Edgar Filing: SOUTHERN UNION CO

Southern Union Company Form 10-Q 06/30/06

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

____________________________

FORM 10-Q

For the quarterly period ended

June 30, 2006

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

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

Title of each class		Name of each exchange in which registered
Common Stock, par value $1 per share		New York Stock Exchange
7.55% Depositary Shares		New York Stock Exchange
5.75% Corporate Units		New York Stock Exchange
5.00% Corporate Units		New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securi-ties 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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer P Accelerated filer Non-accelerated filer ____

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

Yes No ü

The number of shares of the registrant's Common Stock outstanding on August 4, 2006 was 112,061,207.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

FORM 10-Q

June 30, 2006

Table of Contents

PART I. FINANCIAL INFORMATION:	Page(s)

ITEM 1. Financial Statements (Unaudited):

Condensed consolidated statement of operations - three and six months ended June 30, 2006 and 2005.	2-3

Condensed consolidated balance sheet - June 30, 2006 and December 31, 2005.	4-5

Condensed consolidated statement of cash flows - six months ended June 30, 2006 and 2005.	6

Condensed consolidated statement of stockholders’ equity and comprehensive income - six months ended June 30, 2006.	7

Notes to condensed consolidated financial statements.	8-36

ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.	37-49

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.	49

ITEM 4. Controls and Procedures.	49-50

PART II. OTHER INFORMATION:

ITEM 1. Legal Proceedings.	51

ITEM 1A. Risk Factors.	51-55

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds.	55

ITEM 3. Defaults Upon Senior Securities.	55

ITEM 4. Submission of Matters to a Vote of Security Holders.	55

ITEM 5. Other Information.	55

ITEM 6. Exhibits.	55-59

SIGNATURES	60

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (UNAUDITED)

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

(UNAUDITED)

	Three months ended June 30,
	2006			2005
	(In thousands of dollars, except shares and per share amounts)

Operating revenues (Note 18)	$	552,355		$	195,236

Operating expenses:
Cost of gas and other energy		330,297			46,198
Revenue-related taxes		4,156			3,998
Operating, maintenance and general		98,357			80,412
Depreciation and amortization		38,657			23,591
Taxes, other than on income and revenues		11,096			8,913
Total operating expenses		482,563			163,112
Operating income		69,792			32,124

Other income (expenses):
Interest		(62,978	)		(29,894	)
Earnings from unconsolidated investments		15,833			20,232
Other, net (Note 8)		1,550			(346	)
Total other income (expenses), net		(45,595	)		(10,008	)

Earnings from continuing operations before income taxes		24,197			22,116

Federal and state income taxes (Note 15)		7,876			4,474

Net earnings from continuing operations		16,321			17,642

Discontinued operations (Note 19):
Losses from discontinued operations before income tax benefit		(4,460	)		(2,510	)
Federal and state income tax benefit (Note 15)		(1,873	)		(543	)
Net loss from discontinued operations		(2,587	)		(1,967	)

Net earnings		13,734			15,675

Preferred stock dividends		(4,341	)		(4,340	)

Net earnings available for common stockholders	$	9,393		$	11,335

Net earnings available for common stockholders from
continuing operations per share:
Basic	$	0.11		$	0.12
Diluted	$	0.10		$	0.12

Net earnings available for common stockholders per
share:
Basic	$	0.08		$	0.10
Diluted	$	0.08		$	0.10

Weighted average shares outstanding (Note 7):
Basic		111,944,643			110,787,049
Diluted		114,981,373			114,325,703

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

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

(UNAUDITED)

	Six months ended June 30,
	2006			2005
	(In thousands of dollars, except shares and per share amounts)

Operating revenues (Note 18)	$	1,099,521		$	647,336

Operating expenses:
Cost of gas and other energy		636,899			276,430
Revenue-related taxes		20,373			21,282
Operating, maintenance and general		177,135			149,246
Depreciation and amortization		69,521			46,635
Taxes, other than on income and revenues		22,954			19,764
Total operating expenses		926,882			513,357
Operating income		172,639			133,979

Other income (expenses):
Interest		(105,199	)		(63,483	)
Earnings from unconsolidated investments		27,399			35,574
Other, net (Note 8)		38,643			(5,436	)
Total other income (expenses), net		(39,157	)		(33,345	)

Earnings from continuing operations before income taxes		133,482			100,634

Federal and state income taxes (Note 15)		43,742			26,598

Net earnings from continuing operations		89,740			74,036

Discontinued operations (Note 19):
Earnings from discontinued operations before
income taxes		33,549			51,018
Federal and state income taxes (Note 15)		11,607			17,183
Net earnings from discontinued operations		21,942			33,835

Net earnings		111,682			107,871

Preferred stock dividends		(8,682	)		(8,681	)

Net earnings available for common stockholders	$	103,000		$	99,190

Net earnings available for common stockholders from
continuing operations per share:
Basic	$	0.72		$	0.61
Diluted	$	0.70		$	0.59

Net earnings available for common stockholders per
share:
Basic	$	0.92		$	0.92
Diluted	$	0.90		$	0.89

Weighted average shares outstanding (Note 7):
Basic		111,807,253			107,546,799
Diluted		114,993,178			111,139,659

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,
	2006			2005
	(In thousands of dollars)
Property, plant and equipment:
Plant in service	$	4,859,229		$	4,183,280
Construction work in progress		158,389			184,423
		5,017,618			4,367,703
Less accumulated depreciation and amortization		(545,141	)		(881,763	)
Net property, plant and equipment		4,472,477			3,485,940

Current assets:
Cash and cash equivalents		37,198			16,938
Accounts receivable, net of allowances of
$6,240 and $15,893, respectively		239,520			428,735
Accounts receivable – affiliates		11,775			8,827
Inventories (Note 6)		216,935			295,658
Gas imbalances - receivable		76,810			105,233
Prepayments and other assets		73,617			68,382
Assets held for sale		1,251,051			-
Total current assets		1,906,906			923,773

Goodwill		90,208			465,547

Deferred charges:
Regulatory assets (Note 9)		57,509			112,963
Deferred charges		92,683			113,793
Total deferred charges		150,192			226,756

Unconsolidated investments (Note 10)		709,953			682,834

Other		43,141			51,969


Total assets	$	7,372,877		$	5,836,819

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,
	2006			2005
	(In thousands of dollars)
Stockholders’ equity:
Common stock, $1 par value; authorized 200,000,000 shares;
issued 113,084,025 shares at June 30, 2006	$	113,084		$	112,530
Preferred stock, no par value; authorized 6,000,000 shares;
issued 920,000 shares at June 30, 2006		230,000			230,000
Premium on capital stock		1,687,693			1,681,167
Less treasury stock: 1,053,879 and 1,053,879
shares, respectively, at cost		(27,566	)		(27,566	)
Less common stock held in trust: 818,415
and 826,348 shares, respectively		(10,610	)		(12,910	)
Deferred compensation plans		10,674			10,173
Accumulated other comprehensive loss		(54,096	)		(56,272	)
Retained earnings (deficit)		-			(83,053	)
Total stockholders' equity		1,949,179			1,854,069

Long-term debt and capital lease obligation (Note 13)		1,522,694			2,049,141

Total capitalization		3,471,873			3,903,210

Current liabilities:
Long-term debt and capital lease obligation
due within one year (Note 13)		576,164			126,648
Notes payable (Note 13)		1,851,000			420,000
Accounts payable and accrued liabilities		202,411			206,504
Federal, state and local taxes payable		38,695			47,195
Accrued interest		41,324			40,688
Customer deposits		14,268			16,096
Deferred gas purchases		13,697			83,147
Gas imbalances - payable		113,538			124,297
Other		126,679			158,555
Liabilities related to assets held for sale		204,633			-
Total current liabilities		3,182,409			1,223,130

Deferred credits:
Regulatory liabilities (Note 9)		7,142			10,070
Deferred credits		291,221			303,919
Total deferred credits		298,363			313,989

Accumulated deferred income taxes		420,232			396,490

Commitments and contingencies (Note 17)

Total stockholders' equity and liabilities	$	7,372,877		$	5,836,819

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,
	2006			2005
	(In thousands of dollars)
Cash flows provided by operating activities:
Net earnings	$	111,682		$	107,871
Adjustments to reconcile net earnings to net cash flows
provided by operating activities:
Depreciation and amortization		69,521			63,264
Amortization of debt premium		(1,281	)		(1,229	)
Deferred income taxes		28,204			41,697
Provision for bad debts		8,847			14,050
Impairment of assets		6,500			508
Amortization of debt expense		5,756			2,963
Gain on derivative		(37,182	)		-
Earnings from unconsolidated investments		(27,399	)		(35,573	)
Other		422			(147	)
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable		102,339			132,154
Accounts payable and accrued liabilities		(59,414	)		(58,858	)
Gas imbalances payable		(65	)		(727	)
Customer deposits		2,996			267
Deferred gas purchases		(52,523	)		53,389
Inventories		(13,710	)		3,158
Deferred charges and credits		43,777			(13,902	)
Prepayments and other assets		37,572			9,259
Taxes and other liabilities		(2,569	)		(10,660	)
Net cash provided by operating activities of discontinued operations		76,592			-
Net cash flows provided by operating activities		300,065			307,484
Cash flows (used in) provided by investing activities:
Additions to property, plant and equipment		(110,311	)		(135,531	)
Acquisitions of operations, net of cash received		(1,537,111	)		-
Net cash used in investing activities of discontinued operations		(24,551	)		-
Other		2,225			(2,181	)
Net cash flows used in investing activities		(1,669,748	)		(137,712	)
Cash flows provided by (used in) financing activities:
Increase (decrease) in bank overdraft		(20,992	)		1,740
Issuance costs of debt		(9,195	)		(680	)
Issuance of common stock		-			331,772
Issuance of equity units		-			100,000
Issuance cost of equity units		-			(2,622	)
Issuance of long-term debt		-			255,626
Dividends paid on common stock		(11,175	)		-
Dividends paid on preferred stock		(8,682	)		(8,681	)
Repayment of debt and capital lease obligation		-			(334,609	)
Issuance of bridge loan		1,600,000			-
Net payments under revolving credit facilities		(169,000	)		(547,000	)
Proceeds from exercise of stock options		6,334			3,958
Tax benefit on stock option exercises		2,653			-
Other		-			1,282
Net cash flows provided by (used in) financing activities		1,389,943			(199,214	)
Change in cash and cash equivalents		20,260			(29,442	)
Cash and cash equivalents at beginning of period		16,938			30,053
Cash and cash equivalents at end of period	$	37,198		$	611

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)

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

Balance December 31, 2005	$	112,530	$	230,000	$	1,681,167		$	(27,566	)	$	(12,910	)	$	10,173		$	(56,272	)	$	(83,053	)	$	1,854,069

Comprehensive income (loss):
Net earnings		-		-		-			-			-			-			-			111,682			111,682
Unrealized loss on hedging																								-
activities, net of tax		-		-		-			-			-			-			(73	)		-			(73	)
Change in fair value of hedging
derivative, net of tax		-		-		-			-			-			-			2,249			-			2,249
Comprehensive income																					-			113,858
Preferred stock dividends		-		-		-			-			-			-			-			(8,682	)		(8,682	)
Cash dividends declared		-		-		(2,425	)		-			-			-			-			(19,947	)		(22,372	)
Share-based compensation		-		-		3,319			-			-			-			-			-			3,319
Implementation of FAS 123R		-		-		(2,801	)		-			2,801			-			-			-			-
Restricted stock issuances		125		-		(125	)		-			-			-			-			-			-
Exercise of stock options		429		-		8,558			-			-			-			-			-			8,987
Contributions to Trust		-		-		-			-			(1,862	)		1,862			-			-			-
Disbursements from Trust		-		-		-			-			1,361			(1,361	)		-			-			-
Balance June 30, 2006	$	113,084	$	230,000	$	1,687,693		$	(27,566	)	$	(10,610	)	$	10,674		$	(54,096	)	$	-		$	1,949,179

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 outstanding.

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 Southern Union Company (Southern Union), including all of its subsidiaries (collectively, the Company), have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) for quarterly reports on Form 10-Q. These statements do not include all of the information and note disclosures required by accounting principles generally accepted in the United States of America (GAAP), and should be read in conjunction with the Company’s financial statements and notes thereto for the twelve months ended December 31, 2005, included in the Company’s Form 8-K filed with the SEC on July 17, 2006. 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. Because of 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 prior period amounts have been reclassified to conform with the current period 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, processing, transportation, storage, and distribution of natural gas in the United States. The Company operates in three reportable segments: the Transportation and Storage, Gathering and Processing and Distribution segments. The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas in the Midwest and Southwest 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, transmission, treating, processing and redelivery of natural gas and natural gas liquids in Texas and New Mexico. The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts. The Company’s discontinued operations relate to its PG Energy natural gas distribution division and the Rhode Island operations of its New England Gas Company division.

2. New Accounting Principles

FIN 48, “Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement 109” (FIN 48 or the Interpretation): Issued by the Financial Accounting Standards Board (FASB) in July 2006, this Interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. FIN 48 prescribes a recognition and measurement threshold attributable for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosures and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. The Company is currently evaluating the impact of this Interpretation on its consolidated financial statements.

3. Acquisition of Sid Richardson Energy Services

Overview

On March 1, 2006, Southern Union acquired 100 percent of the partnership interests in Sid Richardson Energy Services, Ltd. and related entities (collectively, Sid Richardson Energy Services) for $1.6 billion in cash. The acquisition was undertaken by the Company to increase its investment in higher growth businesses. The acquisition was funded under a short-term bridge loan facility in the amount of $1.6 billion. See Note 13 - Debt Obligations - Notes Payable for additional information related to the bridge loan facility.

The principal assets of the acquired Sid Richardson Energy Services business, now known as Southern Union Gas Services, are located in the Permian Basin of Texas and New Mexico and include approximately 4,800 miles of natural gas and natural gas liquids gathering pipelines, four cryogenic plants and six natural gas treating plants. Southern Union Gas Services is engaged in the gathering, transmission, treating, processing and redelivery of natural gas and natural gas liquids in Texas and New Mexico. Southern Union Gas Services’ activities primarily include 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 natural gas liquids, transporting natural gas and redelivering natural gas and natural gas liquids to a variety of markets. Southern

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Union Gas Services’ primary sales customers include producers, power generating companies, utilities, energy marketers and industrial users located primarily in the southwestern United States. Southern Union Gas Services receives hydrocarbons for purchase or transportation to market from over 200 producers and suppliers, none of which account for more than 15 percent of its total hydrocarbon throughput. Southern Union Gas Services’ major natural gas pipeline interconnects are with ATMOS Pipeline, El Paso Natural Gas Company, Energy Transfer Fuel, LP, Enterprise Pipeline and Transwestern Pipeline Company, LLC (Transwestern), an affiliate of the Company. Its major natural gas liquids pipeline interconnects are with Chapparal, Louis Dreyfus and Chevron.

Purchase Accounting

The acquisition was accounted for using the purchase method of accounting, with the purchase price paid by the Company allocated to Southern Union Gas Services’ net assets as of the acquisition date based on their fair values. Southern Union Gas Services’ assets acquired and liabilities assumed have been recorded in the Condensed Consolidated Balance Sheet beginning March 1, 2006 at their estimated fair values and have been adjusted to reflect the results of a third-party appraisal. Southern Union Gas Services’ results of operations have been included in the Condensed Consolidated Statement of Operations since March 1, 2006. Thus, the Condensed Consolidated Statement of Operations for the periods subsequent to the acquisition are not comparable to the same periods in prior years.

The following table summarizes the estimated fair values of Southern Union Gas Services’ assets acquired and liabilities assumed at the date of acquisition.

	At March 1, 2006
	(In thousands)

Property, plant and equipment (1)	$	1,566,445
Goodwill (2)		981
Current assets (3)		156,732
Other non-current assets		2,288
Total assets acquired		1,726,446
Current liabilities		142,074
Deferred taxes		(3,008	)
Other non-current liabilities		1,672
Total liabilities assumed		140,738
Net assets acquired (4)	$	1,585,708

(1)	The Company expects to finalize the purchase price allocation before the 2006 year-end. Property, plant and equipment includes an initial allocation of $18.3 million

to other intangibles for leases, software and contracts with weighted-average lives of 4 years, 5 years and 3 years, respectively.

(2)	The purchase price included goodwill because of the expected synergies to be derived with the combined

operation. The amount allocated to Goodwill is expected to be deductible for tax purposes.

(3)	Includes cash and cash equivalents of approximately $53.7 million.

(4)	Reflects final working capital adjustments of $11.0 million from the $1.6 billion purchase price.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The following unaudited pro forma financial information for the periods presented is reported as though the following events had occurred at the beginning of the earliest period presented: (i) acquisition of Sid Richardson Energy Services, (ii) issuance of the bridge loan facility and (iii) removal of interest expense associated with seller’s pre-acquisition debt not assumed by Southern Union. The pro forma financial information is not necessarily indicative of the results that would have been obtained if the acquisition of Sid Richardson Energy Services and the issuance of the bridge loan facility had been completed as of the assumed date for the period presented or of the results that may be obtained in the future.

	Three Months		Six Months
	Ended June 30,		Ended June 30,
	2005		2006		2005
	(In thousands)

Operating revenue	$	507,335	$	1,330,070	$	1,199,083
Net earnings available for common shareholders
from continuing operations		9,798		70,764		51,346

Net earnings available for common shareholders from
continuing operations per share:
Basic	$	0.09	$	0.63	$	0.48
Diluted	$	0.09	$	0.62	$	0.46

The pro forma financial information above reflects the impact of the temporary bridge loan facility, which the Company expects to retire with the proceeds from: (i) the sales of its Pennsylvania and Rhode Island distribution operations; and (ii) permanent debt and/or equity financing. To the extent the Company is successful at closing the sales of these operations and issuing permanent equity financing, ongoing interest expense associated with the acquisition financing will be less than amounts estimated in the pro forma financial information above.

Summary of Southern Union Gas Services’ Significant Accounting Policies

The following is a summary of significant accounting policies associated with Southern Union Gas Services that should be read in conjunction with the related accounting policies disclosure in the Company’s financial statements and notes thereto for the twelve months ended December 31, 2005, included in the Company’s Form 8-K dated July 17, 2006 filed with the SEC. This supplementary disclosure includes the significant accounting policies unique to Southern Union Gas Services that are not already encompassed by the related disclosure in the Company’s Form 8-K dated July 17, 2006 filed with the SEC.

