Exhibit 99.7

Index to Consolidated Financial Statements

	Page
Report of Independent Registered Public Accounting Firm as of and for the years ended December 31, 2009 and 2008	F-2
Report of Independent Registered Public Accounting Firm as of December 31, 2009	F-3
Consolidated Balance Sheets as of December 31, 2009 and 2008	F-4
Consolidated Statements of Operations for the years ended December  31, 2009, 2008 and 2007	F-5
Consolidated Statements of Comprehensive Income (Loss) for the years ended December  31, 2009, 2008 and 2007	F-6
Consolidated Statements of Cash Flows for the years ended December  31, 2009, 2008 and 2007	F-7
Consolidated Statements of Partners' Capital and Noncontrolling Interest for the years ended December 31, 2009, 2008 and 2007	F-8

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Partners

Regency Energy Partners LP:

We have audited the accompanying consolidated balance sheets of Regency Energy Partners LP and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations, comprehensive income (loss), cash flows, and partners’ capital and noncontrolling interest for each of the years in the three-year period ended December 31, 2009. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Regency Energy Partners LP and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Regency Energy Partners LP’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 1, 2010 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

/s/ KPMG LLP

Dallas, Texas

March 1, 2010

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Partners

Regency Energy Partners LP:

We have audited Regency Energy Partners LP and subsidiaries’ internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Regency Energy Partners LP’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Regency Energy Partners LP and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Regency Energy Partners LP and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations, comprehensive income (loss), cash flows, and partners’ capital and noncontrolling interest for each of the years in the three-year period ended December 31, 2009, and our report dated March 1, 2010 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Dallas, Texas

March 1, 2010

F-3

Regency Energy Partners LP

Consolidated Balance Sheets

(in thousands except unit data)

	December 31, 2009			December 31, 2008
ASSETS
Current Assets:
Cash and cash equivalents	$	9,827		$	599
Restricted cash		1,511			10,031
Trade accounts receivable, net of allowance of $1,130 and $941		30,433			40,875
Accrued revenues		95,240			96,712
Related party receivables		6,222			855
Derivative assets		24,987			73,993
Other current assets		10,556			13,338
Total current assets		178,776			236,403
Property, Plant and Equipment:
Gathering and transmission systems		465,959			652,267
Compression equipment		823,060			799,527
Gas plants and buildings		159,596			156,246
Other property, plant and equipment		162,433			167,256
Construction-in-progress		95,547			154,852
Total property, plant and equipment		1,706,595			1,930,148
Less accumulated depreciation		(250,160	)		(226,594	)
Property, plant and equipment, net		1,456,435			1,703,554
Other Assets:
Investment in unconsolidated subsidiary		453,120			—
Long-term derivative assets		207			36,798
Other, net of accumulated amortization of debt issuance costs of $10,743 and $5,246		19,468			13,880
Total other assets		472,795			50,678
Intangible Assets and Goodwill:
Intangible assets, net of accumulated amortization of $33,929 and $22,517		197,294			205,646
Goodwill		228,114			262,358
Total intangible assets and goodwill		425,408			468,004
TOTAL ASSETS	$	2,533,414		$	2,458,639
LIABILITIES & PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST
Current Liabilities:
Trade accounts payable	$	44,912		$	65,483
Accrued cost of gas and liquids		76,657			76,599
Related party payables		2,312			—
Deferred revenue, including related party amounts of $338 and $0		11,292			11,572
Derivative liabilities		12,256			42,691
Escrow payable		1,511			10,031
Other current liabilities		12,368			10,574
Total current liabilities		161,308			216,950
Long-term derivative liabilities		48,903			560
Other long-term liabilities		14,183			15,487
Long-term debt, net		1,014,299			1,126,229
Commitments and contingencies
Series A convertible redeemable preferred units, redemption amount $83,891		51,711			—
Partners’ Capital and Noncontrolling Interest:
Common units (94,243,886 and 55,519,903 units authorized; 93,188,353 and 54,796,701 units issued and outstanding at December 31, 2009 and 2008)		1,211,605			764,161
Class D common units (7,276,506 units authorized, issued and outstanding at December 31, 2008)		—			226,759
Subordinated units (19,103,896 units authorized, issued and outstanding at December 31, 2008)		—			(1,391	)
General partner interest		19,249			29,283
Accumulated other comprehensive (loss) income		(1,994	)		67,440
Noncontrolling interest		14,150			13,161
Total partners’ capital and noncontrolling interest		1,243,010			1,099,413
TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST	$	2,533,414		$	2,458,639

