holdings, LLC, as borrower, Panhandle Eastern Pipeline Company, LP and Trunkline LNG Company, LLC, as guarantors, the financial institutions listed therein and Hypo-Und Vereinsbank AG, New York Branch, as administrative agent, dated as of March 15, 2007. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on March 21, 2007 and incorporated herein by reference.)

10(h)

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

10(i)

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

10(j)

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

10(k)

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

10(l)

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

10(m)

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

10(n)

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

10(o)

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

10(p)

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

10(q)

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

10(r)

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

10(s)

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

10(t)

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.)

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

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.

101.INS

XBRL Instance Document **

101.SCH

XBRL Taxonomy Extension Schema Document **

101.CAL

XBRL Taxonomy Calculation Linkbase Document **

101.DEF

XBRL Taxonomy Extension Definitions Document **

101.LAB

XBRL Taxonomy Label Linkbase Document **

101.PRE

XBRL Taxonomy Presentation Linkbase Document **

* Management contract or compensation plan or arrangement

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

SIGNATURES

Pursuant to the requirements of 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: August 5, 2010	By /s/ GEORGE E. ALDRICH
	George E. Aldrich Senior Vice President and Controller (authorized officer and principal accounting officer)