Revenue and Cost of Sales Recognition. Revenue and the related cost of sales for natural gas and natural gas liquids are recognized in the period when the physical product is delivered to the customer at the contractually agreed-upon price and title is transferred. Cost of sales primarily includes the cost of purchased natural gas and natural gas liquids.

Southern Union Gas Services accounts for sale and purchase arrangements on a gross basis in the Condensed Consolidated Statement of Operations as Operating revenues and Cost of gas and other energy, respectively.

Contractual arrangements establish the purchase of natural gas and natural gas liquids at specified locations and the sale at different locations on the same or other specified dates. Both purchase and sale transactions require physical delivery of the natural gas and natural gas liquids. The transfer of ownership is evidenced by the purchaser’s assumption of title, price risk, credit risk, counterparty nonperformance risk, environmental risk and transportation scheduling.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

4. Stock Based Compensation

Stock Award Plans. On May 9, 2005, the stockholders of the Company adopted the Southern Union Company Amended and Restated 2003 Stock and Incentive Plan (Amended 2003 Plan). The Amended 2003 Plan allows for awards in the form of stock options (either incentive stock options or non-qualified options), stock appreciation rights, stock bonus awards, restricted stock, performance units or other equity-based and liability-based rights. The persons eligible to receive awards under the Amended 2003 Plan include all of the employees, directors, officers, agents and other service providers of the Company and its affiliates and subsidiaries. The Amended 2003 Plan provides that each non-employee director will receive annually a restricted stock award or, at the election of the non-employee director, options having an equivalent value, which will be granted at such time or times as the compensation committee shall determine. Under the Amended 2003 Plan: (i) no participant may receive in any calendar year awards covering more than 500,000 shares; (ii) the exercise price for a stock option may not be less than 100 percent of the fair market value of the common stock on the date of grant; and (iii) no award may be granted more than ten years after the date of the Amended 2003 Plan.

On May 2, 2006 the stockholders of the Company approved the adoption of the Second Amended 2003 Plan which included the following changes to the Amended 2003 Plan:

·	An increase from 7,000,000 to 9,000,000 in the aggregate number of shares of stock that may be issued under the Amended 2003 Plan;

·	An increase from 725,000 to 1,500,000 in the total number of shares of stock that may be issued pursuant to stock awards, performance units and other equity-based rights; and

·	An increase from 4,000 to 5,000 in the maximum number of shares of restricted common stock that each non-employee director is eligible to receive annually.

The Second Amended 2003 Plan will not become effective until approved by the Massachusetts Department of Telecommunications and Energy (MDTE). In anticipation of the Second Amended 2003 Plan becoming effective, the Compensation Committee of the Board of Directors approved a grant of 5,000 shares of restricted common stock to each of the non-employee directors. The restricted stock awards contain certain restrictions that expire on January 2, 2007. The award of restricted shares to the non-employee directors will become effective upon approval by the MDTE.

The Company maintains its 1992 Plan, under which options to purchase 8,491,540 shares of its common stock were authorized to be granted until July 1, 2002 to officers and key employees at prices not less than the fair market value on the date of grant. The 1992 Plan allowed for the granting of stock appreciation rights, dividend equivalents, performance shares and restricted stock. Options granted under the 1992 Plan are exercisable for periods of ten years from the date of grant or such lesser period as may be designated for particular options, and become exercisable after a specified period of time from the date of grant in cumulative annual installments. Options typically vest at the rate of 20 percent per year, but may vest over a longer or shorter period as designated for a particular option grant. At June 30, 2006 there were no shares available for future option grants under the 1992 Plan.

Stock Options. Effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123 (revised 2004), Share-Based Payment (Statement No. 123R), using the Modified Prospective Application method of transition, as defined in Statement No. 123R. After adoption of Statement No. 123R, the Company records the grant date fair value of share-based payment arrangements, net of estimated forfeitures, as compensation expense using a straight-line basis over the awards’ requisite service period. Prior to adoption, the Company used the intrinsic value method of accounting for stock-based compensation awards in accordance with APB Opinion No. 25, Accounting for Stock Issued to Employees, which generally resulted in no compensation expense for employee stock options with an exercise price no less than fair value on the date of grant. Under the Modified Prospective Application method, Statement No. 123R applies to new awards and to awards modified, repurchased, or cancelled after December 31, 2005. Compensation cost for the portion of awards for which the requisite service has not been rendered that are outstanding as of December 31, 2005 is recognized as the requisite service is rendered on or after January 1, 2006. Additionally, no transition adjustment is generally permitted for the deferred tax assets associated with outstanding equity instruments, as these deferred tax assets will be recorded as a credit to Premium on capital stock when realized. No cumulative effect of a change in accounting principle was recognized upon adoption of Statement No. 123R.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The Company has previously disclosed the fair value of stock options granted and the assumptions used in determining fair value pursuant to Statement No. 123, Accounting for Stock-Based Compensation. The Company has historically used a Black-Scholes valuation model to determine the fair value of stock options granted. Stock options (either incentive stock options or non-qualified options) and stock appreciation rights generally vest over a four- or five-year period from the date of grant and expire ten years after the date of grant. As of December 31, 2005, outstanding stock options totaled 2,549,833 of which 1,503,860 were vested. The remaining 1,045,973 stock options vest over 2006 and future periods and are used to determine compensation expense pursuant to the transition provisions of Statement No. 123R. The Company attributes the requisite service period to the vesting period. The adoption of Statement No. 123R reduced Operating Income, Earnings from continuing operations before income taxes, and Net earnings by $0.9 million, $0.9 million and $0.7 million, respectively, or $0.01 per basic share and $0.01 per diluted share, during the three months ended June 30, 2006. For the six-month period ended June 30, 2006, Operating Income, Earnings from continuing operations before income taxes, and Net earnings were reduced by $1.8 million, $1.8 million and $1.5 million respectively, or $0.01 per basic share and $0.01 per diluted share.

Pursuant to the Modified Prospective Application method of transition, the Company has not adjusted results of operations for prior periods. The following table reflects pro forma net income as was disclosed in the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 and net earnings per share adjusted for subsequent stock dividends that the Company would have reported if it had elected to adopt the fair value approach of Statement No. 123 prior to January 1, 2006:

	Three Months Ended		Six Months Ended
	June 30, 2005		June 30, 2005
		(In thousands of dollars, except per share amounts)

Net earnings, as reported	$	15,675	$	107,871
Deduct stock-based employee compensation
expense determined under fair value based method
for all awards, net of related taxes		373		712
Pro forma net earnings	$	15,302	$	107,159

Net earnings available for common stockholders per share:
Basic- as reported	$	0.10	$	0.92
Basic- pro forma	$	0.10	$	0.92

Diluted- as reported	$	0.10	$	0.89
Diluted- pro forma	$	0.10	$	0.89

The fair value of each option award is estimated on the date of grant using a Black-Scholes option pricing model. The Company’s expected volatilities are based on historical volatility of the Company’s stock and other factors. To the extent that volatility of the Company’s stock price increases in the future, the estimates of the fair value of options granted in the future could increase, thereby increasing share-based compensation expense in future periods. The Company’s estimate of the forfeiture rate was based primarily upon historical experience of employee turnover. To the extent that the Company revises this estimate in the future, the share-based compensation could be materially impacted in the quarter of revision, as well as in the following quarters. Additionally, the expected dividend yield is considered for each grant on the date of grant. The Company’s expected term of options granted was derived from the average midpoint between vesting and the contractual term. In the future, as information regarding post vesting termination becomes more accessible, the Company may change the method of deriving the expected term. This change could impact the fair value of options granted

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

in the future. The Company expects to refine the method of deriving the expected term no later than January 1, 2008. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant. The following table represents the Black-Scholes estimated ranges under the Company plans for the periods presented:


	June 30, 2005
Expected volatility	27.5% to 37.61%
Weighted average volatility	32.26%
Expected dividend yield		1.67%
Risk-free interest rate		3.75% to 5.00%
Expected life in years		5.0 to 7.0 years

A summary of the status of the Company’s outstanding stock options as of June 30, 2006 and changes during the six months ended June 30, 2006, is presented below:

				Weighted-		Weighted-
				Average		Average		Aggregate
				Exercise		Contractual		Intrinsic
Stock Options	Shares			Price		Life		Value

Outstanding options at January 1, 2006		2,549,833		$	16.93
Granted		-			-
Exercised		(433,833	)	$	14.60
Forfeited		(12,099	)	$	16.55
Outstanding options at June 30, 2006		2,103,901		$	17.41		5.98	$	19,856,712
Exercisable options at June 30, 2006		1,244,931		$	15.80		4.50	$	13,759,292

As of June 30, 2006, there was $6.1 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the stock option plans. That cost is expected to be recognized over a weighted-average contractual period of 1.6 years. The total fair value of options vested as of June 30, 2006 was $8.3 million. Compensation expense recognized related to stock options totaled $0.9 million ($0.7 million, net of tax) and $1.8 million ($1.5 million, net of tax) for the three- and six-month periods ended June 30, 2006.

The intrinsic value of options exercised during the three and six months ended June 30, 2006 was approximately $1.6 million and $4.4 million, respectively, and the Company realized an additional tax benefit of approximately $1.5 million for the amount of intrinsic value in excess of compensation cost recognized during the year, which has been reported as an increase in financing cash flows in the Company’s 2006 Condensed Consolidated Statement of Cash Flows.

Restricted Stock. The Company’s Amended 2003 Plan also provides for grants of restricted stock. The restrictions associated with a grant of restricted stock under the Amended 2003 Plan generally expire equally over a period of four years. Restrictions on certain grants expire over two years and contain various provisions that allow for accelerated expiration over a shorter term if certain criteria are met. Certain grants made to the non-employee directors and a senior executive of the Company provide for restriction expiration over a period less than one year from the date of grant. Restrictions on restricted stock expire at the end of the applicable period, which is also the requisite service period. The fair value of restricted stock is the excess of the average market price of common stock on the date of grant over the exercise price, which is zero.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

A summary of the status of nonvested restricted stock awards as of June 30, 2006 and changes during the six months ended June 30, 2006, is presented below:

	Number of			Weighted-Average
	Restricted Shares			Grant-Date
Nonvested Restricted Shares	Outstanding			Fair-Value

Nonvested restricted shares at January 1, 2006		209,903		$	24.15
Granted		37,636		$	25.02
Vested		(125,428	)	$	24.19
Forfeited		-
Nonvested restricted shares at June 30, 2006		122,111		$	24.39

As of June 30, 2006, there was $2.3 million of total unrecognized compensation cost related to nonexpired, share-based compensation arrangements granted under the restricted stock plans. That cost is expected to be recognized over a weighted-average contractual period of 1.4 years. The total fair value of restricted shares that vested during the six-month period ended June 30, 2006 was $3.0 million. Compensation expense recognized related to restricted stock totaled $0.6 million ($0.4 million, net of tax) and $1.5 million ($1.0 million, net of tax) during the three- and six-month periods ended June 30, 2006.

The intrinsic value of restricted stock vested during the three- and six-month periods ended June 30, 2006 was approximately $1.5 million and $3.0 million, respectively, and the Company realized an additional tax benefit of approximately $1.1 million for the amount of intrinsic value in excess of compensation cost recognized during the year.

Financing cash flows were affected by the realized tax benefits specific to stock option exercises, calculated on an option by option basis, of $1.5 million for the six-month period ended June 30, 2006. Financing cash flows were affected by the realized tax benefits specific to the restricted stock, calculated on a grant by grant basis, of $1.1 million for the six-month period ended June 30, 2006. Such realized tax benefits were reported as an increase in financing cash flows in the Condensed Consolidated Statement of Cash Flows.

5. Accumulated Other Comprehensive Loss

The Company reports comprehensive income and its components in accordance with FASB Statement No. 130, Reporting Comprehensive Income. The main components of comprehensive income that relate to the Company’s net earnings are minimum pension liability adjustments and unrealized gain (loss) on hedging activities, all of which are presented in the Condensed Consolidated Statement of Stockholders’ Equity and Comprehensive Income.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The table below provides an overview of Comprehensive income for the periods indicated:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Other Comprehensive Income (Loss)	2006			2005			2006			2005
	(In thousands)
Net Earnings	$	13,734		$	15,675		$	111,682		$	107,871
Unrealized gain (loss) on interest rate hedges, net of tax of $0,
$(214), $0 and $(820) respectively		-			(339	)		-			(1,299	)
Reclassification of unrealized gain (loss) on interest rate hedges
into earnings, net of tax of $(24), $208, $(58) and $1,642, respectively		(36	)		310			(73	)		2,443
Change in fair value of commodity hedges, net of tax of $4,921
$0, $1,592 and $0, respectively		8,277			-			2,677			-
Reclassification of unrealized gain (loss) on commodity hedges
into earnings, net of tax of $(255), $0, $(255) and $0		(428	)		-			(428	)		-
Total other comprehensive income (loss)		7,813			(29	)		2,176			1,144
Total comprehensive income	$	21,547		$	15,646		$	113,858		$	109,015

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

	June 30,			December 31,
	2006			2005
	(In thousands)
Interest rate hedges, net	$	(3,300	)	$	(3,227	)
Commodity hedges, net		2,249			-
Minimum pension liability, net		(53,045	)		(53,045	)
Accumulated other comprehensive loss, net of tax	$	(54,096	)	$	(56,272	)

6. Inventories

In the Transportation and Storage segment, inventories consist of gas held for operations and materials and supplies, both of which are carried at the lower of weighted average cost or market, while gas received from or owed back to customers is valued at market. The gas held for operations that the Company does not expect to consume in its operations in the next 12 months is reflected in other non-current assets. Gas held for operations at June 30, 2006 was $107.5 million, or 15,772,000 million British thermal units (MMBtu), of which $17.9 million was classified as non-current. Gas held for operations at December 31, 2005 was $102.5 million, or 14,145,000 MMBtu, of which $25.1 million was classified as non-current.

In the Gathering and Processing segment, inventories consist of natural gas liquids and are stated at the lower of cost or market value. Cost is determined using the first-in, first-out method. Southern Union Gas Services’ natural gas liquids inventories were $2.4 million at June 30, 2006, or 1,985,000 gallons, all of which was classified as current.

In the Distribution segment, inventories consist of natural gas in underground storage and materials and supplies, both of which are carried at weighted average cost. Natural gas in underground storage at June 30, 2006 and December 31, 2005 was $101.6 million and $187.6 million, respectively, and consisted of 14,100,000 MMBtu and 25,324,000 MMBtu, respectively.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

7. 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, warrants, restricted stock and convertible equity units. A reconciliation of the shares used in the basic and diluted earnings per share calculations is shown in the following table.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005

Weighted average shares outstanding - Basic		111,944,643		110,787,049		111,807,253		107,546,799
Add assumed vesting of restricted stock		73,310		104,995		109,391		104,964
Add assumed conversion of equity units		2,407,644		2,064,855		2,337,051		2,050,258
Add assumed exercise of stock options		555,776		1,368,804		739,483		1,437,638
Weighted average shares outstanding - Dilutive		114,981,373		114,325,703		114,993,178		111,139,659

There were nil and 15,000 anti-dilutive options outstanding for the three and six months ended June 30, 2006, respectively, and 11,538 and 5,801 outstanding for the three and six months ended June 30, 2005, respectively. At June 30, 2006, 818,415 shares of common stock were held by various rabbi trusts for certain of the Company’s benefit plans. From time to time, the Company’s benefit plans may purchase shares of Southern Union common stock subject to regular restrictions.

8. Other Income (Expense), Net

Other, net in the Condensed Consolidated Statement of Operations for the three-month period ended June 30, 2006, totaling $1.6 million, primarily includes distributions received on previously written off Enron affiliate receivables of $0.9 million and net gains on sales of certain assets of $0.6 million.

Other, net in the Condensed Consolidated Statement of Operations for the six-month period ended June 30, 2006, totaling $38.6 million, primarily includes $37.2 million of pre-acquisition mark-to-market gains on put options associated with the acquisition of Sid Richardson Energy Services. See Note 12 - Derivative Instruments and Hedging Activities - Natural Gas Put Options, for more information related to the gain on put options mentioned above.

Other, net for the six-month period ended June 30, 2005, totaling $(5.4) million, primarily includes charges of $4.5 million to: (i) reserve for an impairment in the Company’s investment in Advent, a technology company, and (ii) record a liability for the guarantee by a subsidiary of the Company of a line of credit between Advent and a bank.

9. Regulatory Assets and Liabilities

The Company records regulatory assets and liabilities with respect to its Distribution segment operations and for certain of its operations reported as discontinued operations in accordance with FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation (Statement No. 71). The Company’s wholly-owned subsidiary Panhandle Eastern Pipe Line Company, LP (PEPL and, collectively with its subsidiaries, Panhandle) does not apply this statement in accounting for its operations. Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978. In 1999, Panhandle discontinued the application of Statement No. 71 primarily due to the level of discounting from tariff rates and its ability to recover specific costs. The accounting required by Statement No. 71 differs from the accounting required for businesses that do not apply its provisions. Transactions that are generally recorded differently as a result of applying regulatory accounting requirements include, among others, recording of regulatory assets and the capitalization of an equity component on regulated capital projects. Statement No. 71 does not apply to the Company’s Gathering and Processing segment.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

	June 30,		December 31,
Regulatory Assets	2006		2005
		(In thousands)

Pension and Postretirement Benefits	$	28,630	$	32,627
Deferred Income Tax		-		28,076
Environmental		13,143		23,656
Missouri Safety Program		10,353		11,956
Other		5,383		16,648
	$	57,509	$	112,963

The Company’s regulatory assets at June 30, 2006 relating to Distribution segment operations that are being recovered through current rates totaled $32.1 million. The remaining recovery period associated with these assets ranged from two months to 99 months. As of December 31, 2005, the Company’s regulatory assets relating to the Distribution segment operations and discontinued operations included $59.1 million that is being recovered through current rates. The remaining recovery period as of December 31, 2005 associated with these assets ranged from one month to 187 months.