See accompanying notes to consolidated financial statements

F-4

Regency Energy Partners LP

Consolidated Statements of Operations

(in thousands except unit data and per unit data)

	Year Ended December 31,
	2009			2008			2007
REVENUES
Gas sales	$	481,400		$	1,126,760		$	744,681
NGL sales		262,652			409,476			347,737
Gathering, transportation and other fees, including related party amounts of $11,162, $3,763 and $1,350		273,770			286,507			100,644
Net realized and unrealized gain (loss) from derivatives		41,577			(21,233	)		(34,266	)
Other		30,098			62,294			31,442
Total revenues		1,089,497			1,863,804			1,190,238
OPERATING COSTS AND EXPENSES
Cost of sales, including related party amounts of $10,913, $1,878 and $14,165 and excluding items shown separately below		699,563			1,408,333			976,145
Operation and maintenance		130,826			131,629			58,000
General and administrative		57,863			51,323			39,713
Loss (gain) on asset sales, net		(133,284	)		472			1,522
Management services termination fee		—			3,888			—
Transaction expenses		—			1,620			420
Depreciation and amortization		109,893			102,566			55,074
Total operating costs and expenses		864,861			1,699,831			1,130,874
OPERATING INCOME		224,636			163,973			59,364
Income from unconsolidated subsidiary		7,886			—			—
Interest expense, net		(77,996	)		(63,243	)		(52,016	)
Loss on debt refinancing		—			—			(21,200	)
Other income and deductions, net		(15,132	)		332			1,252
INCOME (LOSS) BEFORE INCOME TAXES		139,394			101,062			(12,600	)
Income tax (benefit) expense		(1,095	)		(266	)		931
NET INCOME (LOSS)	$	140,489		$	101,328		$	(13,531	)
Net income attributable to noncontrolling interest		(91	)		(312	)		(305	)
NET INCOME (LOSS) ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP	$	140,398		$	101,016		$	(13,836	)
Amounts attributable to Series A convertible redeemable preferred units		3,995			—			—
General partner's interest, including IDR		5,252			4,303			(366	)
Amount allocated to non-vested common units		965			869			(103	)
Beneficial conversion feature for Class D common units		820			7,199			—
Beneficial conversion feature for Class C common units		—			—			1,385
Amount allocated to Class E common units		—			—			5,792
Limited partners' interest	$	129,366		$	88,645		$	(20,544	)
Basic and Diluted earnings (loss) per unit:
Amount allocated to common and subordinated units	$	129,366		$	88,645		$	(20,544	)
Weighted average number of common and subordinated units outstanding		80,582,705			66,190,626			51,056,769
Basic income (loss) per common and subordinated unit	$	1.61		$	1.34		$	(0.40	)
Diluted income (loss) per common and subordinated unit	$	1.60		$	1.28		$	(0.40	)
Distributions paid per unit	$	1.78		$	1.71		$	1.52
Amount allocated to Class B common units	$	—		$	—		$	—
Weighted average number of Class B common units outstanding		—			—			651,964
Income per Class B common unit	$	—		$	—		$	—
Distributions per unit	$	—		$	—		$	—
Amount allocated to Class C common units	$	—		$	—		$	1,385
Total number of Class C common units outstanding		—			—			2,857,143
Income per Class C common unit due to beneficial conversion feature	$	—		$	—		$	0.48
Distributions per unit	$	—		$	—		$	—
Amount allocated to Class D common units	$	820		$	7,199		$	—
Total number of Class D common units outstanding		7,276,506			7,276,506			—
Income per Class D common unit due to beneficial conversion feature	$	0.11		$	0.99		$	—
Distributions per unit	$	—		$	—		$	—
Amount allocated to Class E common units	$	—		$	—		$	5,792
Total number of Class E common units outstanding		—			—			4,701,034
Income per Class E common unit due to beneficial conversion feature	$	—		$	—		$	1.23
Distributions per unit	$	—		$	—		$	2.06

See accompanying notes to consolidated financial statements

F-5

Regency Energy Partners LP

Consolidated Statements of Comprehensive Income (Loss)

(in thousands)

	Year Ended December 31,
	2009			2008		2007
Net income (loss)	$	140,489		$	101,328	$	(13,531	)
Net hedging amounts reclassified to earnings		(47,394	)		35,512		19,362
Net change in fair value of cash flow hedges		(22,040	)		70,253		(58,706	)
Comprehensive income (loss)	$	71,055		$	207,093	$	(52,875	)
Comprehensive income attributable to noncontrolling interest		91			312		305
Comprehensive income (loss) attributable to Regency Energy Partners LP	$	70,964		$	206,781	$	(53,180	)

See accompanying notes to consolidated financial statements

F-6

Regency Energy Partners LP

Consolidated Statements of Cash Flows

(in thousands)

	Year Ended December 31,
	2009			2008			2007
OPERATING ACTIVITIES
Net income	$	140,489		$	101,328		$	(13,531	)
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization, including debt issuance cost amortization		116,307			105,324			57,069
Write-off of debt issuance costs		—			—			5,078
Non-cash income from unconsolidated subsidiary		—			—			(43	)
Derivative valuation changes		5,163			(14,700	)		14,667
Loss (gain) on asset sales, net		(133,284	)		472			1,522
Unit based compensation expenses		6,008			4,306			15,534
Gain on insurance settlements		—			(3,282	)		—
Cash flow changes in current assets and liabilities:
Trade accounts receivable, accrued revenues, and related party receivables		10,727			18,648			(28,789	)
Other current assets		10,471			(6,615	)		(1,394	)
Trade accounts payable, accrued cost of gas and liquids, and related party payables		(3,762	)		(40,772	)		30,089
Other current liabilities		(6,726	)		12,749			(149	)
Amount of swap termination proceeds reclassified into earnings		—			—			(1,078	)
Other assets and liabilities		(1,433	)		3,840			554
Net cash flows provided by operating activities		143,960			181,298			79,529
INVESTING ACTIVITIES
Capital expenditures		(193,083	)		(375,083	)		(129,784	)
Acquisitions		(52,803	)		(577,668	)		(34,855	)
Return of investment in unconsolidated subsidiary		1,039			—			—
Acquisition of investment in unconsolidated subsidiary, net of $100 cash		—			—			(5,000	)
Net proceeds from asset sales		88,682			840			11,706
Proceeds from insurance settlement		—			3,282			—
Net cash flows used in investing activities		(156,165	)		(948,629	)		(157,933	)
FINANCING ACTIVITIES
Net (repayments) borrowings under revolving credit facilities		(349,087	)		644,729			59,300
Repayments under credit facilities		—			—			(50,000	)
Proceeds from issuance (repayments) of senior notes, net of discount		236,240			—			(192,500	)
Debt issuance costs		(12,224	)		(2,940	)		(2,427	)
Partner contributions		6,344			11,746			7,735
Partner distributions		(146,585	)		(120,591	)		(79,933	)
Acquisition of assets between entities under common control in excess of historical cost		(10,197	)		—			—
Proceeds from option exercises		—			2,700			—
Proceeds from equity issuances, net of issuance costs		220,318			199,315			353,546
Proceeds from preferred equity issuance, net of issuance costs		76,624			—			—
FrontStreet distributions		—			—			(9,695	)
FrontStreet contributions		—			—			13,417
Net cash flows provided by financing activities		21,433			734,959			99,443
Net increase (decrease) in cash and cash equivalents		9,228			(32,372	)		21,039
Cash and cash equivalents at beginning of period		599			32,971			9,139
Cash acquired from FrontStreet		—			—			2,793
Cash and cash equivalents at end of period	$	9,827		$	599		$	32,971
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	69,401		$	59,969		$	67,844
Income taxes paid		6			605			—
Non-cash capital expenditures in accounts payable		9,688			25,845			7,761
Non-cash capital expenditure for consolidation of investment in previously unconsolidated subsidiary		—			—			5,650
Non-cash capital expenditure upon entering into a capital lease obligation		—			—			3,000
Issuance of common units for an acquisition		—			219,560			19,724
Release of escrow payable from restricted cash		8,501			4,570			—
Contribution of fixed assets, goodwill and working capital to HPC		263,921			—			—
Non-cash proceeds from contribution of RIGS to HPC		403,568			—			—
Distributions accrued but not paid to Series A convertible redeemable preferred units		3,891			—			—

See accompanying notes to consolidated financial statements

F-7

Regency Energy Partners LP

Consolidated Statements of Partners' Capital and Noncontrolling Interest

(in thousands except unit data)