The following table provides a summary of regulatory liabilities at the dates indicated:

	June 30,		December 31,
Regulatory Liabilities	2006		2005
	(In thousands)

Environmental	$	7,024	$	8,817
Other		118		1,253
	$	7,142	$	10,070

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

10. Unconsolidated Investments

A summary of the Company’s unconsolidated investments at the dates indicated is as follows:

	June 30,		December 31,
Unconsolidated Investments	2006		2005
		(In thousands)
Equity investments:
CCE Holdings	$	696,398	$	668,985
Other		12,780		13,074
Investments at cost		775		775

	$	709,953	$	682,834

Equity Investments. Unconsolidated investments include the Company’s 50%, 29% and 49.9% investments in CCE Holdings, LLC (CCE Holdings), Lee 8 and PEI Power II, respectively, which are accounted for using the equity method. The Company’s share of net income or loss from these equity investments is recorded in Earnings from unconsolidated investments in the Condensed Consolidated Statement of Operations. The Company’s equity investment balances include purchase price differences of $18.4 million as of June 30, 2006 and December 31, 2005. The purchase price differences represent the excess of the purchase price over the Company’s share of the investee’s book value at the time of acquisition and, accordingly, have been designated as goodwill that will be accounted for pursuant to Accounting Principles Board (APB) Opinion 18, The Equity Method of Accounting for Investments in Common Stock, and FASB Statement No. 142, Goodwill and Other Intangible Assets.

The following table presents summarized financial information for the periods presented applicable to the entities in which the Company has an equity investment:

	For the Three Months Ended June 30,
	2006				2005
	CCE		Other Equity		CCE		Other Equity
	Holdings		Investments		Holdings		Investments
	(In thousands)
Income Statement Data:
Revenues	$	56,007	$	723	$	58,910	$	1,130
Operating income		23,972		85		34,836		197
Equity earnings		21,774		-		19,682		-
Net income		31,544		49		41,112		152


		For the Six Months Ended June 30,
		2006				2005
		CCE		Other Equity		CCE		Other Equity
		Holdings		Investments		Holdings		Investments
		(In thousands)
Income Statement Data:
Revenues	$	110,433	$	1,741	$	111,657	$	2,309
Operating income		47,994		331		59,943		395
Equity earnings		35,632		-		36,037		-
Net income		55,307		262		71,775		304

Contingent Matters Potentially Impacting the Company’s Investment in CCE Holdings. The following update information should be read in conjunction with the related information included in Note 9 - Unconsolidated Investments in the Company’s Form 8-K dated July 17, 2006 filed with the SEC.

Transwestern Rate Case. The level of Transwestern’s transportation rates, fuel retention percentages and operational gas sales will be affected by Transwestern’s rate case, which is required to be filed by October 1, 2006 to go into effect November 1, 2006; the Company expects that effectiveness of the rates will be suspended by FERC until April 2007. The Company expects the rate case will result in lower average fuel retention factors and will reduce operational gas sales volumes. The outcome of this and other rate matters will be decided through litigation or settlement of the rate case and is impossible to determine at this time.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Phoenix Expansion Project. The Phoenix Expansion project, as currently proposed, includes the construction and operation of approximately 260 miles of 36-inch or larger diameter pipeline extending from Transwestern's existing mainline in Yavapai County, Arizona to delivery points in the Phoenix, Arizona area (Phoenix Lateral). In addition, the project includes certain looping on Transwestern's existing San Juan Lateral with approximately 25 miles of 36-inch diameter pipeline (San Juan Expansion 2008). Total project costs are estimated to be approximately $700 million with a projected in-service date of mid-2008. Extensions have been received to August 10, 2006 of Transwestern’s project termination rights under the contracts executed with the anchor shippers to allow further opportunity to resolve project scope and structuring issues. If these issues are not resolved, the project will likely be cancelled and the project development costs incurred to date will likely be written off. Development costs incurred through June 30, 2006 are approximately $20 million.

11. Stockholders’ Equity

On March 17, 2006, the Company’s Board of Directors authorized the payment of the Company’s first regular quarterly cash dividend of $0.10 per share on the Company’s common stock. Dividend payments totaling $11.2 million were paid on April 14, 2006, to holders of record as of the close of business on March 31, 2006.

On June 16, 2006, the Company’s Board of Directors authorized the payment of the Company’s second regular quarterly cash dividend of $0.10 per share on the Company’s common stock. Dividend payments totaling $11.2 million were paid on July 14, 2006, to holders of record as of the close of business on June 30, 2006. For the three- and six-month periods ended June 30, 2006 the Company reduced Retained earnings (deficit) and Premium on capital stock in the Condensed Consolidated Statement of Stockholders’ Equity and Comprehensive Income by $9.3 million and $19.9 million, respectively (to the extent that earnings were available) and $1.8 million and $2.4 million, respectively.

12. Derivative Instruments and Hedging Activities

Interest Rate Swaps. Interest rate swaps are used to reduce interest rate risks and to manage interest expense. By entering into these agreements, the Company converts floating-rate debt into fixed-rate debt, or alternatively converts fixed-rate debt into floating-rate debt. Interest differentials paid or received under the swap agreements are reflected as an adjustment to interest expense. These interest rate swaps are financial derivative instruments that qualify for hedge treatment.

On April 29, 2005, the Company refinanced the existing bank loans of Trunkline LNG Holdings, LLC (LNG Holdings) in the amount of $255.6 million, due in January 2007 (see Note 13 - Debt Obligations). Interest rate swaps previously designated as cash flow hedges of the LNG Holdings’ bank loans were terminated upon refinancing of the loans. As a result, a gain of $3.5 million ($2.1 million net of tax) was recorded in Accumulated other comprehensive loss during the second quarter of 2005 and is being amortized to interest expense through the maturity date of the original bank loans in 2007. From January 1, 2005 through the termination date of the swap agreements on April 29, 2005, there was no swap ineffectiveness.

In March and April 2003, the Company entered into a series of treasury rate locks with an aggregate notional amount of $250 million to manage its exposure against changes in future interest payments attributable to changes in the benchmark interest rate prior to the anticipated issuance of fixed-rate debt. These treasury rate locks expired on June 30, 2003, resulting in a $6.9 million after-tax loss that was recorded in Accumulated other comprehensive loss and is being amortized into interest expense over the lives of the associated debt instruments. As of June 30, 2006, approximately $967,000 of the net after-tax losses in Accumulated other comprehensive loss will be amortized into interest expense during the next twelve months.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

In March 2004, Panhandle entered into interest rate swaps to hedge the risk associated with the fair value of its $200 million principal amount of 2.75% Senior Notes. These swaps are designated as fair value hedges and qualify for the short cut method under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended (Statement No. 133). Under the swap agreements, Panhandle will receive fixed interest payments at a rate of 2.75 percent and will make floating interest payments based on the six-month LIBOR. No ineffectiveness is assumed in the hedging relationship between the debt instrument and the interest rate swap. As of June 30, 2006 and December 31, 2005, the fair values of the swaps are included in the Condensed Consolidated Balance Sheet as liabilities and matching adjustments to the underlying debt of $4.4 million and $5.7 million, respectively.

The notional amounts of the interest rate swaps are not exchanged and do not represent exposure to credit loss. In the event of default by a counterparty, the risk in these transactions is the cost of replacing the agreements at current market rates.

Trading and Non-Hedging Activities. During 2005 and 2004, the Company entered into natural gas commodity swaps and collars to mitigate price volatility of natural gas passed through to utility customers. 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/liability in the Condensed Consolidated Balance Sheet. As of June 30, 2006 and December 31, 2005, the fair values of the contracts, which expire at various times through March 2007, are included in the Condensed Consolidated Balance Sheet as assets and liabilities, respectively, with matching adjustments to deferred cost of gas of $(6.6) million and $17.5 million, respectively.

Commodity Hedging Activities. Due to the contract and asset structure of Southern Union Gas Services, the Company maintains the option to hedge its equity commodity exposure utilizing the most advantageous commodity at the time the hedges are entered into. The Company believes that given the relative price of natural gas and natural gas liquids in December 2005 natural gas was the appropriate commodity to hedge due to the relative prices. In connection with its agreement to acquire the Sid Richardson Energy Services business, now doing business as Southern Union Gas Services, the Company purchased put options for $49.7 million based on the price of natural gas in December 2005. These commodity options were tied to the WAHA price of natural gas for the monthly delivery periods March 2006 through December 2006 (2006 Put Options) and January 2007 through December 2007 (2007 Put Options) (collectively, Put Options). The 2006 Put Options relate to 45,000 MMBtu/day at the price of $11.00 per MMBtu and the 2007 Put Options relate to 25,000 MMBtu/day at the price of $10.00 per MMBtu. The goal of the purchase of the Put Options was to reduce the downside commodity price risk of the Southern Union Gas Services business. Prior to the closing of the Company’s acquisition of Sid Richardson Energy Services on March 1, 2006, the Put Options were required to be accounted for using mark-to-market accounting with the change in value between measurement dates recorded as a gain or loss in current period earnings. The impact on the Company’s results of operations for the January and February 2006 pre-acquisition period was a gain of $37.2 million. The gain was recorded in Other, net in the Condensed Consolidated Statement of Operations. There was also a $1.8 million gain in December 2005. In July 2006, the Company completed hedging substantially all of its equity commodity exposure utilizing energy commodity put options for the remaining four month period (September through December) of 2006 and calendar year 2007.

As a result of the required mark-to-market gains in the Put Options since their purchase, the Company’s basis in them was increased to $88.7 million as of March 1, 2006. With the closing of the acquisition on March 1, 2006, the commodity-based Put Options were designated as “cash flow hedges” and are subsequently being accounted for in accordance with Statement No. 133. Accordingly, changes in fair market value of the Put Options that are considered effective will be initially recorded in Accumulated other comprehensive loss, and reclassified to earnings in the period the hedged sales occur. If it is determined that the hedge is not effectively operating as anticipated, income is adjusted to the extent of such ineffectiveness. Since the hedge involved a significant investment, the portion of the hedge associated primarily with the change in the time value of the investment is excluded from the assessment of hedge effectiveness and recorded to income.

In March 2006 and during the second quarter of 2006, the Company recorded ineffectiveness under the hedges of a $1.1 million gain and a $1.3 million loss, respectively, primarily associated with the time value portion of the hedge. The ineffectiveness described herein was reported as Operating revenues in the Condensed Consolidated Statement of Operations.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

At March 31, 2006 and June 30, 2006, the Company marked the Put Options to fair market value and recorded the effective portion of the change between measurement dates in Accumulated other comprehensive loss for $8.9 million ($5.6 million, net of tax), and Accumulated other comprehensive loss for $13.2 million ($8.3 million, net of tax), respectively. At June 30, 2006, the Company reported the $52.1 million current portion of the fair market value of the Put Options in the Condensed Consolidated Balance Sheet in Prepayments and other assets and the remaining $12.1 million in Deferred charges, respectively. During the first and second quarters of 2006, the Company received $6.7 million and $21.8 million, respectively in cash from the settlement of the Put Options. Approximately $4.6 million of gain included in the Accumulated other comprehensive loss balance of $3.6 million ($2.2 million, net of tax) as of June 30, 2006 is expected to be reclassified into earnings during the next twelve months and approximately $1.0 million of loss thereafter through the end of the hedge.

13. Debt Obligations

The following table sets forth the debt obligations of Southern Union and Panhandle under their respective notes, debentures and bonds at the dates indicated:

	June 30,		December 31,
	2006		2005
	(In thousands)
Long-Term Debt and Capital Lease Obligations:

Southern Union Company
7.60% Senior Notes due 2024	$	359,765	$	359,765
8.25% Senior Notes due 2029		300,000		300,000
2.75% Senior Notes due 2006		125,000		125,000
6.50% to 10.25% First Mortgage Bonds, due 2019 to 2027		34,500		111,419
4.375% Senior Notes, due 2008		100,000		100,000
Capital lease and other, due 2006 to 2007		31		71
		919,296		996,255

Panhandle
2.75% Senior Notes due 2007		200,000		200,000
4.80% Senior Notes due 2008		300,000		300,000
6.05% Senior Notes due 2013		250,000		250,000
6.50% Senior Notes due 2009		60,623		60,623
8.25% Senior Notes due 2010		40,500		40,500
7.00% Senior Notes due 2029		66,305		66,305
Term Loan due 2007		255,626		255,626
Net premiums on long-term debt		10,924		12,205
		1,183,978		1,185,259

Notes Payable Associated with Southern Union Company
Bridge Loan		1,600,000		-
Credit Facilities		251,000		420,000
		1,851,000		420,000

Total consolidated debt and capital lease obligations		3,954,274		2,601,514
Less fair value swaps of Panhandle		4,416		5,725
Less current portion of long-term debt and capital lease (1)		576,164		126,648
Less short-term debt obligation		1,851,000		420,000
Total consolidated long-term debt and capital lease obligations	$	1,522,694	$	2,049,141

(1) Includes $4.4 million of fair value of swaps related to debt classified as current.

Southern Union has $2.1 billion of long-term debt recorded at June 30, 2006, of which $125.0 million and $451.2 million is due in August 2006 and March 2007, respectively, and is thus classified as current. Debt of $1.65 billion, including net premiums of $10.9 million, is at fixed rates ranging from 2.75 percent to 9.44 percent. Southern Union also has floating rate debt, excluding notes payable, totaling $455.6 million, bearing an average interest rate of 5.8 percent as of June 30, 2006. The variable rate bank loans are unsecured.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

As of June 30, 2006, the Company has scheduled long-term debt payments as follows:

	Remainder										2011 and
	2006		2007		2008		2009		2010		thereafter
	(In thousands)

Southern Union Company	$	125,000	$	-	$	100,000	$	-	$	-	$	694,265
Panhandle		-		455,626		300,000		60,623		40,500		316,305

Total	$	125,000	$	455,626	$	400,000	$	60,623	$	40,500	$	1,010,570

Each note, debenture or bond is an obligation of Southern Union or a unit of Panhandle, as noted above. Panhandle’s debt is non-recourse to Southern Union. All debts that are listed as debt of Southern Union are direct obligations of Southern Union, and no debt is cross-collateralized.

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. Certain covenants exist in certain of the Company’s debt agreements that require the Company to maintain a certain level of net worth, to meet certain debt to total capitalization ratios, and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by the Company to satisfy any such covenant would be considered an event of default under the associated debt, which could become immediately due and payable if the Company did not cure such default within any permitted cure period or if the Company did not obtain amendments, consents or waivers from its lenders with respect to such covenants.

Notes Payable

Bridge Loan. On March 1, 2006, Southern Union acquired Sid Richardson Energy Services for $1.6 billion in cash. The acquisition was funded under a bridge loan facility in the amount of $1.6 billion (Bridge Loan) that was entered into on March 1, 2006 between the Company and its wholly-owned subsidiary, Enhanced Service Systems, Inc., as borrowers, and a group of banks as lenders. The Bridge Loan is available for a maximum period of 364 days at interest rates tied to LIBOR or the prime rate plus a spread based upon the credit ratings of the Company’s senior unsecured debt. Interest expense totaling $22.5 and $29.7 million was incurred for the three months ended June 30, 2006 and for the period March 1 through June 30, 2006, respectively, at an average interest rate of 5.72 percent. Debt issuance costs totaling $9.2 million associated with the financing of the acquisition were incurred, of which $7.8 million is related to the Bridge Loan and $1.4 million is related to the placement of permanent financing. The Company amortized $3.9 million and $5.2 million of the debt issuance cost to interest expense during the quarter ended June 30, 2006 and for the period March 1 through June 30, 2006, respectively. Under the terms of the Bridge Loan, the Company is required to apply 100 percent of the net cash proceeds from asset dispositions and from the issuance of equity and/or debt, other than from the refinancing of debt, to repayment of the Bridge Loan. The Bridge Loan is collateralized by the Company’s pledge of its interests in PEPL and a pledge of the equity interests in the acquired Southern Union Gas Services entities.

Credit Facilities. Balances of $251 million and $420 million were outstanding under the Company’s credit facilities at average effective interest rates of 5.95 percent and 4.73 percent at June 30, 2006 and December 31, 2005, respectively. As of August 4, 2006, there was a balance of $300.0 million outstanding under the Company’s credit facilities, with an effective interest rate of 5.90 percent.

Retirement of Debt Obligations

The Company plans to refinance or retire its current debt obligations through asset dispositions and by accessing capital markets. An inability to repay these obligations would cause a material adverse change to the Company’s financial condition. See Note 19 - Discontinued Operations for additional information related to planned asset dispositions.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

14. Employee Benefits

Components of Net Periodic Benefit Cost. Net periodic benefit cost from continuing operations for the three months ended June 30, 2006 and 2005 includes the components in the table below. Net periodic pension cost from discontinued operations totaled $1.4 million and $3.9 million for the three-month periods ended June 30, 2006 and 2005, respectively. Net periodic postretirement benefit cost from discontinued operations totaled $0.8 million and $0.8 million for the three-month periods ended June 30, 2006 and 2005, respectively.

	Pension Benefits						Postretirement Benefits
	Three Months Ended						Three Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
	(In thousands)

Service cost	$	694		$	638		$	586		$	727
Interest cost		2,246			2,339			975			1,227
Expected return on plan		(2,204	)		(2,182	)		(456	)		(344	)
Prior service cost amortization		147			196			(751	)		(138	)
Recognized actuarial gain		1,812			1,341			(23	)		(41	)
Curtailment recognition		-			2,726			-			-
Settlement recognition		-			(161	)		-			-
Sub-total		2,695			4,897			331			1,431
Regulatory adjustment		(1,983	)		-			-			-
Net periodic benefit cost	$	712		$	4,897		$	331		$	1,431

Net periodic benefit cost from continuing operations for the six months ended June 30, 2006 and 2005 includes the components in the table below. Net periodic pension cost from discontinued operations totaled $6.3 million and $7.7 million for the six-month periods ended June 30, 2006 and 2005, respectively, and includes recognition of a $3.0 million curtailment charge during the first quarter of 2006. Net periodic postretirement benefit cost from discontinued operations totaled $1.2 million and $1.4 million for the six-month periods ended June 30, 2006 and 2005, respectively.

	Pension Benefits						Postretirement Benefits
	Six Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
	(In thousands)

Service cost	$	1,387		$	1,275		$	1,171		$	1,454
Interest cost		4,491			4,678			1,950			2,454
Expected return on plan		(4,408	)		(4,364	)		(913	)		(688	)
Prior service cost amortization		295			391			(1,502	)		(276	)
Recognized actuarial gain		3,624			2,682			(45	)		(82	)
Curtailment recognition		-			3,107			-			-
Settlement recognition		-			(322	)		-			-
Sub-total		5,389			7,447			661			2,862
Regulatory adjustment		(3,966	)		-			-			-
Net periodic benefit cost	$	1,423		$	7,447		$	661		$	2,862

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

In the Distribution segment, the Company recovers certain qualified pension plan and postretirement benefit plan costs through rates to utility customers. Certain utility commissions require that the recovery of pension costs be based on ERISA or other utility commission guidelines. The difference between these amounts and pension expense calculated pursuant to FASB Statement No. 87, Employers' Accounting for Pensions, is deferred as a regulatory asset or liability and amortized to expense over periods promulgated by the applicable utility commission in which this difference will be recovered in rates.

15. Taxes on Income

The Company's estimated annual consolidated federal and state effective income tax rate (EITR) from continuing operations for the three-month periods ended June 30, 2006 and 2005 was 32 percent and 20 percent, respectively. The Company's EITR from continuing operations for the six-month periods ended June 30, 2006 and 2005 was 33 percent and 26 percent, respectively.

The increase in the EITR for both the three-month and six-month periods was primarily due to the release of an $11.9 million valuation allowance in 2005 that was originally established for a deferred tax asset in 2004 related to the difference between the book and tax basis of the Company’s investment in CCE Holdings. The Company determined that this valuation allowance was no longer necessary because the book income from CCE Holdings was substantially greater than the taxable income for 2005 and is expected to continue to be higher for the foreseeable future.

The Company's EITR from discontinued operations for the three-month periods ended June 30, 2006 and 2005 was 42 percent and 22 percent, respectively. The difference was primarily due to the disproportionate allocation of state tax and other permanent differences between continuing and discontinued operations. The Company's EITR from discontinued operations for the six-month periods ended June 30, 2006 and 2005 was 34 percent for both periods.

16. Regulation and Rates

Panhandle. Trunkline LNG’s Phase I expansion project was placed into service on April 5, 2006 with a total project cost of $140 million, plus capitalized interest. The expanded vaporization capacity portion of the expansion was placed into service on September 18, 2005. Phase II went into service on July 8, 2006. The estimated final cost of Phase II is $79 million, plus capitalized interest. The expansions increased sustainable send-out capacity from .63 Bcf per day to 1.8 Bcf per day, and storage increased from 6.3 Bcf to 9.0 Bcf. BG LNG Services has contracted for all the additional capacity at the facility from these expansions with a rate moratorium through 2015. Approximately $83.7 million and $102 million of costs are included in the line item Construction work-in-progress for the expansion projects through June 30, 2006 and December 31, 2005, respectively.

On March 31, 2006, the Company filed for regulatory approval with FERC for an additional enhancement of Trunkline LNG’s terminal. This infrastructure enhancement project, which is expected to cost approximately $250 million, plus capitalized interest, will increase send out flexibility at the terminal and lower fuel costs. Construction will begin after regulatory approvals are received. The project is planned to be in operation in 2008. In addition, Trunkline LNG and BG LNG Services agreed to extend the existing terminal and pipeline services agreements through 2028, representing a five-year extension.

The Company has filed for regulatory authorization to modernize and replace various compression facilities on PEPL. Such replacements will be made at 12 different compressor stations and will be installed through the end of 2008. The estimated cost of these replacements is approximately $290 million, which includes the compression component of a PEPL east end enhancement project which is already under construction. The Company has also filed for approval to replace approximately 32 miles of existing pipeline on the east end of the PEPL system at an estimated cost of approximately $60 million, which would further improve system integrity. Construction will begin after regulatory approvals are received; the project is planned to be completed in late 2007.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Trunkline has announced a Field Zone Expansion project, which includes adding capacity to its pipeline system in Texas and Louisiana to increase deliveries to the Henry Hub. The Field Zone Expansion project includes the previously announced North Texas Expansion as well as additional capacity to the Henry Hub. Trunkline will increase the capacity along existing right of way from Kountze, Texas, to Longville, Louisiana, by approximately 510 million cubic feet per day with the construction of approximately 45 miles of 36-inch diameter pipeline. The project includes horsepower additions and modifications at existing compressor stations. Trunkline also will create additional capacity to the Henry Hub with the construction of a 15-mile, 36-inch diameter pipeline loop from Kaplan, Louisiana, directly into the Hub. Trunkline expects to file the project with the FERC near the end of the third quarter of 2006 with an anticipated in-service date of the fourth quarter of 2007. Project costs are currently estimated at approximately $150 to $160 million plus capitalized interest.

FERC is responsible under the Natural Gas Act for assuring that rates charged by interstate pipelines are "just and reasonable." To enforce that requirement, FERC applies a ratemaking methodology that determines an allowed rate of return on common equity for the companies it regulates. The Natural Gas Supply Association (NGSA), a natural gas producer trade association, has published a study that alleges, based on NGSA's analysis, that certain natural gas pipelines, including PEPL and Southwest Gas Storage, are over-recovering their allowed rates of return. A group purporting to have an interest in the rates charged by PEPL and Southwest Gas Storage approached Panhandle to propose a voluntary rate reduction. No agreement was reached and discussions have been discontinued. No proceeding has been initiated at FERC relating to rates charged by PEPL or Southwest Gas Storage. The ultimate resolution of this matter has many variables and potential outcomes and is impossible to predict its timing or materiality at this time. Any potential rate reductions resulting from such a proceeding would be expected to be mitigated by the impact of significant ongoing capital spending at PEPL for pipeline integrity, safety, air emissions and other environmental, compression modernization and other requirements.

Missouri Gas Energy. On September 21, 2004, the Missouri Public Service Commission (MPSC) issued a rate order authorizing Missouri Gas Energy to increase base revenues by $22.4 million, effective October 2, 2004. Missouri Gas Energy filed various appeals related to this matter seeking increased base revenues in addition to those contained in the MPSC’s order on grounds that the capital structure and 10.5 percent return on equity used by the MPSC in determining such increase did not provide an adequate rate of return. On April 11, 2006, the Missouri Supreme Court denied a hearing on this matter, effectively concluding the Company’s appeal. Missouri Gas Energy accounts for its revenues based upon the September 21, 2004 MPSC rate order.

On May 1, 2006, Missouri Gas Energy announced the filing of a proposal with the MPSC to increase annual revenues by approximately $41.7 million, or 6.8 percent. The MPSC may take up to 11 months to issue a ruling on the proposal.

Through filings made on various dates, the staff of the MPSC has recommended that the MPSC disallow a total of approximately $42.7 million in gas costs incurred during the period July 1, 1997 through June 30, 2004. Missouri Gas Energy disputes the basis of $34.3 million of the total proposed disallowance, which appears to be the same as was rejected by the MPSC through an order dated March 12, 2002, applicable to the period July 1, 1996 through June 30, 1997. No date for a hearing in this matter has been set. Missouri Gas Energy also disputes the basis of $3 million of the total proposed disallowance, applicable to the period July 1, 2000 through June 30, 2001, which was the subject of a hearing concluded in November 2003, and is presently awaiting decision by the MPSC. In addition, Missouri Gas Energy disputes the basis of $3.4 million of the total proposed disallowance, applicable to the period July 1, 2001 through June 30, 2003; a hearing is set for August 2006. Finally, Missouri Gas Energy disputes the basis of $2.04 million of the proposed disallowance for the period of July 1, 2003 through June 30, 2004 (which appears to be the same as or very similar to the basis of the disallowance set for the hearing in August 2006); this matter has not yet been set for hearing. 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.

New England Gas Company. The New England Gas Company filed on June 15, 2006, a notice of intent to file rate schedules for its Massachussetts operations with the MDTE. Such notice is a requirement in advance of filing for an increase in base gas rates.

PG Energy. PG Energy filed on April 13, 2006, an application with the Pennsylvania Public Utility Commission (PPUC) seeking an increase in its base gas rates, designed to produce $29.8 million in additional annual revenue, to be effective June 12, 2006. On May 19, 2006, the PPUC suspended this rate increase for seven months (until January 12, 2007) in order to investigate the reasonableness of the proposed rates. It is not presently possible to determine what action the PPUC will ultimately take in this matter.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

17. Commitments and Contingencies

Environmental

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

The Company follows the provisions of American Institute of Certified Public Accountants Statement of Position 96-1, Environmental Remediation Liabilities, for recognition, measurement, display and disclosure of environmental remediation liabilities.

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 financial position, results of operations or cash flows. The table below reflects the amount of accrued liabilities recorded in the Condensed Consolidated Balance Sheet at June 30, 2006 and December 31, 2005 to cover probable environmental response actions:

	June 30,		December 31,
	2006		2005
	(In thousands)

Current	$	4,289	$	6,541
Noncurrent		19,362		27,274
Total Environmental Liabilities	$	23,651	$	33,815

Transportation and Storage Segment Environmental Matters.

Gas Transmission Systems. Panhandle is responsible for environmental remediation at certain sites on its gas transmission systems. The contamination resulted from the past use of lubricants containing polychlorinated biphenyls (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 is implementing a program to remediate such contamination. Remediation and decontamination has been completed at 33 of 35 compressor station sites where auxiliary buildings that house the air compressor equipment have been impacted by the past use of lubricants containing PCBs. At some locations, PCBs have been identified in paint that was applied many years ago. A program has been implemented to remove and dispose of PCB impacted paint during painting activities. 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, such as the Pierce Waste Oil sites described below, Panhandle may share liability associated with contamination with other potentially responsible parties. 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. Panhandle believes the outcome of these matters will not have a material adverse effect on its financial position, results of operations or cash flows.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

PEPL and Trunkline, together with other non-affiliated parties, have been identified as potentially liable for conditions at three former waste oil disposal sites in Illinois - the Pierce Oil Springfield site, the Dunavan Waste Oil site and the McCook site (collectively, the Pierce Waste Oil sites). PEPL and Trunkline received notices of potential liability from the United States Environmental Protection Agency (U.S. EPA) for the Dunavan site. The notice demanded reimbursement to the U.S. EPA for all its costs incurred to date in the amount of approximately $1.8 million and encouraged each potentially responsible party (PRP) to voluntarily negotiate an administrative settlement agreement with the U.S. EPA within certain limited time frames providing for the PRPs to conduct or finance the response activities required at the site. The demand was declined in a joint letter dated December 15, 2005 by the major PRPs including PEPL and Trunkline. Although no formal notice has been received for the Pierce Oil Springfield site, special notice letters are anticipated and the process of listing the site on the National Priority List has begun. No formal notice has been received for the McCook site. Panhandle believes the outcome of these matters will not have a material adverse effect on its financial position, results of operations or cash flows.

On June 16, 2005, PEPL experienced a release of liquid hydrocarbons near Pleasant Hill, Illinois. The release occurred in the form of a mist at a valve that was in use to reduce the pressure in the pipeline as part of maintenance activities. The hydrocarbon mist affected several acres of adjacent agricultural land and a nearby marina. Approximately 27 gallons of hydrocarbons reached the Mississippi River. PEPL contacted appropriate federal and state regulatory agencies and the U.S. EPA took the lead role in overseeing the subsequent cleanup activities, which have been completed. PEPL has resolved claims of affected boat owners and the marina operator. PEPL received a violation notice from the Illinois Environmental Protection Agency (Illinois EPA) alleging that PEPL is in apparent violation of several sections of the Illinois Environmental Protection Act by allowing the release. The violation notice did not propose a penalty. Responses to the violation notice were submitted and the responses were discussed with the agency. On December 14, 2005 the Illinois EPA notified PEPL that the matter might be considered for referral to the Office of the Attorney General, the State’s Attorney or the U.S. EPA for formal enforcement action and the imposition of penalties. Panhandle believes the outcome of this matter will not have a material adverse effect on its financial position, results of operations or cash flows.

Air Quality Control. U.S. EPA issued a final rule on regional ozone control (NOx SIP Call) in April 2004 that impacts Panhandle in two Midwestern states, Indiana and Illinois. Based on a U.S. EPA guidance document negotiated with gas industry representatives in 2002, Panhandle will be required in states that follow the EPA guidance to reduce nitrogen oxide (NOx) emissions by 82 percent on the identified large internal combustion engines and will be able to trade off engines within Panhandle in an effort to create a cost effective NOx reduction solution. The final implementation date is May 2007. The rule will affect 20 large internal combustion engines on Panhandle’s system in Illinois and Indiana with an approximate cost of $20.0 million for capital improvements through 2007, based on current projections. Approximately $19.0 million of the $20.0 million of capital expenditures has been incurred as of June 30, 2006. Indiana has promulgated state regulations to address the requirements of the NOx SIP Call rule that essentially follow the EPA guidance.

The Illinois EPA has distributed several draft versions of a rule to control NOx emissions from reciprocating engines and turbines statewide. The latest draft requires controls on engines regulated under the U.S. EPA NOx SIP Call by May 1, 2007 and the remaining engines by January 1, 2011. The state is requiring the controls to comply with U.S. EPA rules regarding the NOx SIP Call, ozone non-attainment and fine particulate standards. The Illinois EPA has held multiple meetings with industry representatives to discuss the draft rule and is expected to propose the rule in late-2006. The rule is currently being reviewed for potential impact to Panhandle. As drafted, the rule applies to all PEPL and Trunkline stations in Illinois and significant expenditures in addition to the $20.0 million associated with NOx reductions described above would be required for emission control.

In 2002, the Texas Commission on Environmental Quality enacted the Houston/Galveston SIP regulations requiring reductions in NOx emissions in an eight-county area surrounding Houston. Trunkline’s Cypress compressor station is affected and requires the installation of emission controls. New regulations also require certain grandfathered facilities in Texas to enter into the new source permit program which may require the installation of emission controls at one additional facility owned by Panhandle. Management estimates capital improvements of $17.0 million will be needed at the two affected Texas locations. Approximately $7.0 million of the $17.0 million of capital expenditures have been incurred as of June 30, 2006.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The U.S. EPA promulgated various Maximum Achievable Control Technology rules in February 2004. The rules require that PEPL and Trunkline control Hazardous Air Pollutants (HAPs) emitted from certain internal combustion engines at major HAPs sources. Most PEPL and Trunkline compressor stations are major HAPs sources. The HAPs pollutant of concern for PEPL and Trunkline is formaldehyde. As promulgated, the rule seeks to reduce formaldehyde emissions by 76 percent from these engines. Catalytic controls will be required to reduce emissions under these rules with a final implementation date of June 2007. PEPL and Trunkline have approximately 20 internal combustion engines subject to the rules. Management expects that compliance with these regulations will necessitate an estimated expenditure of $1.7 million for capital improvements, based on current projections.

Spill Control. Environmental regulations were recently modified for U.S. EPA’s Spill Prevention, Control and Countermeasures (SPCC) program. Panhandle is currently reviewing the impact to its operations and expects to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures. Costs associated with tank integrity testing and resulting corrective actions cannot be reasonably estimated at this time, but Panhandle believes such costs will not have a material adverse effect on its financial position, results of operations or cash flows.

Gathering and Processing Segment Environmental Matters.

Gathering and Processing Systems. Southern Union Gas Services is responsible for environmental remediation at certain sites on its gathering and processing systems. The contamination results primarily from releases of hydrocarbons. Southern Union Gas Services 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. On June 16, 2006 Southern Union Gas Services submitted information to the Texas Commission on Environmental Quality (TCEQ) in connection with a request to permit the Grey Ranch, Texas facility to continue its current level of emissions. The State of Texas requires all previously grandfathered emission sources to obtain permits or to shutdown by March 1, 2008. Southern Union Gas Services is currently in negotiations with the TCEQ to finalize permit requirements for the Grey Ranch facility which is owned 50 percent by an unaffiliated party. Although Southern Union Gas Services is requesting that no control measures be required at this time, there can be no assurance such control measures will not be required. Costs associated with emission controls, if any, cannot be reasonably estimated at this time as a final permit has not been issued, but the Company believes such costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Spill Control. Environmental regulations were recently modified for U.S. EPA’s Spill Prevention, Control and Countermeasures program. The Company is currently reviewing the impact of these modifications to its operations and expects to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures. Costs associated with tank integrity testing and resulting corrective actions cannot be reasonably estimated 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.

Distribution Segment Environmental Matters.

The Company is responsible for environmental remediation at various contaminated sites that are primarily associated with former Manufactured Gas Plants (MGPs) and sites associated with the operation and disposal activities from MGPs which produced a fuel known as “town gas”. Some constituents of the manufactured gas process may be regulated substances under various federal and state environmental laws. To the extent these constituents 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

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 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, and some contamination may be unrelated to 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 potentially responsible parties, 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.

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 made accruals in accordance with FASB Statement No. 5, Accounting for Contingencies, in order to provide for such matters. Management believes the final disposition of these proceedings will not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.

Bay Street, Tiverton, Rhode Island Site. On March 17, 2003, the Rhode Island Department of Environmental Management sent the Company’s New England Gas Company division a letter of responsibility pertaining to soils allegedly impacted by historic MGP residuals in a residential neighborhood in Tiverton, Rhode Island. Without admitting responsibility or accepting liability, New England Gas Company began assessment work in June 2003 and has continued to perform assessment field work since that time. During 2005, four lawsuits were filed against New England Gas Company in Rhode Island regarding the Tiverton neighborhood. The plaintiffs seek to recover damages for the diminution in value of their property, lost use and enjoyment of their property and emotional distress in an unspecified amount. The Company removed the lawsuits to federal court and filed motions to dismiss, which are currently pending. The Company will continue to vigorously defend itself against all four lawsuits. Parts of the Tiverton neighborhood appear to have been built on fill placed there at various times and include one or more historic waste disposal sites. Research is therefore underway by the Company to identify other PRPs associated with the fill materials and the waste disposal. Under the terms of the Purchase and Sale Agreement between the Company and National Grid USA, the potential obligation for the matters described above will remain with the Company. Based upon its current understanding of the facts, the Company does not believe the outcome of these matters will have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Mercury Release. The Company has completed an investigation of an incident involving the release of mercury stored in a New England Gas Company facility in Pawtucket, Rhode Island. On October 19, 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. State and federal authorities are also investigating the incident. In addition, the Company is discussing with the authorities New England Gas Company’s compliance with relevant environmental requirements, including hazardous waste management provisions, spill and release notification procedures, and communication requirements. The Company received and complied with a subpoena requesting documents relating to this matter. The U.S. Attorney’s office in Rhode Island has advised the Company that this incident may give rise to unspecified criminal charges against the Company. The Company would vigorously defend any such action. The Company is currently engaged in discussions with authorities to resolve the matter on a civil basis. On January 20, 2006 a complaint was filed against the Company in the Superior Court of Providence, Rhode Island regarding the mercury release from the Pawtucket facility, asserting claims for personal injury and property damage as a result of the release. The suit was removed to Rhode Island federal court on January 27, 2006. A motion to remand the case to state court filed by plaintiffs was argued on June 9, 2006. No ruling on the motion has been made. In addition, an attorney for unspecified residents of the neighboring apartment complex who are not associated with the filed litigation has made a demand upon New England Gas Company. Under the terms of

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

the Purchase and Sale Agreement between the Company and National Grid USA, the potential obligation for the matters described above will remain with the Company. The Company believes the outcome of this matter will not have a material adverse effect on its financial position, results of operations or cash flows.