	Units												Common Unitholders			Class B Unitholders
	Common		Class B		Class C		Class D		Class E		Subordinated
Balance—December 31, 2006	19,620,396		5,173,189		2,857,143		—		—		19,103,896		$	42,192		$	60,671
Conversion of Class B and C to common units	8,030,332		(5,173,189	)	(2,857,143	)	—		—		—			120,663			(60,671	)
Issuance of common units for acquisition	751,597		—		—		—		—		—			19,724			—
Issuance of common units	11,500,000		—		—		—		—		—			353,446			—
Issuance of restricted common units, net of forfeitures	565,167		—		—		—		—		—			—			—
Exercise of common unit options	47,403		—		—		—		—		—			100			—
Unit based compensation expenses	—		—		—		—		—		—			15,534			—
Partner distributions	—		—		—		—		—		—			(49,296	)		—
Partner contributions	—		—		—		—		—		—			—			—
Acquisition of FrontStreet	—		—		—		—		4,701,034		—			—			—
FrontStreet contributions	—		—		—		—		—		—			—			—
FrontStreet distributions	—		—		—		—		—		—			—			—
Contributions from noncontrolling interest	—		—		—		—		—		—			—			—
Net (loss) income	—		—		—		—		—		—			(12,037	)		—
Other	—		—		—		—		—		—			25			—
Net hedging activity reclassified to earnings	—		—		—		—		—		—			—			—
Net change in fair value of cash flow hedges	—		—		—		—		—		—			—			—
Balance—December 31, 2007	40,514,895		—		—		—		4,701,034		19,103,896			490,351			—
Issuance of Class D common units	—		—		—		7,276,506		—		—			—			—
Issuance of restricted common units and option exercises, net of forfeitures	559,863		—		—		—		—		—			2,700			—
Issuance of common units	9,020,909		—		—		—		—		—			199,315			—
Working capital adjustment on FrontStreet	—		—		—		—		—		—			—			—
Acquisition on noncontrolling interest	—		—		—		—		—		—			—			—
Conversion of Class E common units	4,701,034		—		—		—		(4,701,034	)	—			92,104			—
Unit based compensation expenses	—		—		—		—		—		—			4,306			—
Partner distributions	—		—		—		—		—		—			(84,207	)		—
Partner contributions	—		—		—		—		—		—			—			—
Net income	—		—		—		—		—		—			59,592			—
Contributions from noncontrolling interest	—		—		—		—		—		—			—			—
Net hedging amounts reclassified to earnings	—		—		—		—		—		—			—			—
Net change in fair value of cash flow hedges	—		—		—		—		—		—			—			—
Balance—December 31, 2008	54,796,701		—		—		7,276,506		—		19,103,896			764,161			—
Revision of partner interest	—		—		—		—		—		—			6,073			—
Issuance of restricted common units, net of forfeitures	(63,750	)	—		—		—		—		—			—			—
Issuance of common units	12,075,000		—		—		—		—		—			220,318			—
Conversion of subordinated units	19,103,896		—		—		—		—		(19,103,896	)		(1,391	)		—
Unit based compensation expenses	—		—		—		—		—		—			6,008			—
Accrued distributions to phantom units	—		—		—		—		—		—			(249	)		—
Acquisition of assets between entities under common control in excess of historical cost	—		—		—		—		—		—			—			—
Partner distributions	—		—		—		—		—		—			(141,225	)		—
Partner contributions	—		—		—		—		—		—			—			—
Net income	—		—		—		—		—		—			134,326			—
Conversion of Class D common units	7,276,506		—		—		(7,276,506	)	—		—			227,579			—
Contributions from noncontrolling interest	—		—		—		—		—		—			—			—
Accrued distributions to Series A convertible redeemable preferred units	—		—		—		—		—		—			(3,891	)		—
Accretion of Series A convertible redeemable preferred units	—		—		—		—		—		—			(104	)		—
Net cash flow hedge amounts reclassified to earnings	—		—		—		—		—		—			—			—
Net change in fair value of cash flow hedges	—		—		—		—		—		—			—			—
Balance—December 31, 2009	93,188,353		—		—		—		—		—		$	1,211,605		$	—

See accompanying notes to consolidated financial statements

F-8

Regency Energy Partners LP

Consolidated Statements of Partners' Capital and Noncontrolling Interest—(Continued)

(in thousands except unit data)