Hope Land. Hope Land Mineral Corporation (Hope Land) contends that it owns the storage rights to property that contains a portion of the Company’s Howell storage field. During June 2003, the Michigan Court of Appeals reversed the trial court’s previous order, which had granted summary judgment in favor of the Company and dismissed the case. The Company filed an appeal of the Court of Appeals order with the Michigan Supreme Court, which was denied in December of 2003. In April 2005, Hope Land filed trespass and unjust enrichment complaints against the Company to prevent running of the statute of limitations. The Company then filed an action for condemnation to obtain the storage rights from Hope Land. Pursuant to a pre-filing settlement with Hope Land, the Company obtained legal title to the storage rights upon the filing of the condemnation action. As a result, the only issue to be determined at trial is the value of such rights and the amount of trespass damages to which Hope Land is entitled. The trial date has been extended to September 2006. The Company does not believe the outcome of this case will have a material adverse effect on the Company’s consolidated results of operations, cash flows or financial position.

Jack Grynberg. Jack Grynberg, an individual, has filed actions against a number of companies, including Panhandle, now transferred to the U.S. District Court for the District of Wyoming, for damages for mis-measurement of gas volumes and Btu content, resulting in lower royalties to mineral interest owners. On May 13, 2005, the Special Master in this case issued a recommended decision that would, if adopted by the District Judge, result in dismissal of Panhandle from the case. A similar action, known as the Will Price litigation, also has been filed against a number of companies, including Panhandle, in U.S. District Court for the District of Kansas. Panhandle is currently awaiting the decision of the trial judge on the defendants’ motion to dismiss the Will Price action. Panhandle believes that its measurement practices conformed to the terms of its FERC Gas Tariff, which was filed with and approved by FERC. As a result, the Company believes that it has meritorious defenses to the complaints (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 tariff) and is defending the suits vigorously. 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.

Southwest Gas Litigation. During 1999, several actions were commenced in federal courts by persons involved in competing efforts to acquire Southwest Gas Corporation (Southwest). All of these actions eventually were transferred to the U.S. District Court for the District of Arizona, consolidated and lodged with Judge Roslyn Silver. As a result of summary judgments granted, there were no claims allowed against the Company. The trial of the Company’s claims against the sole remaining defendant, former Arizona Corporation Commissioner James Irvin, was concluded on December 18, 2002, with a jury award to the Company of nearly $400,000 in actual damages and $60.0 million in punitive damages against former Commissioner Irvin. After the District Court denied former Commissioner Irvin’s motions to set aside the verdict and reduce the amount of punitive damages, former Commissioner Irvin appealed to the Ninth Circuit Court of Appeals (Ninth Circuit). On July 25, 2005, the Ninth Circuit denied former Commissioner Irvin’s motions to set aside the verdict and affirmed the judgment against him for compensatory damages. The Ninth Circuit also determined that punitive damages against former Commissioner Irvin were appropriate but found that the $60.0 million punitive damage award against him was excessive. Accordingly, the Ninth Circuit remanded that issue to the District Court for further action. The Company intends to continue to vigorously pursue its case against former Commissioner Irvin, including seeking to collect all damages ultimately determined to lie against him. There can be no assurance, however, as to the amount of such damages, or as to the amount, if any, that the Company ultimately will collect.

Mineral Management Service. In 1993, the U.S. Department of the Interior announced its intention to seek, through its Mineral Management Service (MMS), additional royalties from gas producers as a result of payments received by such producers in connection with past take-or-pay settlements and buyouts and buydowns of gas sales contracts with natural gas pipelines. PEPL and Trunkline, with respect to certain producer contract settlements, may be contractually required to reimburse or, in some instances, to indemnify producers against such royalty claims. The potential liability of the producers to the government and of the pipelines to the producers involves complex issues of law and fact, which are likely to take substantial time to resolve. If required to reimburse or indemnify the producers, PEPL and Trunkline may file with FERC to recover these costs from pipeline customers. Management believes these commitments and contingencies will not have a material adverse effect on the Company's consolidated financial condition, results of operations or cash flows.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Sunbury Pennsylvania Manufactured Gas Plant Site. By letter dated July 28, 2006, the Company received a demand by counsel for PPL, Inc. (PPL) and draft complaint seeking to recover costs incurred by PPL in investigating and remediating contamination of the Sunbury, Pennsylvania manufactured gas plant, which, according to the letter, have totaled in excess of $4.5 million to date. The Company has previously contributed to PPL’s remediation project by making cash payments and by removing and relocating gas utility lines located in the path of the remediation. Based upon its current understanding of the facts, the Company does not believe the outcome of this matter will have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Other Commitments and Contingencies.

Late in the third quarter of 2005, after coming through the Gulf of Mexico, Hurricanes Katrina and Rita came ashore along the Upper Gulf Coast. These hurricanes caused damage to property and equipment owned by Sea Robin, Trunkline, and Trunkline LNG. Based on the latest damage assessments, there are revenue, expense and capital impacts resulting from Hurricanes Katrina and Rita in 2005 and 2006, mostly impacting Sea Robin and Trunkline LNG. Estimated capital outlays of approximately $25 million are expected in 2006, of which $14.5 million was spent during the six month period ended June 30, 2006. The revenue losses now estimated at $3.0 million for 2006 relate primarily to reduced volumes on Sea Robin which are expected to continue having an impact into the latter portion of 2006.

The Company anticipates reimbursement from its property insurance carriers for a significant portion of damages from Hurricane Rita in excess of its $5.0 million deductible. Such reimbursement is currently estimated by the Company’s property insurance carrier to ultimately be limited to 70 percent of the portion of the claimed damages accepted by the insurance carrier, but the amount is subject to the level of total ultimate claims from all companies relative to the carrier’s $1.0 billion total limit on payout per claim.

In addition, after the 2005 hurricanes, the Mineral Management Service (MMS) mandated inspections by leaseholders and pipeline operators along the hurricane tracks. The Company has detected exposed pipe and other facilities on Trunkline and Sea Robin that must be re-covered to comply with the regulations. Associated with this, there was approximately $1.3 million of inspection related expense recorded in 2006. Additional capital expenditures are estimated at $5.0 million. The Company will seek recovery of these expense and capital amounts as part of the hurricane related claim.

18. Reportable Segments

The Company’s operating segments are aggregated into reportable business segments 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. The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas in the Midwest and Southwest and from the Gulf Coast to Florida, and also provides LNG terminalling and regasification services. Its operations are conducted through Panhandle and the Company’s equity investment in CCE Holdings (Panhandle Energy). The Company acquired Sid Richardson Energy Services on March 1, 2006, which represents the new Gathering and Processing reportable segment. The Gathering and Processing segment is primarily engaged in the gathering, transmission, treating, processing and redelivery of natural gas and natural gas liquids in Texas and New Mexico. Its operations are conducted through Southern Union Gas Services. (See Note 3 - Acquisition of Sid Richardson Energy Services.) The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts. The Company’s discontinued operations relate to its PG Energy natural gas distribution division and the Rhode Island operations of its New England Gas Company division. During the first quarter of 2006, the Company entered into definitive agreements to sell the Rhode Island operations of its New England Gas Company division and its PG Energy natural gas distribution division in Pennsylvania. The Company expects the sales to be completed by the end of the third quarter of 2006.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Revenue included in the Corporate and other category is primarily attributable to PEI Power Corporation, which generates and sells electricity. This business does not meet the quantitative thresholds for determining reportable segments. The Company also has corporate operations that do not generate any operating revenues.

The Company evaluates segment performance based on several factors, of which the primary financial measure is earnings before interest and taxes (EBIT). The Company defines EBIT as net earnings (loss) available for common stockholders, adjusted for: (i) items that do not impact earnings (loss) from continuing operations, such as extraordinary items, discontinued operations and the impact of accounting changes; (ii) income taxes; (iii) interest; and (iv) dividends on common and preferred stock. EBIT may not be comparable to measures used by other companies. Additionally, EBIT should be considered in conjunction with net earnings and other performance measures such as operating income or operating cash flow. 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 six months ended June 30, 2006 and 2005.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The following table sets forth certain selected financial information for the Company’s segments and a reconciliation of EBIT to net earnings for the three- and six-month periods ended June 30, 2006 and 2005. The Statement of Operations segment information presented herein for the 2005 periods has been reclassified to distinguish between results of operations from continuing and discontinued operations. Segment information presented herein for expenditures of long-lived assets in the 2005 periods and total asset amounts by segment at December 31, 2005 have not been adjusted for discontinued operations.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Segment Data	2006			2005			2006			2005
	(In thousands)						(In thousands)
Revenues from external customers:
Transportation and Storage	$	134,109		$	110,421		$	278,752		$	245,821
Gathering and Processing		329,094			-			432,325			-
Distribution		88,292			83,770			386,521			399,682
Total segment operating revenues		551,495			194,191			1,097,598			645,503
Corporate and other		860			1,045			1,923			1,833
	$	552,355		$	195,236		$	1,099,521		$	647,336

Depreciation and amortization:
Transportation and Storage	$	16,985		$	15,025		$	34,459		$	30,392
Gathering and Processing		13,400			-			18,952			-
Distribution		7,792			8,002			15,375			15,133
Total segment depreciation and amortization		38,177			23,027			68,786			45,525
Corporate and other		480			564			735			1,110
	$	38,657		$	23,591		$	69,521		$	46,635

Earnings (loss) from unconsolidated investments:
Transportation and Storage	$	15,823		$	20,268		$	27,387		$	35,653
Corporate and other		10			(36	)		12			(79	)
	$	15,833		$	20,232		$	27,399		$	35,574

Other income (expense), net:
Transportation and Storage	$	1,522		$	978		$	3,294		$	1,315
Gathering and Processing		775			-			1,184			-
Distribution		(927	)		(1,185	)		(2,135	)		(1,506	)
Total segment other income (expense), net		1,370			(207	)		2,343			(191	)
Corporate and other		180			(139	)		36,300			(5,245	)
	$	1,550		$	(346	)	$	38,643		$	(5,436	)

Segment performance:
Transportation and Storage EBIT	$	76,011		$	61,641		$	162,812		$	139,877
Gathering and Processing EBIT		17,917			-			25,030			-
Distribution EBIT		(6,376	)		(5,456	)		23,613			29,799
Total segment EBIT		87,552			56,185			211,455			169,676
Corporate and other		(377	)		(4,175	)		27,226			(5,559	)
Interest		62,978			29,894			105,199			63,483
Federal and state income taxes		7,876			4,474			43,742			26,598
Net earnings from continuing operations		16,321			17,642			89,740			74,036
Net earnings(loss) from discontinued operations		(2,587	)		(1,967	)		21,942			33,835
Net earnings		13,734			15,675			111,682			107,871
Preferred stock dividends		4,341			4,340			8,682			8,681
Net earnings available for common stockholders	$	9,393		$	11,335		$	103,000		$	99,190

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Segment Data	2006		2005		2006		2005
	(In thousands)				(In thousands)
Expenditures for long-lived assets:
Transportation and Storage	$	47,914	$	61,506	$	76,733	$	96,139
Gathering and Processing		14,299		-		16,795		-
Distribution		13,529		20,646		22,851		33,027
Total segment expenditures for
long-lived assets		75,742		82,152		116,379		129,166
Corporate and other		439		2,319		1,112		6,365
Expenditures for long-lived assets	$	76,181	$	84,471	$	117,491	$	135,531


		June 30,		December 31,
Total assets:		2006		2005
		(In thousands)
Transportation and Storage	$	3,199,697	$	3,155,549
Gathering and Processing		1,726,647		-
Distribution		1,011,600		2,490,164
Total segment assets		5,937,944		5,645,713
Corporate and other		183,882		191,106
Assets held for sale		1,251,051		-
Total consolidated assets	$	7,372,877	$	5,836,819

19. Discontinued Operations

On January 26, 2006, Southern Union entered into a definitive agreement to sell its PG Energy natural gas distribution division in Pennsylvania to UGI Corporation for $580 million, subject to working capital adjustments. Subsequently, on February 15, 2006, Southern Union entered into a definitive agreement to sell the Rhode Island operations of its New England Gas Company division to National Grid USA for $575 million, subject to working capital adjustments, less assumed debt of $77 million. The Rhode Island Division of Public Utilities and Carriers issued an order approving the transaction on July 25, 2006. On July 26, 2006, a Pennsylvania administrative law judge issued a decision recommending approval of the transaction to the PPUC, which is expected to consider the transaction in August. On August 4, 2006, the Company joined with UGI Corporation and certain interveners in a settlement proposal relating to the PPUC proceeding. While subject to conditions, if adopted, the proposal would result in additional funding by the Company of the PG Energy pension plans prior to closing and subsequent transfer of the pension assets and obligations to the buyer. This transaction would result in a settlement charge upon completion of the sale of approximately $5 million to $6 million. The Company expects to complete the sales transactions by the end of the third quarter of 2006.

The results of operations of the divisions have been segregated and reported as Discontinued operations in the Condensed Consolidated Statement of Operations. The prior interim periods have been reclassified to report the results of operations of these divisions as discontinued operations. At June 30, 2006, the related assets and liabilities of the PG Energy natural gas distribution division and the Rhode Island operations of the New England Gas Company division are reported, as applicable, in current Assets held for sale and Liabilities related to assets held for sale. The PG Energy natural gas distribution division and Rhode Island operations of the New England Gas Company division were historically reported within the Distribution segment.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

In December 2005, the Company recorded a goodwill impairment charge of $175 million after considering the purchase prices for the Company’s PG Energy division and the Rhode Island operations of its New England Gas Company division, as reflected in the definitive agreements entered into in the first quarter of 2006. Asset impairment charges of $12.3 million and $19.4 million were recorded in Earnings from discontinued operations before income taxes in the Condensed Consolidated Statement of Operations in the three- and six-month periods ended June 30, 2006, respectively. The losses arose primarily from the effect on plant, property and equipment balances of incurring additional capital expenditures during 2006. An additional factor related to higher plant, property and equipment balances is the cessation of recording depreciation expense subsequent to January 2006 after approval of the Company’s Board of Directors to dispose of the applicable assets. Additionally, approximately $1.9 million of estimated selling costs are included in the second quarter impairment charge. The total amount of the ultimate gain or loss on sale depends on various factors, including timing of the closing of the transactions, capital expenditures prior to closing and other matters. Given the nature of these items, the Company is currently unable to estimate with certainty additional losses that may be realized.

The following table summarizes the combined results of operations that have been segregated and reported as discontinued operations in the Condensed Consolidated Statement of Operations.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006		2005
	(In thousands)						(In thousands)

Operating revenue	$	122,279		$	109,927		$	471,044	$	425,384
Operating income		10,190			(1,049	)		54,971		52,678
Net earnings from discontinued operations (1)		(2,587	)		(1,967	)		21,942		33,835

Net earnings available from discontinued operations per share:
Basic	$	(0.02	)	$	(0.02	)	$	0.20	$	0.31
Diluted	$	(0.02	)	$	(0.02	)	$	0.19	$	0.30

(1)

Net earnings from discontinued operations do not include any allocation of corporate interest expense or other corporate costs.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The following table summarizes the major classes of assets and liabilities included in Assets held for sale and Liabilities related to assets held for sale, respectively, in the Company’s Condensed Consolidated Balance Sheet at June 30, 2006:


	At June 30, 2006
	(In thousands)
Assets held for sale:
Property, plant and equipment, net	$	629,314
Goodwill		376,321
Accounts receivable, net		92,321
Deferred charges		62,857
Inventories		81,635
Other assets		8,603
Total assets held for sale	$	1,251,051

Liabilities related to assets held for sale:
Long-term debt and capital lease obligation	$	76,935
Accounts payable and accrued liabilities		43,696
Deferred gas purchases		49,639
Deferred credits		11,704
Other liabilities		22,659
Total liabilities related to assets held for sale	$	204,633

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

INTRODUCTION

This Management’s Discussion and Analysis of Financial Condition and Results of Operations is provided as a supplement to the accompanying unaudited condensed consolidated financial statements and notes to help provide an understanding of Southern Union’s financial condition, changes in financial condition and results of operations. The following section includes an overview of the Company’s business as well as recent developments that 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, processing, transportation, storage and distribution of natural gas and natural gas liquids in a safe, efficient and dependable manner. The Company’s operating segments are aggregated into reportable business segments 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. The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas in the Midwest and Southwest and from the Gulf Coast to Florida, and also provides LNG terminalling and regasification services. Its operations are conducted through Panhandle Energy. The Gathering and Processing segment is primarily engaged in the gathering, transmission, treating, processing and redelivery of natural gas and natural gas liquids in Texas and New Mexico. Its operations are conducted through Southern Union Gas Services. The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts. The Company’s discontinued operations relate to its PG Energy natural gas distribution division in Pennsylvania and the Rhode Island operations of its New England Gas Company division. During the first quarter of 2006, the Company entered into definitive agreements to sell the Rhode Island operations of its New England Gas Company division and its PG Energy natural gas distribution division in Pennsylvania. The Company expects the sales to be completed by the end of the third quarter of 2006.

RESULTS OF OPERATIONS

Overview

The Company believes that its acquisition of Panhandle on June 11, 2003, its investment in CCE Holdings on November 17, 2004, and its acquisition of Sid Richardson Energy Services on March 1, 2006, represent significant steps undertaken by the Company in its transformation into a higher return business with significant growth opportunities. During the first quarter of 2006, the Company entered into definitive agreements to sell the Rhode Island operations of its New England Gas Company natural gas distribution division and the assets of its PG Energy natural gas distribution division. The Company expects the sales to be completed by the end of the third quarter of 2006. Proceeds from the sales will be used to retire a portion of the acquisition debt associated with the purchase of Sid Richardson Energy Services.

The Company evaluates segment performance based on several factors, of which the primary financial measure is EBIT. EBIT may not be comparable to measurements used by other companies and should be considered in conjunction with net income and other performance measures such as operating income or operating cash flow.

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006		2005
	(In thousands)						(In thousands)
EBIT:
Transportation and storage segment	$	76,011		$	61,641		$	162,812	$	139,877
Gathering and processing segment		17,917			-			25,030		-
Distribution segment		(6,376	)		(5,456	)		23,613		29,799
Corporate and other		(377	)		(4,175	)		27,226		(5,559	)
Total EBIT		87,175			52,010			238,681		164,117
Interest		62,978			29,894			105,199		63,483
Federal and state income taxes		7,876			4,474			43,742		26,598
Net earnings from continuing operations		16,321			17,642			89,740		74,036

Discontinued operations:
Earnings from discontinued operations before income taxes		(4,460	)		(2,510	)		33,549		51,018
Federal and state income taxes (benefit)		(1,873	)		(543	)		11,607		17,183
Net earnings from discontinued operations		(2,587	)		(1,967	)		21,942		33,835

Net earnings		13,734			15,675			111,682		107,871

Preferred stock dividends		4,341			4,340			8,682		8,681

Net earnings available for common stockholders	$	9,393		$	11,335		$	103,000	$	99,190

Business Segment Results

Transportation and Storage Segment. The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas from gas producing areas in Texas, Oklahoma, Colorado, and the Gulf of Mexico and the Gulf Coast to markets throughout the Midwest, Southwest to California and to Florida, and also provides LNG terminalling and regasification services. Its operations are conducted through Panhandle Energy and are regulated as to rates and other matters by FERC. The Transportation and Storage segment operations are somewhat sensitive to weather and are seasonal in nature with a significant percentage of annual operating revenues and net earnings occurring in the traditional winter heating season.

Historically, much of the Company’s business was conducted through long-term contracts with customers. Over the past several years, some of the Company’s customers have shifted to shorter term transportation services contracts. This shift, which can increase the volatility of revenues, is primarily due to changes in market conditions and competition with other pipelines, new supply sources, changing supply sources and volatility in natural gas prices. However, changes in commodity prices and volumes transported do not generally have a significant short-term impact on revenues because the majority of the Transportation and Storage segment revenues are related to firm capacity reservation charges.

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. Changes in rates and other tariff provisions resulting from these regulatory proceedings have the potential to negatively impact 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,
Transportation and Storage Segment	2006		2005		2006		2005
	(In thousands)

Operating revenues	$	134,109	$	110,421	$	278,752	$	245,821

Operating expenses		51,066		48,132		97,420		98,315
Depreciation and amortization		16,985		15,025		34,459		30,392
Taxes other than on income and revenues		7,392		6,869		14,742		14,205
Total operating income		58,666		40,395		132,131		102,909
Earnings from unconsolidated investments		15,823		20,268		27,387		35,653
Other income, net		1,522		978		3,294		1,315
EBIT	$	76,011	$	61,641	$	162,812	$	139,877

Operating information:
Panhandle Energy - volumes transported (in trillion
British thermal units (TBtu))		288		295		590		645
CCE Holdings (TBtu)		354		335		661		619

Three-month period ended June 30, 2006 versus the three-month period ended June 30, 2005. The $14.4 million EBIT improvement in the three-month period ended June 30, 2006 versus the same period in 2005 was primarily due to improved contributions from Panhandle totaling $18.8 million, partially offset by $4.4 million of lower equity earnings from the Company’s investment in CCE Holdings.

Panhandle’s $18.8 million EBIT improvement was primarily related to the following items:

·	Higher operating revenues of $23.7 million primarily due to:

o	A $13.5 million increase in LNG terminalling revenue due to expanded vaporization capacity, a base capacity increase on the BG LNG Services contract, and higher commodity revenues resulting from an increase in cargoes;

Increased transportation and storage revenues of $7.0 million due to higher average reservation revenues of $4.7 million which were primarily driven by higher average rates on contracts, higher parking revenues of $2.7 million, and higher storage revenue of $1.8 million due to increased contracted capacity. These increases were partially offset by lower revenues of $2.2 million, primarily on Sea Robin resulting from the impact of the hurricanes that occurred in the third quarter of 2005; and

o	Increased other revenue of $3.2 million primarily due to non-recurring operational sales of gas;

·	Higher operating expenses of $3.2 million primarily due to $1.3 million of cost for inspections of facilities due to Hurricane Rita, higher LNG electric power costs of $1.0 million due to more cargoes, and a Sea Robin fuel overrecovery in 2005 of $1.5 million;

·	A $2.0 million increase in depreciation and amortization expense primarily due to an increase in property, plant and equipment placed in service, including the LNG Phase I expansion; and

·	Higher taxes other than on income and revenues of $0.5 million primarily due to higher property taxes.

Equity earnings were lower by $4.4 million primarily due to the following items in equity contributions from CCE Holdings, which have been adjusted to reflect the Company’s related 50 percent equity share:

·	Higher operating expense of $2.8 million primarily due to the higher system balancing expenses of approximately $1.3 million and $0.6 million of higher electricity costs due to the addition of San Juan compression, and $0.7 million of Calpine bankruptcy-related bad debt expense;

Lower net revenues of $1.5 million primarily due to lower transportation revenues of $2.5 million associated with the replacement of expired contracts at discounted rates, partially offset by $0.9 million of increased operational gas sales revenue at Transwestern driven by a 14 percent increase in sales volumes and a 2 percent increase in average pricing;

·	Higher depreciation and amortization expense of $0.6 million primarily due to additions associated with the San Juan expansion project and implementation of financial systems to replace systems previously provided by Enron;

·	Lower capitalized equity cost during construction of $0.5 million primarily due to the completion of the San Juan expansion project in May 2005; and

·	Higher offsetting equity earnings of $1.0 million associated with CCE Holdings’ equity investment in Citrus Corp, primarily due to higher interruptible revenues and lower interest expense, partially offset by higher operating expenses and income taxes.

Six-month period ended June 30, 2006 versus the six-month period ended June 30, 2005. The $22.9 million EBIT improvement in the six-month period ended June 30, 2006 versus the same period in 2005 was primarily due to improved contributions from Panhandle totaling $31.2 million, partially offset by $8.3 million of lower equity earnings from the Company’s investment in CCE Holdings.

Panhandle’s $31.2 million EBIT improvement was primarily related to the following items:

·	Higher operating revenues of $32.9 million primarily due to:

o	A $19.8 million increase in LNG terminalling revenue due to expanded vaporization capacity, a base capacity increase on the BG LNG Services contract, and higher commodity revenues resulting from an increase in cargoes;

Increased transportation and storage revenues of $8.4 million due to higher average reservation revenues of $8.8 million, which were primarily driven by higher average rates on contracts, higher parking revenues of $1.5 million, and higher storage revenue of $1.4 million due to increased contracted capacity. These increases were partially offset by lower revenues of $3.3 million, primarily on Sea Robin resulting from the impact of the hurricanes that occurred in the third quarter of 2005; and

o	Increased other revenue of $4.8 million primarily due to non-recurring operational sales of gas in 2006;

·	A $4.0 million increase in depreciation and amortization expense primarily due to an increase in property, plant and equipment placed in service, including the LNG Phase I expansion;

A $0.9 million decrease in operation, maintenance and general expenses primarily due to a $3.7 million reduction in benefit costs including Medicare Part D subsidies and lower headcounts and lower insurance costs of $1.7 million, partially offset by $2.0 million of higher fuel and electric power tracker costs and $1.3 million for inspections of facilities due to Hurricane Rita; and

·	A $0.5 million increase in taxes other than on income and revenues primarily due to higher property taxes.

Equity earnings were lower by $8.3 million primarily due to the following items in equity contributions from CCE Holdings, which have been adjusted to reflect the Company’s related 50 percent equity share:

·	Higher operating expense of $3.6 million primarily due to the higher system balancing expenses of $1.9 million, $1.0 million of higher electricity costs due to the addition of San Juan compression, and $0.7 million of Calpine bankruptcy-related bad debt expense;

·	Lower capitalized equity cost during construction of $1.6 million primarily due to the completion of the San Juan expansion project in May 2005;

·	Higher depreciation and amortization expense of $1.3 million primarily due to additions associated with the San Juan expansion project and implementation of financial systems to replace services previously provided by Enron;

·	Lower equity earnings of $0.2 million associated with CCE Holdings’ equity investment in Citrus Corp., primarily due to higher depreciation and property taxes, partially offset by higher interruptible revenues, lower interest expense and income taxes;

·	A $0.5 million increase in taxes other than on income primarily due to higher property taxes; and

Lower net revenues of $0.6 million primarily due to lower transportation revenues of $4.7 million associated with the replacement of expired contracts at discounted rates, partially offset by $3.8 million of increased operational gas sales revenue at Transwestern driven by a 21 percent increase in sales volumes and a 14 percent increase in average pricing. The level of Transwestern’s transportation rates, fuel retention percentages and operational gas sales could be affected by Transwestern’s rate case to be filed in the fourth quarter of 2006. It is anticipated that lower average fuel retention factors than are currently in effect will be proposed and, if adopted, would reduce operational gas sales. The outcome of this and other rate matters will be decided through litigation or settlement of the rate case and is impossible to determine at this time.

Gathering and Processing Segment. The Gathering and Processing segment is primarily engaged in the gathering, transmission, treating, processing and redelivery of natural gas and natural gas liquids in Texas and New Mexico. Its operations are conducted through Southern Union Gas Services. The results of operations provided by Southern Union Gas Services have been included in the Condensed Consolidated Statement of Operations since its March 1, 2006 acquisition.

The following table illustrates the results of operations applicable to the Company’s Gathering and Processing segment:

	Three Months Ended		Six Months Ended
Gathering and Processing Segment	June 30, 2006		June 30, 2006
	(In thousands)		(In thousands)
			(1)

Operating revenues	$	329,094	$	432,325
Cost of gas and other energy		279,069		365,227
Operating expense		19,483		24,300
Depreciation and amortization		13,400		18,952
Total operating income		17,142		23,846
Other income, net		775		1,184
EBIT	$	17,917	$	25,030

(1) Represents results of operations for the period subsequent to the March 1, 2006 acquisition

Operating information:
Volumes:
Average natural gas processed volumes (MMbtu/day)		465,142		458,033
Average liquids processed volumes (gallons/day)		1,459,914		1,448,918
Prices:
Average Waha natural gas daily price ($/MMbtu)	$	5.71	$	5.74
Average natural gas liquids daily price ($/gallon)	$	0.96	$	0.92

Natural gas commodity prices were lower for the March 1 to June 30, 2006 period reported by Southern Union Gas Services relative to the average prices experienced for the year. A significant portion of Southern Union Gas Services’ margin is impacted by natural gas commodity prices. As natural gas commodity prices increase, the Company’s margin generally increases. Southern Union Gas Services’ results of operations for the periods reported subsequent to the March 1, 2006 acquisition were favorably impacted with larger processing spreads associated with higher natural gas liquids prices, partially offset by low natural gas prices.

The Company purchased commodity-based Put Options to reduce the downside commodity price risk of the Southern Union Gas Services business. Effective March 1, 2006, the Company designated its Put Options as “cash flow hedges” of future sales of natural gas by Southern Union Gas Services. The Company’s basis in the Put Options at March 1, 2006 was $88.7 million, comprised of a $49.7 million initial investment and $39 million in unrealized gains since inception. In March 2006 and during the second quarter of 2006, the Company recorded non-cash earnings (loss) from ineffectiveness under the hedges of $1.1 million and $(1.3) million, respectively in Operating revenues for Southern Union Gas Services, primarily associated with the change in time value of the hedges. Additionally, the Company received $6.7 million and $21.8 million in cash from the settlement of the March 2006 and second quarter of 2006 Put Options, respectively. This amount is not reflected in segment earnings for the period as it primarily relates to the realization of the mark-to-market gain reflected in Corporate and Other during the pre-acquisition period. For further information related to the Put Options, see PART I. ITEM 1. Financial Information (Unaudited), Note 12 - Derivative Instruments and Hedging Activities, in this Quarterly Report on Form 10-Q.

Distribution Segment. The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts. The utility divisions’ operations are regulated as to rates and other matters by the regulatory commissions of the states in which each operates. The utility divisions’ operations are generally sensitive to weather and are seasonal in nature, with a significant percentage of annual operating revenues and net earnings occurring in the traditional winter heating season in the first and fourth calendar quarters.

The following table illustrates the results of continuing operations applicable to the Company’s Distribution segment and excludes the results of discontinued operations for the periods presented:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Distribution Segment	2006			2005			2006			2005
	(In thousands)						(In thousands)

Net operating revenue (1)	$	33,020		$	33,853		$	94,736		$	102,408

Operating expense		28,058			28,363			48,298			50,971
Depreciation and amortization		7,792			8,003			15,375			15,134
Taxes other than on income and revenues		2,619			1,758			5,315			4,998
Total operating income		(5,449	)		(4,271	)		25,748			31,305
Other expense, net		(927	)		(1,185	)		(2,135	)		(1,506	)
EBIT	$	(6,376	)	$	(5,456	)	$	23,613		$	29,799

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

Three-month period ended June 30, 2006 versus the three-month period ended June 30, 2005. The $0.9 million EBIT reduction in the three-month period ended June 30, 2006 versus the same period in 2005 was primarily due to a decrease in net operating revenues of $0.8 million caused by an 8 percent reduction in consumption volumes resulting from the warmer than normal weather as evidenced by a 22 percent reduction in degree days.

Six-month period ended June 30, 2006 versus the six-month period ended June 30, 2005. The $6.2 million EBIT reduction in the six-month period ended June 30, 2006 versus the same period in 2005 was primarily due to the following items:

·	Net operating revenues were $7.7 million lower primarily due to a 12 percent reduction in consumption volumes resulting from the warmer than normal weather as evidenced by a 16 percent reduction in degree days;

·	Lower operating costs of $2.7 million primarily due to $3.3 million of lower pension costs principally related to the net deferral of pension costs permitted by a MPSC rate order authorization.

Corporate and Other

Except for revenue related to the Management Agreement associated with CCE Holdings, Corporate and Other consists of corporate operations that do not generate operating revenues and certain subsidiaries established to support and expand natural gas sales and other energy sales.

Three-month period ended June 30, 2006 versus the three-month period ended June 30, 2005. The $3.8 million EBIT improvement in the three-month period ended June 30, 2006 versus the same period in 2005 was primarily due to the following items:

·	Incurrence in 2005 of a $1.6 million curtailment loss related to the termination of a pension plan;

·	A $1.1 million curtailment loss on pension plan payments in 2005 to a former employee of the Company; and

·	Impact of a $0.5 million non-recurring true up adjustment in 2005 to reduce previously provided for employee benefit accruals.

Six-month period ended June 30, 2006 versus the six-month period ended June 30, 2005. The $32.8 million EBIT improvement in the six-month period ended June 30, 2006 versus the same period in 2005 was primarily due to the following items:

·	A mark-to-market gain of $37.2 million on put options for the pre-acquisition period associated with the March 1, 2006 acquisition of Sid Richardson Energy Services;

·	Negative impact of a first quarter 2006 $6.5 million write down in the carrying value of the Scranton corporate building;

Negative impact of $1.7 million of corporate stock-based compensation costs resulting from the implementation of Statement No. 123R in 2006;

·	Negative impact of a $1.0 million charge to record a reserve in March 2006 for final estimated costs resulting from a sales and use tax audit;

Charges of $4.5 million in the first quarter of 2005 to: (i) reserve for an other-than-temporary impairment in the Company’s investment in a technology company, and (ii) record a liability for the guarantee by a subsidiary of the Company of a line of credit between the technology company and a bank; and

·	Impact of $2.7 million of net non-recurring true up adjustments in 2005 to reduce previously provided for employee benefit accruals.

Interest Expense

Three-month period ended June 30, 2006 versus the three-month period ended June 30, 2005. Interest expense was $33.1 million higher in 2006 compared with 2005 primarily due to:

·	Interest of $22.5 million and debt issuance cost amortization of $3.9 million (which is being amortized over a six-month period) associated with the bridge loan facility entered into with the acquisition of Sid Richardson Energy Services;

·	Increased interest expense of $3.0 million associated with borrowings under the Company’s credit agreements primarily due to higher average outstanding balances and higher interest rates in 2006 versus 2005; and

·	Increased interest expense of $4.7 million related to Panhandle debt primarily due to higher average interest rates in 2006 versus 2005.

Six-month period ended June 30, 2006 versus the six-month period ended June 30, 2005. Interest expense was $41.7 million higher in 2006 compared with 2005 primarily due to:

·	Interest of $29.7 million and debt issuance cost amortization of $5.2 million (which is being amortized over a six-month period) associated with the bridge loan facility entered into with the acquisition of Sid Richardson Energy Services;

·	Increased interest expense of $5.5 million associated with borrowings under the Company’s credit agreements primarily due to higher average outstanding balances and higher interest rates in 2006 versus 2005;

·	Increased interest expense of $5.8 million related to Panhandle debt primarily due to higher average interest rates in 2006 versus 2005;

·	Decreased interest expense of $3.1 million related to the $407 million bridge loan paid off in 2005 that was used to finance a portion of the Company’s investment in CCE Holdings; and

·	Decreased interest expense of $1.0 million on the $311.1 million bank note (2002 Term Note) primarily due to the $76.1 million repayment of the note during 2005.