	Class C Unitholders			Class D Unitholders			Class E Unitholders			Subordinated Unitholders			General Partner Interest			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total
Balance—December 31, 2006	$	59,992		$	—		$	—		$	43,240		$	5,543		$	1,019		$	—		$	212,657
Conversion of Class B and C to common units		(59,992	)		—			—			—			—			—			—			—
Issuance of common units for acquisition		—			—			—			—			—			—			—			19,724
Issuance of common units		—			—			—			—			—			—			—			353,446
Issuance of restricted common units, net of forfeitures		—			—			—			—			—			—			—			—
Exercise of common unit options		—			—			—			—			—			—			—			100
Unit based compensation expenses		—			—			—			—			—			—			—			15,534
Partner distributions		—			—			—			(29,038	)		(1,599	)		—			—			(79,933	)
Partner contributions		—			—			—			—			7,735			—			—			7,735
Acquisition of FrontStreet		—			—			83,448			—			—			—			—			83,448
FrontStreet contributions		—			—			13,417			—			—			—			—			13,417
FrontStreet distributions		—			—			(9,695	)		—			—			—			—			(9,695	)
Contributions from noncontrolling interest		—			—			—			—			—			—			4,588			4,588
Net (loss) income		—			—			5,792			(7,198	)		(393	)		—			305			(13,531	)
Other		—			—			—			15			—			—			—			40
Net hedging activity reclassified to earnings		—			—			—			—			—			19,362			—			19,362
Net change in fair value of cash flow hedges		—			—			—			—			—			(58,706	)		—			(58,706	)
Balance—December 31, 2007		—			—			92,962			7,019			11,286			(38,325	)		4,893			568,186
Issuance of Class D common units		—			219,560			—			—			—			—			—			219,560
Issuance of restricted common units and option exercises, net of forfeitures		—			—			—			—			—			—			—			2,700
Issuance of common units		—			—			—			—			—			—			—			199,315
Working capital adjustment on FrontStreet		—			—			(858	)		—			—			—			—			(858	)
Acquisition on noncontrolling interest		—			—			—			—			—			—			(4,893	)		(4,893	)
Conversion of Class E common units		—			—			(92,104	)		—			—			—			—			—
Unit based compensation expenses		—			—			—			—			—			—			—			4,306
Partner distributions		—			—			—			(32,668	)		(3,716	)		—			—			(120,591	)
Partner contributions		—			—			—			—			11,746			—			—			11,746
Net income		—			7,199			—			24,258			9,967			—			312			101,328
Contributions from noncontrolling interest		—			—			—			—			—			—			12,849			12,849
Net hedging amounts reclassified to earnings		—			—			—			—			—			35,512			—			35,512
Net change in fair value of cash flow hedges		—			—			—			—			—			70,253			—			70,253
Balance—December 31, 2008		—			226,759			—			(1,391	)		29,283			67,440			13,161			1,099,413
Revision of partner interest		—			—			—			—			(6,073	)		—			—			—
Issuance of restricted common units, net of forfeitures		—			—			—			—			—			—			—			—
Issuance of common units		—			—			—			—			—			—			—			220,318
Conversion of subordinated units		—			—			—			1,391			—			—			—			—
Unit based compensation expenses		—			—			—			—			—			—			—			6,008
Accrued distributions to phantom units		—			—			—			—			—			—			—			(249	)
Acquisition of assets between entities under common control in excess of historical cost		—			—			—			—			(10,197	)		—			—			(10,197	)
Partner distributions		—			—			—			—			(5,360	)		—			—			(146,585	)
Partner contributions		—			—			—			—			6,344			—			—			6,344
Net income		—			820			—			—			5,252			—			91			140,489
Conversion of Class D common units		—			(227,579	)		—			—			—			—			—			—
Contributions from noncontrolling interest		—			—			—			—			—			—			898			898
Accrued distributions to Series A convertible redeemable preferred units		—			—			—			—			—			—			—			(3,891	)
Accretion of Series A convertible redeemable preferred units		—			—			—			—			—			—			—			(104	)
Net cash flow hedge amounts reclassified to earnings		—			—			—			—			—			(47,394	)		—			(47,394	)
Net change in fair value of cash flow hedges		—			—			—			—			—			(22,040	)		—			(22,040	)
Balance—December 31, 2009	$	—		$	—		$	—		$	—		$	19,249		$	(1,994	)	$	14,150		$	1,243,010

See accompanying notes to consolidated financial statements

F-9

Regency Energy Partners LP

Notes to Consolidated Financial Statements

For the Year Ended December 31, 2009

1. Organization and Basis of Presentation

Organization. The consolidated financial statements presented herein contain the results of Regency Energy Partners LP and its subsidiaries (“Partnership”), a Delaware limited partnership. The Partnership was formed on September 8, 2005, and completed its IPO on February 3, 2006. The Partnership and its subsidiaries are engaged in the business of gathering, processing and transporting natural gas and NGLs as well as providing contract compression services. Regency GP LP is the Partnership’s general partner and Regency GP LLC (collectively the “General Partner”) is the managing general partner of the Partnership and the general partner of Regency GP LP.