The Company expects to pay down a portion of the Bridge Loan with the proceeds from the sales of the Rhode Island operations of its New England Gas Company division and its PG Energy natural gas distribution division, which the Company expects to complete during the third quarter of 2006. The estimated reduction of the Bridge Loan’s outstanding balance by $1.1 billion resulting from the receipt of net sales proceeds is expected to reduce the Company’s monthly interest expense by approximately $5.1 million.

Federal and State Income Taxes from Continuing Operations

Three-month period ended June 30, 2006 versus the three-month period ended June 30, 2005. The Company's estimated annual consolidated federal and state effective income tax rate (EITR) from continuing operations for the three-month periods ended June 30, 2006 and 2005 was 32 percent and 20 percent, respectively.

Six-month period ended June 30, 2006 versus the six-month period ended June 30, 2005. The Company's estimated annual consolidated federal and state EITR from continuing operations for the six-month periods ended June 30, 2006 and 2005 was 33 percent and 26 percent, respectively.

Net Earnings from Discontinued Operations

Net earnings from discontinued operations for the three-month periods ended June 30, 2006 and 2005 are related to the assets of the PG Energy natural gas distribution division in Pennsylvania and the Rhode Island operations of the New England Gas Company division.

Earnings from discontinued operations before income taxes for the three-month period ended June 30, 2006 versus the same period in 2005 was $2.0 million lower primarily due to the following items:

·	Recognition of $12.3 million in asset impairment charges in June 2006 related to the disposition of the assets held for sale; and

·	Offsetting impact of $9.6 million of lower depreciation expense primarily due to the cessation of depreciation expense in connection with the assets held for sale classification.

Earnings from discontinued operations before income taxes for the six-month period ended June 30, 2006 versus the same period in 2005 was $17.5 million lower primarily due to the following items:

·	Recognition of $19.4 million in asset impairment charges related to the disposition of the assets held for sale;

·	Incurrence of a non-recurring $3.0 million pension curtailment loss associated with the impending sale of the PG Energy division;

·	Net operating revenues were $4.8 million lower primarily due to an 11 percent reduction in consumption volumes resulting from the warmer than normal weather as evidenced by a 15 percent reduction in degree days;

·	Higher bad debt expense of $2.6 million principally related to higher gas costs; and

·	Offsetting impact of $16.0 million of lower depreciation expense primarily due to the cessation of depreciation expense in connection with the assets held for sale classification.

The Company's EITR from discontinued operations for the six-month periods ended June 30, 2006 and 2005 was 34 percent for both periods.

See PART I, ITEM 1. Financial Statements (Unaudited), Note 19 - Discontinued Operations in this Quarterly Report on Form 10-Q.

Preferred Stock Dividends

There was no change in dividends on preferred securities for the six-month periods ended June 30, 2006 and 2005.

LIQUIDITY AND CAPITAL RESOURCES

Operating Activities

Cash generated from internal operations constitutes the Company’s primary source of liquidity. Additional sources of liquidity include use of available credit facilities, various equity offerings, project and bank financings, issuance of long-term debt and proceeds from asset dispositions.

The Company has increased the scale of its natural gas transportation, storage and distribution operations and the size of its customer base by pursuing and consummating the Panhandle and CCE Holdings acquisitions. Additionally, the Company has entered into the gathering and processing of natural gas and natural gas liquids business with its acquisition of Sid Richardson Energy Services. Acquisitions generally require a substantial increase in expenditures that may need to be financed through cash flow from operations, dispositions of assets, future debt or equity offerings, or any combination thereof. The availability and terms of any such financing sources 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. Acquisitions and financings also affect the Company's combined results due to factors such as the Company's ability to realize any anticipated benefits from the acquisitions, successful integration of new and different operations and businesses and effects of different regional economic and weather conditions. Future acquisitions or related acquisition financing or refinancing may involve the issuance of shares of the Company's common stock, which could have a dilutive effect on the then-current stockholders of the Company.

Six-month period ended June 30, 2006 versus the six-month period ended June 30, 2005. Cash flows provided by operating activities were $300.1 million for the six months ended June 30, 2006 compared with cash flows provided by operating activities of $307.5 million for the same period in 2005. Cash flows provided by operating activities before changes in operating assets and liabilities for 2006 were $165.1 million compared with $193.4 million for 2005. Changes in operating assets and liabilities provided cash of $135.0 million in 2006 and $114.1 million for the same period in 2005. After adjusting for the $76.6 million of cash provided by the operating activities of discontinued operations, cash provided by operating assets and liabilities in 2006 was $58.4 million, resulting in an increased usage of cash of $55.7 million in the six-month period ended June 30, 2006 versus the same period in 2005. The increased usage of cash is primarily related to the higher cost of natural gas purchases and related replenishment of natural gas inventory levels in the 2006 period versus 2005, partially offset by the $28.5 million cash settlement of Put Options.

Investing Activities

Summary

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

Cash flow changes associated with these objectives resulted primarily from the $1.54 billion (net of $53.7 million cash received) March 1, 2006 acquisition of Sid Richardson Energy Services and ongoing expansion of the Company’s existing asset base through that acquisition and additions to property, plant and equipment in 2006. The following table presents a summary of additions to property, plant and equipment in continuing operations by segment, including additions related to major projects for the periods presented.

	Six Months Ended June 30,
Property, Plant and Equipment Additions	2006		2005
	(In thousands)
Transportation and Storage Segment
LNG Terminal Expansions	$	26,370	$	43,529
Trunkline LNG Loop		3,101		13,322
East End Enhancement		9,498		-
Pipeline Integrity		8,841		5,698
System Reliability		7,660		5,172
Information Technology		3,252		198
Other		18,011		28,220
Total		76,733		96,139

Gathering and Processing Segment (1)		16,795		-

Distribution Segment
Missouri Safety Program		6,413		5,766
Other, primarily system replacement and expansion		16,438		27,261
Total		22,851		33,027

Corporate and other		1,112		6,365

Total (2)	$	117,491	$	135,531

(1) Reflects expenditures for March 2006 for the period subsequent to the March 1, 2006 acquisition of Sid Richardson
Energy Services versus the six-month period ended June 30, 2006.
(2) Includes net capital accruals totaling ($7.2) million and $4.8 million for the six-month periods ended June 30, 2006
and 2005, respectively.

Principal Capital Expenditure Projects

The following is a summary update of the Company’s principal capital expenditure projects, which should be read in conjunction with the related liquidity information in the Management’s Discussion and Analysis of Financial Condition and Results of Operations disclosure included in the Company’s Form 8-K dated July 17, 2006 filed with the SEC.

LNG Terminal Enhancement. On March 31, 2006, the Company filed for regulatory approval with FERC for an additional enhancement of Trunkline LNG’s terminal. This infrastructure enhancement project, which is expected to cost approximately $250 million, plus capitalized interest, will increase send out flexibility at the terminal and lower fuel costs. Construction will begin after regulatory approvals are received. The project is planned to be in operation in 2008. In addition, Trunkline LNG and BG LNG Services agreed to extend the existing terminal and pipeline services agreements through 2028, representing a five-year extension.

Compression Modernization. The Company has filed for regulatory authorization to modernize and replace various compression facilities on PEPL. Such replacements will be made at 12 different compressor stations and will be installed through the end of 2008. The estimated cost of these replacements is approximately $290 million, which includes the compression component of a PEPL east end enhancement project which is already under construction. The Company has also filed for approval to replace approximately 32 miles of existing pipeline on the east end of the PEPL system at an estimated cost of approximately $60 million, which would further improve system integrity. Construction will begin after regulatory approvals are received; the project is planned to be completed in late 2007.

Trunkline Field Zone Expansion Project. Trunkline has announced a Field Zone Expansion project, which includes adding capacity to its pipeline system in Texas and Louisiana to increase deliveries to the Henry Hub. The Field Zone Expansion project includes the previously announced North Texas Expansion as well as additional capacity to the Henry Hub. Trunkline will increase the capacity along existing right of way from Kountze, Texas, to Longville, Louisiana, by approximately 510 million cubic feet per day with the construction of approximately 45 miles of 36-inch diameter pipeline. The project includes horsepower additions and modifications at existing compressor stations. Trunkline also will create additional capacity to the Henry Hub with the construction of a 15-mile, 36-inch diameter pipeline loop from Kaplan, Louisiana, directly into the Hub. Trunkline expects to file the project with the FERC near the end of the third quarter of 2006 with an anticipated in-service date of the fourth quarter of 2007. Project costs are currently estimated at approximately $150 to $160 million plus capitalized interest.

Phoenix Expansion Project. The Phoenix Expansion project, as currently proposed, includes the construction and operation of approximately 260 miles of 36-inch or larger diameter pipeline extending from Transwestern's existing mainline in Yavapai County, Arizona to delivery points in the Phoenix, Arizona area (Phoenix Lateral). In addition, the project includes certain looping on Transwestern's existing San Juan Lateral with approximately 25 miles of 36-inch diameter pipeline (San Juan Expansion 2008). Total project costs are estimated to be approximately $700 million with a projected in-service date of mid-2008. Extensions have been received to August 10, 2006 of Transwestern’s project termination rights under the contracts executed with the anchor shippers to allow further opportunity to resolve project scope and structuring issues. If these issues are not resolved, the project will likely be cancelled and the project development costs incurred to date will likely be written off. Development costs incurred through June 30, 2006 are approximately $20 million.

Hurricane-Related Expenditures. Late in the third quarter of 2005, after coming through the Gulf of Mexico, Hurricanes Katrina and Rita came ashore along the Upper Gulf Coast. These hurricanes caused damage to property and equipment owned by Sea Robin, Trunkline, and Trunkline LNG. Based on the latest damage assessments, there are revenue, expense and capital impacts resulting from Hurricanes Katrina and Rita in 2005 and 2006, mostly impacting Sea Robin and Trunkline LNG. Estimated capital outlays of approximately $25 million are expected in 2006, of which $14.5 million was spent during the six month period ended June 30, 2006. The revenue losses now estimated at $3.0 million for 2006 relate primarily to reduced volumes on Sea Robin which are expected to continue having an impact into the latter portion of 2006.

Financing Activities

Summary

In conjunction with financing activities, the Company continues to pursue opportunities to enhance its credit profile by reducing its ratio of total debt to total capital. At June 30, 2006, the Company’s ratio of total debt to total capital was 67 percent, including the $1.6 billion Bridge Loan used to temporarily finance the acquisition of Sid Richardson Energy Services, which is expected to be repaid with the proceeds from asset sales and the issuance of long-term debt and/or equity securities. Excluding the $1.6 billion Bridge Loan, the ratio of total debt to total capital would be 55 percent. The issuance of common stock, equity units and preferred stock and use of proceeds therefrom to reduce debt or limit use of debt in conjunction with acquisitions is continued evidence of the Company’s commitment to strengthen its balance sheet and solidify its current investment grade status.

Cash flows provided by financing activities were $1.39 billion for the six-month period ended June 30, 2006 compared with cash flows used by financing activities of $199.2 million for the same period in 2005. Financing activity cash flow changes were primarily due to the $1.6 billion Bridge Loan used to fund the acquisition of Sid Richardson Energy Services.

Debt Refinancing, Repayment and Issuance Activity

On March 1, 2006, Southern Union acquired Sid Richardson Energy Services, Ltd. and related entities for $1.6 billion in cash. The acquisition was funded under a bridge loan facility in the amount of $1.6 billion that was entered into on March 1, 2006 between the Company and its wholly-owned subsidiary, Enhanced Service Systems, Inc., as borrowers, and a group of banks and lenders. The Bridge Loan is available for a maximum period of 364 days at interest rates tied to LIBOR or the prime rate plus a spread based upon the credit ratings of the Company’s senior unsecured debt. Interest expense totaling $22.5 million and $29.7 million was incurred for the three months ended June 30, 2006 and for the period March 1 through June 30, 2006, respectively, at an average interest rate of 5.72 percent. Debt issuance costs totaling $9.2 million associated with the financing of the acquisition were incurred, of which $7.8 million is related to the Bridge Loan and $1.4 million is related to the placement of permanent financing. The Company amortized $3.9 million and $5.2 million of the debt issuance cost to interest expense during the quarter ended June 30, 2006 and for the period March 1 through June 30, 2006, respectively. Under the terms of the Bridge Loan, the Company is required to apply 100 percent of the net cash proceeds from asset dispositions and from the issuance of equity and/or debt, other than from the refinancing of debt, to repayment of the Bridge Loan. The Company expects that the Bridge Loan will be repaid in its entirety before the end of 2006 and intends to structure any permanent financing to help maintain its investment grade rating. The Bridge Loan is collateralized by the Company’s pledge of its interests in PEPL and a pledge of the equity interests in the acquired Southern Union Gas Services entities.

Expected Refinancing. The Company’s $255.6 million Term Loan and $200 million 2.75% Senior Notes are due in March 2007. The Company expects to refinance these obligations.

Debt and Notes Payable Maturities and Other Debt Matters

The Company issued 2.5 million 5.75% Equity Units in connection with its June 2003 acquisition of Panhandle. Each 5.75% Equity Unit consists of a $50 principal amount of 2.75% Senior Notes due August 16, 2006 and a forward stock purchase contract that entitles the holder to purchase Southern Union common stock on August 16, 2006 at a price based on the preceding 20-trading day average closing price subject to a minimum conversion price per share of $13.82 (in which case 9.044 million shares would be issued) and a maximum conversion price of $16.86 (in which case 7.413 million shares would be issued). The Company is obligated to attempt to remarket the Senior Notes prior to August 11, 2006. Although the Company will not receive any proceeds from the remarketing of the 2.75% Senior Notes, it will receive on August 16, 2006, which is the settlement date of the purchase contracts comprising part of the 5.75% Equity Units, $125 million as the purchase price paid for the shares of common stock issued under the purchase contracts.

Balances of $251 million and $420 million were outstanding under the Company’s credit facilities at average effective interest rates of 5.95 percent and 4.73 percent at June 30, 2006 and December 31, 2005, respectively. As of August

4, 2006, there was a balance of $300.0 million outstanding under the Company’s credit facilities at an average effective interest rate of 5.90 percent.

The Company’s ability to arrange financing, including refinancing, and its cost of capital are dependent on various factors and conditions, including: general economic and capital market conditions; maintenance of acceptable credit ratings; credit availability from banks and other financial institutions; investor confidence in the Company, its competitors and peer companies in the energy industry; market expectations regarding the Company’s future earnings and probable cash flows; market perceptions of the Company’s ability to access capital markets on reasonable terms; and provisions of relevant tax and securities laws. The Company plans to refinance or retire its current debt and notes payable through asset dispositions and by accessing capital markets. An inability to repay these current obligations would cause a material adverse change to the Company’s financial condition. See PART I, ITEM 1. Financial Statements (Unaudited), Note 19 - Discontinued Operations for additional information related to planned asset dispositions.

OTHER MATTERS

Contingencies

See PART I, ITEM 1. Financial Statements (Unaudited), Note 17 - Commitments and Contingencies, in this Quarterly Report on Form 10-Q.

Regulatory

See PART I, ITEM 1. Financial Statements (Unaudited), Note 16 - Regulation and Rates, in this Quarterly Report on Form 10-Q.

Insurance

The Company maintains insurance coverage provided under its policies similar to other comparable companies in the same lines of business. The insurance policies are subject to terms, conditions, limitations and exclusions that do not fully compensate the Company for all losses. Insurance deductibles range from $100,000 to $5 million for the various policies utilized by the Company. Furthermore, as the Company renews its policies, it is possible that full insurance coverage may not be obtainable on commercially reasonable terms due to the recent more restrictive insurance markets.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See PART II. ITEM 1A. Risk Factors of this Quarterly Report on Form 10-Q for changes in market risks faced by the Company resulting from its March 1, 2006 acquisition of Sid Richardson Energy Services.

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, 2005 and the Company’s Form 8-K filed with the SEC on July 17, 2006, in addition to the 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.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures.

Southern Union has established disclosure controls and procedures to ensure that information required to be disclosed by the Company, including consolidated entities, in reports filed or submitted under the Securities Exchange Act of 1934, as amended (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 Chief Executive Officer (CEO) and Chief Financial Officer

(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, 2006.

Changes in Internal Controls.

Management’s assessment of internal control over financial reporting as of December 31, 2005, was included in Southern Union’s Annual Report on Form 10-K filed on March 16, 2006.

Except for the resulting impact of the March 1, 2006 acquisition of Sid Richardson Energy Services, which is now doing business as Southern Union Gas Services, there have been no changes in internal control over financial reporting that occurred during the first six months of 2006 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. The Company is currently evaluating the internal control over financial reporting associated with Southern Union Gas Services.

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 plans and assumptions. From time to time, Southern Union 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 products, expenses, interest rates, the outcome of contingencies, such as legal proceedings, and financial results.

Southern Union cannot guarantee that any forward-looking statement will be realized, although management believes that the Company has been prudent 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.

Southern Union 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 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 thinks 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 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 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 such as Hurricanes Katrina and Rita;

·	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;

·	risks relating to Southern Union’s recent acquisition of the Sid Richardson Energy Services business, including without limitation, the Company’s increased indebtedness resulting from that acquisition and the Company’s increased exposure to highly competitive commodity businesses;

·	risks relating to and that could interfere with the completion of Southern Union’s pending divestitures of PG Energy and the Rhode Island assets of New England Gas Company;

·	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, 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 17 - Commitments and Contingencies information included in this Quarterly Report on Form 10-Q and in the Financial Statements and Supplementary Data, Note 18 - Commitments and Contingencies information included in the Company’s Form 8-K filed with the SEC on July 17, 2006.

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 17 - Commitments and Contingencies in this Quarterly Report on Form 10-Q and in the Financial Statements and Supplementary Data, Note 18 - Commitments and Contingencies information included in the Company’s Form 8-K filed with the SEC on July 17, 2006.

ITEM 1A. RISK FACTORS.

Except for the risk factors described below associated with the Company’s Gathering and Processing segment resulting from the March 1, 2006 acquisition of Sid Richardson Energy Services, there have been no material changes to the risk factors previously disclosed in the Company’s Form 8-K filed with the SEC on July 17, 2006. The following is a summary of risk factors associated with the Gathering and Processing segment, which should be read in conjunction with the related disclosure included in the Company’s Form 8-K filed with the SEC on July 17, 2006.

RISKS THAT RELATE TO THE COMPANY’S NATURAL GAS GATHERING AND PROCESSING BUSINESS

The Company’s natural gas gathering and processing business is unregulated.

Unlike the Company’s returns on its regulated transportation and distribution businesses, the natural gas gathering and processing operations conducted at Southern Union Gas Services are not regulated and may potentially have a higher level of risk than the Company’s regulated operations. The Company expects to continue to invest in natural gas gathering and processing projects, which will likely involve non-regulated businesses or assets. These projects could involve risks associated with operational factors, such as competition and dependence on certain gas suppliers, industry vendors and customers, and financial, economic and political factors, such as rapid and significant changes in prices of hydrocarbons and energy, the cost and availability of capital and counterparty risk (including the inability of a counterparty, customer or supplier to fulfill a contractual obligation).

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

The natural gas gathering and processing industry is expected to remain highly competitive. Most customers of Southern Union Gas Services have access to more than one gathering and/or processing alternative. The Company’s ability to compete depends on a number of factors including: the infrastructure and contracting strategy of competitors in the Company’s gathering region; the efficiency, quality and reliability of the Company’s system; and the Company’s ability to maintain a reliable low cost pipeline operating system.

In addition to Southern Union Gas Services’ current competitive position in the natural gas gathering and processing industry, its business is subject to pricing risks associated with changes in the supply of and the demand for natural gas and liquid byproducts. If natural gas prices in the supply basins connected to the Company’s gathering system are comparatively higher than prices in other natural gas producing regions, the volume of gas that Southern Union Gas Services chooses to process may be reduced to maximize returns to the Company. Similarly, since the demand for natural gas is primarily a function of commodity prices (including prices for alternative energy sources), customer usage rates, weather, economic conditions and service costs, the volume processed by Southern Union Gas Services may be reduced based on these market conditions on a daily basis after analysis by the Company.

Although Southern Union Gas Services competes in an unregulated market, the business is subject to certain regulatory risks, most notably environmental regulations. Moreover, the Company cannot predict when additional legislation or regulation might affect the gathering and processing industry, nor the impact of these changes on the Company’s operations, financial position or cash flows. Although Southern Union Gas Services is currently positioned to compete effectively in the market, there are no assurances that this will be true in the future.

The success of the Company’s natural gas gathering and processing business depends, in part, on factors beyond the Company’s control.

Third parties produce all of the natural gas gathered and processed by Southern Union Gas Services. As a result, the volume of natural gas gathered and processed by Southern Union Gas Services depends on the ability of those third parties to produce natural gas and is therefore beyond the Company’s control. Furthermore, the following factors, most of which are also beyond the Company’s control, may unfavorably impact the Company’s ability to maintain or increase current processing volumes, to negotiate contracts or to market processing capacity:

·	future weather conditions, including those that favor alternative energy sources;

·	the market price of natural gas;

·	price competition;

·	drilling/work-over activity and supply availability;

·	the expiration of significant contracts;

·	service area competition.

The success of the Company’s natural gas gathering and processing business depends on natural gas producers’ ability to continue to discover and develop additional natural gas reserves in the Company’s gathering vicinity and the Company’s ability to access these additional reserves to offset the natural decline from existing wells connected to the Company’s gathering system.

The amount of revenue generated by Southern Union Gas Services depends substantially upon the volume of natural gas gathered and processed. As the reserves available from the supply basins connected to the Southern Union Gas Services system naturally decline, a decrease in development or production activity could cause a decrease in the volume of natural gas available for processing. Investments by third parties in the development of new natural gas reserves connected to the Company’s gathering system depend on many factors beyond the control of the Company.

The Company’s natural gas gathering and process business is dependent upon the purchases of hydrocarbons from producers and the sale or delivery of hydrocarbons to our customers.

Southern Union Gas Services receives hydrocarbons for purchase or transportation to market from over 200 producers and suppliers, none of which account for more than 15 percent of its total hydrocarbon throughput. The Company delivers for sale or transportation hydrocarbons to numerous downstream customers. In 2005, the Company made deliveries to over 70 sales customers.

Because the Company sells its hydrocarbon products on a daily price basis into three distinct market areas (West Coast, Mid-Continent and the Texas Intrastate Market), its customer mix changes seasonally. In the second quarter of 2006, the Company made sales to over 52 sales customers.

The Company’s natural gas gathering and processing business accepts some credit risk in dealing with customers.

Southern Union Gas Services derives its revenues from customers engaged primarily in the natural gas and utilities industries and extends payment credit to these customers. Southern Union Gas Services’ accounts receivable primarily consist of mid to large-size domestic customers with credit ratings of investment grade or better. Moreover, Southern Union Gas Services maintains trading relationships with counterparties that include reputable U.S. broker-dealers and other financial institutions and evaluates the ability of each counterparty to perform under the terms of the derivatives agreement. Although Southern Union Gas Services has minimized its exposure to this risk by continually monitoring and reviewing the credit exposure of each customer, it accepts some credit risk in dealing with customers.

The Company’s natural gas gathering and processing business revenues are generated under contracts that must be renegotiated periodically.

The revenues of Southern Union Gas Services are generated under gathering and processing contracts that expire periodically and must be replaced approximately every three years, on average. Although the Company actively pursues renegotiation, extension and/or replacement of all of its contracts, it cannot assure that Southern Union Gas Services will be able to extend or replace these contracts when they expire or that the terms of any renegotiated contracts will be as favorable as the existing contracts. If Southern Union Gas Services is unable to renew, extend or replace these contracts, or if these contracts are renewed on less favorable terms, the Company may suffer a material reduction in revenues and earnings.

Southern Union Gas Services does not fully hedge against price changes in commodities. This could result in decreased revenues and increased costs, thereby resulting in lower margins and adversely affecting results of operations.

Southern Union Gas Services is exposed to market risk and the impact of market fluctuations of prices for natural gas and natural gas liquids. Market risk refers to the risk of loss in cash flows and future earnings arising from adverse changes in commodity energy prices.

To minimize the risk from market price fluctuations of natural gas and natural gas liquids, Southern Union Gas Services uses commodity derivative instruments such as futures contracts and swaps to manage market and duration risk of existing or anticipated purchases and sales of natural gas and natural gas liquids. However, these financial derivative instrument contracts do not entirely eliminate pricing risks. Specifically, the Company is subject to other risks including un-hedged commodity price changes, market supply shortages and customer defaults. The impact of these variables could result in the Company paying higher energy or fuel costs relative to corresponding sales contracts.

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

Southern Union Gas Services’ fees are typically charged either (a) as a percentage of the volume of gas gathered and NGL’s processed through the Company’s facilities, or (b) for a specified fee for a range of services provided. The purchase price for the gas gathered and NGL’s processed by the Company is based on a market clearing index (typically a daily price) and is matched with the price at which the gas and NGL’s are ultimately sold to its market customers on the same basis. Therefore, Southern Union Gas Services’ operating margin is highly dependent on energy commodity prices.

To hedge against the commodity price risk of a downturn in energy prices, the Company purchased put options in December 2005 on the future prices for natural gas in 2006 and 2007. The Company believes that given the relative price of natural gas and NGL’s in December 2005 that natural gas was the appropriate commodity to hedge due to the contract and asset structure of Southern Union Gas Services.

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

Numerous operational risks are associated with the operation of a natural gas gathering and processing business. These include adverse weather conditions, accidents, the breakdown or failure of equipment or processes, the performance of processing facilities below expected levels of capacity or efficiency, the collision of equipment with facilities and catastrophic events such as explosions, fires, earthquakes, floods, landslides, tornadoes, lightning or other similar events beyond the Company’s control. It is also possible that infrastructure facilities could be direct targets or indirect casualties of an act of terror. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Insurance proceeds may not be adequate to cover all liabilities or expenses incurred or revenues lost.

The Company’s natural gas gathering and processing business is subject to environmental compliance regulations that could be difficult and costly.

The Company’s natural gas gathering and processing business is subject to multiple environmental laws and regulations affecting many aspects of present and future operations, including air emissions, water quality, wastewater discharges, solid wastes and hazardous material and substance management. These laws and regulations generally require the Company to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with these laws, regulations, permits and licenses may expose the Company to fines, penalties and/or interruptions in processing operations that could be material to the results of operations. If an accidental leak or spill of hazardous materials occurs from the Company’s facilities in the process of gathering or processing natural gas, the Company could be held liable for all resulting liabilities, including investigation and cleanup costs, which could materially affect the Company’s operations, financial results and cash flow.

In addition, emission controls required under the Federal Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at the Company’s facilities. The Company cannot provide assurance that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to the Company’s operations. Revised or additional regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on the Company’s business, financial condition and results of operations.

The inability to continue to access independently owned and publicly owned lands could adversely affect the Company’s ability to operate and/or expand its natural gas gathering and processing business.

Southern Union Gas Services’ ability to operate within its operating region will depend on its success in maintaining existing rights-of-way and obtaining new right-of-way grants. Securing additional rights-of-way is also critical to Southern Union Gas Services’ ability to pursue expansion projects. Southern Union Gas Services cannot assure that

it will be able to acquire new rights-of-way or maintain access to existing rights-of-way upon the expiration of the current grants. The Company’s financial position could be adversely affected if the costs of new or extended right-of-way grants exceed the margin within a gathering region.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

N/A

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

N/A

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

N/A

ITEM 5. OTHER INFORMATION

All information required to be reported on Form 8-K for the quarter ended June 30, 2006 was appropriately reported.

ITEM 6. EXHIBITS

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

2(a)	Amended and Restated Stock Purchase Agreement by and among CMS Gas Transmission Company, Southern Union Company and Southern Union Panhandle Corporation dated as of May 12, 2003. (Filed as Exhibit 99.b to Southern Union’s Current Report on Form 8-K filed on May 27, 2003 and incorporated herein by reference.)

2(b)	Purchase Agreement among CCE Holdings, LLC, Enron Operations Services, LLC, Enron Transportation Services, LLC, EOC Preferred, LLC, and Enron Corp., dated as of June 24, 2004. (Filed as Exhibit 99.b to Southern Union’s Current Report on Form 8-K filed on June 25, 2004 and incorporated herein by reference.)

2(c)	Amendment No. 1 to Purchase Agreement by and among CCE Holdings, LLC, Enron Operations Services, LLC, Enron Transportation Services, LLC, EOC Preferred, LLC, and Enron Corp., dated September 1, 2004. (Filed as Exhibit 10.a to Southern Union’s Current Report on Form 8-K filed on September 14, 2004 and incorporated herein by reference.)

2(d)	Amendment No. 2 to Purchase Agreement by and among CCE Holdings, LLC, Enron Operations Services, LLC, Enron Transportation Services, LLC, EOC Preferred, LLC, and Enron Corp., dated November 10, 2004. (Filed as Exhibit 2.c to Southern Union’s Current Report on Form 8-K filed on November 22, 2004 and incorporated herein by reference.)

2(e)	Purchase Agreement between CCE Holdings, LLC and ONEOK, Inc. dated as of September 16, 2004. (Filed as Exhibit 10.a to Southern Union’s Current Report on Form 8-K filed on September 17, 2004 and incorporated herein by reference.)

2(f)	Purchase and Sale Agreement between Southern Union Company and ONEOK, Inc. dated as of October 16, 2002. (Filed as Exhibit 99.b to Southern Union’s Current Report on Form 8-K filed on October 10, 2002 and incorporated herein by reference.)

2(g)	Escrow Agreement attached as Exhibit B to the Order of the United States Bankruptcy Court for the Southern District of New York dated September 10, 2004 (Filed as Exhibit 10.c to Southern Union’s Current Report on Form 8-K filed on September 14, 2004 and incorporated herein by reference.)

2(h)	Purchase and Sale Agreement by and among SRCG, Ltd. and SRG Genpar, L.P., as Sellers and Southern Union Panhandle LLC and Southern Union Gathering Company LLC,as Buyers, dated as of December 15, 2005. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on December 16, 2005 and incorporated herein by reference.)

2(i)	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(j)	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.)

3(a)	Amended and Restated Certificate of Incorporation of Southern Union Company. (Filed as Exhibit 3.a to Southern Union’s Current Report on Form 10-K filed on March 16, 2006 and incorporated herein by reference.)

3(b)	By-Laws of Southern Union Company as amended through May 9, 2005. (Filed as Exhibit 3.b to Southern Union’s Current Report on Form 10-K filed on March 16, 2006 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)	Indenture between Chase Manhattan Bank, N.A., as trustee, and Southern Union Company dated January 31, 1994. (Filed as Exhibit 4.1 to Southern Union's Current Report on Form 8-K dated February 15, 1994 and incorporated herein 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 (formerly the Chase Manhattan Bank, National Association) (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. (f/n/a JP Morgan Chase Bank) (Filed as Exhibit 4.4 to Southern Union’s Form 8-A/A dated February 22, 2005 and incorporated herein by reference.)

4(p)	First Mortgage Bonds Indenture of Mortgage and Deed of Trust dated as of March 15, 1946 by Southern Union Company (as successor to PG Energy, Inc. formerly, Pennsylvania Gas and Water Company, and originally, Scranton-Spring Brook Water Service Company to Guaranty Trust Company of New York. (Filed as Exhibit 4.1 to Southern Union's Current Report on Form 8-K filed on December 30, 1999 and incorporated herein by reference.)
4(q)	Twenty-Third Supplemental Indenture dated as of August 15, 1989 (Supplemental to Indenture dated as of March 15, 1946) between Southern Union Company and Morgan Guaranty Trust Company of New York (formerly Guaranty Trust Company of New York). (Filed as Exhibit 4.2 to Southern Union's Current Report on Form 8-K filed on December 30, 1999 and incorporated herein by reference.)

4(r)	Twenty-Sixth Supplemental Indenture dated as of December 1, 1992 (Supplemental to Indenture dated as of March 15, 1946) between Southern Union Company and Morgan Guaranty Trust Company of New York. (Filed as Exhibit 4.3 to Southern Union's Current Report on Form 8-K filed on December 30, 1999 and incorporated herein by reference.)

4(s)	Thirtieth Supplemental Indenture dated as of December 1, 1995 (Supplemental to Indenture dated as of March 15, 1946) between Southern Union Company and First Trust of New York, National Association (as successor trustee to Morgan Guaranty Trust Company of New York). (Filed as Exhibit 4.4 to Southern Union's Current Report on Form 8-K filed on December 30, 1999 and incorporated herein by reference.)

4(t)	Thirty-First Supplemental Indenture dated as of November 4, 1999 (Supplemental to Indenture dated as of March 15, 1946) between Southern Union Company and U. S. Bank Trust, National Association (formerly, First Trust of New York, National Association). (Filed as Exhibit 4.5 to Southern Union's Current Report on Form 8-K filed on December 30, 1999 and incorporated herein by reference.)

4(u)	Pennsylvania Gas and Water Company Bond Purchase Agreement dated September 1, 1989. (Filed as Exhibit 4.6 to Southern Union's Current Report on Form 8-K filed on December 30, 1999 and incorporated herein by reference.)

4(v)	Southern Union is a party to certain 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)	Bridge Loan Agreement by and between Southern Union Company and Enhanced Service Systems, as borrowers, and the Banks listed therein dated as of March 1, 2006. (Filed as Exhibit 10.2 to Southern Union’s Current Report on Form 8-K filed on March 6, 2006 and incorporated herein by reference.)

10(b)	First Amendment to the Fourth Amended and Restated Revolving Credit Agreement between Southern Union Company and the Banks named therein. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on March 6, 2006 and incorporated herein by reference.)

10(c)

Fourth Amended and Restated Revolving Credit Agreement between Southern Union Company and the Banks named therein dated September 29, 2005. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on October 5, 2005 and incorporated herein by reference.)

10(d)	Change of Control Agreement between the Company and Julie H. Edwards, effective July 5, 2005. (Filed as Exhibit 10.2 to Southern Union's Current Report on Form 8-K filed on July 5, 2005 and incorporated herein by reference.)

10(e)	Form of Indemnification Agreement between Southern Union Company and each of the Directors of Southern Union Company. (Filed as Exhibit 10(i) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 1986 and incorporated herein by reference.)

10(f)	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(g)	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(h)	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(g)	Employment agreement between Thomas F. Karam and Southern Union Company dated December 28, 1999. (Filed as Exhibit 10(a) to Southern Union's Quarterly Report on Form 10-Q for the quarter ended December 31, 1999 and incorporated herein by reference.)

10(h)	Separation Agreement and General Release Agreement between Thomas F. Karam and Southern Union Company dated November 8, 2005 (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on November 8, 2005 and incorporated herein by reference.)

10(i)	Separation Agreement and General Release Agreement between John E. Brennan and Southern Union Company dated July 1, 2005 (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on July 5, 2005 and incorporated herein by reference.)

10(j)	Separation Agreement and General Release Agreement between David J. Kvapil and Southern Union Company dated July 1, 2005 (Filed as Exhibit 10.4 to Southern Union’s Current Report on Form 8-K filed on July 5, 2005 and incorporated herein by reference.)

10(k)	Southern Union Company Pennsylvania Division Stock Incentive Plan. (Filed as Exhibit 4 to Form S-8, SEC File No. 333-36146, filed on May 3, 2000 and incorporated herein by reference.)

10(l)	Southern Union Company Pennsylvania Division 1992 Stock Option Plan. (Filed as Exhibit 4 to Form S-8, SEC File No. 333-36150, filed on May 3, 2000 and incorporated herein by reference.)

10(m)	Amended and Restated Southern Union Company 2003 Stock and Incentive Plan. (Filed as Exhibit 10(m) to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005 and incorporated herein by reference.)

10(n)

Amended and Restated Limited Liability Company Agreement of CCE Holdings, LLC between EFS-PA, LLC and CCE Acquisition, LLC, dated November 5, 2004. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on November 10, 2004 and incorporated herein by reference.)

10(o)	Administrative Service Agreement between CCE Holdings, LLC and SU Pipeline Management LP, dated November 5, 2004. (Filed as Exhibit 10.2 to Southern Union’s Current Report on Form 8-K filed on November 10, 2004 and incorporated herein by reference.)

14	Code of Ethics and Business Conduct. (Filed as Exhibit 14 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005 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.

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 7, 2006	By /s/ GEORGE E. ALDRICH
	George E. Aldrich Vice President and Controller (authorized officer and principal accounting officer)