On June 18, 2007, indirect subsidiaries of GECC acquired 91.3 percent of both the member interest in the General Partner and the outstanding limited partner interests in the General Partner from an affiliate of HM Capital Partners and acquired 17,763,809 of the outstanding subordinated units, exclusive of 1,222,717 subordinated units which were owned directly or indirectly by certain members of the Partnership’s management. The Partnership was not required to record any adjustments to reflect the acquisition of the HM Capital Partners’ interest in the Partnership or the related transactions (together, referred to as “GE EFS Acquisition”).

In January 2008, the Partnership acquired all of the outstanding equity and noncontrolling interest (the “FrontStreet Acquisition”) of FrontStreet from ASC, an affiliate of GECC, and EnergyOne. Because the acquisition of ASC’s 95 percent interest was a transaction between commonly controlled entities, the Partnership accounted for this portion of the acquisition in a manner similar to the pooling of interest method. Information included in these financial statements is presented as if the FrontStreet Acquisition had been combined throughout the periods presented in which common control existed, June 18, 2007 forward. Conversely, the acquisition of EnergyOne’s noncontrolling interest is a transaction between independent parties, for which the Partnership applied the purchase method of accounting.

In March 2009, the Partnership contributed RIGS to a HPC in exchange for a noncontrolling interest in that joint venture. Accordingly, the Partnership no longer consolidates RIGS in its financial statements, and accounts for its investment in HPC under the equity method. Transactions between the Partnership and HPC involve the transportation of natural gas, contract compression services, and the provision of administrative support. Because these transactions are immediately realized, the Partnership does not eliminate these transactions with its equity method investee.

Basis of presentation. The consolidated financial statements of the Partnership have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of all controlled subsidiaries after the elimination of all intercompany accounts and transactions.

2. Summary of Significant Accounting Policies

Use of Estimates. These consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates.

Cash and Cash Equivalents. Cash and cash equivalents include temporary cash investments with original maturities of three months or less.

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Restricted Cash. Restricted cash of $1,511,000 is held in escrow for purchase indemnifications related to the El Paso acquisition and for environmental remediation projects. A third-party agent invests funds held in escrow in US Treasury securities. Interest earned on the investment is credited to the escrow account.

Equity Method Investments. The equity method of accounting is used to account for the Partnership’s interest in investments of greater than 20 percent voting interest or exerts significant influence over an investee and where the Partnership lacks control over the investee.

Property, Plant and Equipment. Property, plant and equipment is recorded at historical cost of construction or, upon acquisition, the fair value of the assets acquired. Sales or retirements of assets, along with the related accumulated depreciation, are included in operating income unless the disposition is treated as discontinued operations. Natural gas and NGLs used to maintain pipeline minimum pressures is capitalized and classified as property, plant and equipment. Financing costs associated with the construction of larger assets requiring ongoing efforts over a period of time are capitalized. For the years ended December 31, 2009, 2008, and 2007, the Partnership capitalized interest of $1,722,000, $2,409,000 and $1,754,000, respectively. The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. Expenditures to extend the useful lives of the assets are capitalized.

The Partnership accounts for its asset retirement obligations by recognizing on its balance sheet the net present value of any legally-binding obligation to remove or remediate the physical assets that it retires from service, as well as any similar obligations for which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the Partnership. While the Partnership is obligated under contractual agreements to remove certain facilities upon their retirement, management is unable to reasonably determine the fair value of such asset retirement obligations because the settlement dates, or ranges thereof, were indeterminable and could range up to 95 years, and the undiscounted amounts are immaterial. An asset retirement obligation will be recorded in the periods wherein management can reasonably determine the settlement dates.

Depreciation expense related to property, plant and equipment was $97,426,000, $88,828,000, and $50,719,000 for the years ended December 31, 2009, 2008, and 2007, respectively. Depreciation of plant and equipment is recorded on a straight-line basis over the following estimated useful lives.

Functional Class of Property	Useful Lives (Years)
Gathering and transmission systems	5 - 20
Compression equipment	10 - 30
Gas plants and buildings	15 - 35
Other property, plant and equipment	3 - 10

Intangible Assets. Intangible assets consisting of (i) permits and licenses, (ii) customer contracts, (iii) trade name, and (iv) customer relations are amortized on a straight line basis over their estimated useful lives, which is the period over which the assets are expected to contribute directly or indirectly to the Partnership’s future cash flows. The estimated useful lives range from three to 30 years.

The Partnership assesses long-lived assets, including property, plant and equipment and intangible assets, for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is assessed by comparing the carrying amount of an asset to undiscounted future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured as the amount by which the carrying amounts exceed the fair value of the assets. The Partnership did not record any impairment in 2009, 2008 or 2007.

Goodwill. Goodwill represents the excess of the purchase price over the fair value of identifiable net assets acquired in a business combination. Goodwill is not amortized, but is tested for impairment annually based on

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the carrying values as of December 31, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may not be recovered. Impairment occurs when the carrying amount of a reporting unit exceeds its fair value. At the time it is determined that an impairment has occurred, the carrying value of the goodwill is written down to its fair value. To estimate the fair value of the reporting units, the Partnership makes estimates and judgments about future cash flows, as well as revenues, cost of sales, operating expenses, capital expenditures and net working capital based on assumptions that are consistent with the Partnership’s most recent forecast. No impairment was indicated for the years ended December 31, 2009, 2008, or 2007.

Other Assets, net. Other assets, net primarily consists of debt issuance costs, which are capitalized and amortized to interest expense, net over the life of the related debt. Taxes incurred on behalf of, and passed through to, the Partnership’s compression customers are accounted for on a net basis.

Gas Imbalances. Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements are recorded monthly as other current assets or other current liabilities using then current market prices or the weighted average prices of natural gas or NGLs at the plant or system pursuant to imbalance agreements for which settlement prices are not contractually established. Within certain volumetric limits determined at the sole discretion of the creditor, these imbalances are generally settled by deliveries of natural gas. Imbalance receivables and payables as of December 31, 2009 and 2008 were immaterial.

Revenue Recognition. The Partnership earns revenue from (i) domestic sales of natural gas, NGLs and condensate, (ii) natural gas gathering, processing and transportation, and (iii) contract compression services. Revenue associated with sales of natural gas, NGLs and condensate are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery occurs. Revenue associated with transportation and processing fees are recognized when the service is provided. For contract compression services, revenue is recognized when the service is performed. For gathering and processing services, the Partnership receives either fees or commodities from natural gas producers depending on the type of contract. Commodities received are in turn sold and recognized as revenue in accordance with the criteria outlined above. Under the percentage-of-proceeds contract type, the Partnership is paid for its services by keeping a percentage of the NGLs produced and a percentage of the residue gas resulting from processing the natural gas. Under the percentage-of-index contract type, the Partnership earns revenue by purchasing wellhead natural gas at a percentage of the index price and selling processed natural gas at a price approximating the index price and NGLs to third parties. The Partnership generally reports revenue gross in the consolidated statements of operations when it acts as the principal, takes title to the product, and incurs the risks and rewards of ownership. Revenue for fee-based arrangements is presented net, because the Partnership takes the role of an agent for the producers. Allowance for doubtful accounts is determined based on historical write-off experience and specific identification.

Derivative Instruments. The Partnership’s net income and cash flows are subject to volatility stemming from changes in market prices such as natural gas prices, NGLs prices, processing margins and interest rates. The Partnership uses ethane, propane, butane, natural gasoline, and condensate swaps to create offsetting positions to specific commodity price exposures. Derivative financial instruments are recorded on the balance sheet at their fair value on a net basis by settlement date. The Partnership employs derivative financial instruments in connection with an underlying asset, liability and/or anticipated transaction and not for speculative purposes. Derivative financial instruments qualifying for hedge accounting treatment have been designated by the Partnership as cash flow hedges. The Partnership enters into cash flow hedges to hedge the variability in cash flows related to a forecasted transaction. At inception, the Partnership formally documents the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing correlation and hedge effectiveness. The Partnership also assesses, both at the inception of the hedge and on an on-going basis, whether the derivatives are highly effective in offsetting changes in cash flows of the hedged item. Furthermore, the Partnership regularly assesses the creditworthiness of counterparties to manage the risk of default. If the Partnership determines that a derivative is no longer highly effective as a hedge, it discontinues hedge accounting prospectively by including changes in the fair value of the derivative in

F-12

current earnings. For cash flow hedges, changes in the derivative fair values, to the extent that the hedges are effective, are recorded as a component of accumulated other comprehensive income until the hedged transactions occur and are recognized in earnings. Any ineffective portion of a cash flow hedge’s change in value is recognized immediately in earnings. In the statement of cash flows, the effects of settlements of derivative instruments are classified consistent with the related hedged transactions. For the Partnership’s derivative financial instruments that were not designated for hedge accounting, the change in market value is recorded as a component of net unrealized and realized gain (loss) from derivatives in the consolidated statements of operations.

Benefits. The Partnership provides medical, dental, and other healthcare benefits to employees. The Partnership provides a matching contribution for employee contributions to their 401(k) accounts, which vests ratably over 3 years. The amount of matching contributions for the years ended December 31, 2009, 2008, and 2007 were $1,440,000, $395,000, and $469,000, respectively, and were recorded in general and administrative expenses. The Partnership has no pension obligations or other post employment benefits.

Income Taxes. The Partnership is generally not subject to income taxes, except as discussed below, because its income is taxed directly to its partners. The Partnership is subject to the gross margin tax enacted by the state of Texas. The Partnership has wholly-owned subsidiaries that are subject to income tax and provides for deferred income taxes using the asset and liability method for these entities. Accordingly, deferred taxes are recorded for differences between the tax and book basis that will reverse in future periods. The Partnership’s deferred tax liability of $6,996,000 and $8,156,000 as of December 31, 2009 and 2008 relates to the difference between the book and tax basis of property, plant and equipment and intangible assets and is included in other long-term liabilities in the accompanying consolidated balance sheet. The Partnership follows the guidance for uncertainties in income taxes where a liability for an unrecognized tax benefit is recorded for a tax position that does not meet the “more likely than not” criteria. The Partnership has not recorded any uncertain tax positions meeting the more likely than not criteria as of December 31, 2009 and 2008. The Partnership’s entities that are required to pay federal income tax recognized current federal income tax benefit of $420,000 and deferred income tax benefit of $1,160,000 using a 35 percent effective rate during the year ended December 31, 2009.

As of December 31, 2009, the IRS is conducting an audit to the tax returns of Pueblo Holdings Inc., a wholly-owned subsidiary of the Partnership, for the tax years ended December 31, 2007 and December 31, 2008. In addition, on January 27, 2010, the IRS mailed two “Notice of Beginning of Administrative Proceeding” to the Partnership stating that the IRS is commencing audits of the Partnership’s 2007 and 2008 partnership tax returns.

Equity-Based Compensation. The Partnership accounts for equity-based compensation by recognizing the grant-date fair value of awards into expense as they are earned, using an estimated forfeiture rate. The forfeiture rate assumption is reviewed annually to determine whether any adjustments to expense are required.

Earnings per Unit. Basic net income per common unit is computed through the use of the two-class method, which allocates earnings to each class of equity security based on their participation in distributions and deemed distributions. Accretion of the Series A Convertible Redeemable Preferred Units (“Series A Preferred Units”) and the beneficial conversion feature related to the Class D common units are considered deemed distributions. Distributions and deemed distributions to the Series A Preferred Units as well as the beneficial conversion feature of the Class D common units reduce the amount of net income available to the general partner and limited partner interests. The general partners’ interest in net income or loss consists of its two percent interest, make-whole allocations for any losses allocated in a prior tax year and incentive distribution rights (“IDRs”). After deducting the General Partner’s interest, the limited partners’ interest in the remaining net income or loss is allocated to each class of equity units based on distributions and beneficial conversion feature amounts, if applicable, then divided by the weighted average number of common and subordinated units outstanding in each class of security. Diluted net income per common unit is computed by dividing limited partners’ interest in net income, after deducting the General Partner’s interest, by the weighted average number of units outstanding and

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the effect of non-vested restricted units, phantom units, Series A Preferred Units and unit options computed using the treasury stock method. Common and subordinated units are considered to be a single class. For special classes of common units issued with a beneficial conversion feature, the amount of the benefit associated with the period is added back to net income and the unconverted class is added to the denominator.

Revision to Partners' Capital Accounts. In 2009, the Partnership revised the allocation of net income between the General Partner and common unitholders from the third quarter of 2008 to reflect the income allocation provisions of the Partnership agreement. The effect of this revision is not material to the prior financial statements.

Recently Issued Accounting Standards. In June 2009, the FASB issued guidance that significantly changed the consolidation model for variable interest entities. The guidance is effective for annual reporting periods that begin after November 15, 2009, and for interim periods within that first annual reporting period. The Partnership has evaluated this guidance and determined that it will have no impact on its financial position, results of operations or cash flows as a result of adopting this guidance on January 1, 2010.

In January 2010, the FASB issued guidance requiring improved disclosure of transfers in and out of Levels 1 and 2 for an entity’s fair value measurements, such requirement becoming effective for interim and annual periods beginning after December 15, 2009. Further, additional disclosure of activities such as purchases, sales, issuances and settlements of items relying on Level 3 inputs will be required, such requirements becoming effective for interim and annual periods beginning after December 15, 2010. The Partnership has evaluated this guidance and determined that it will have no impact on its financial position, results of operations or cash flows upon adopting this guidance.

3. Partners’ Capital and Distributions

Common Unit Offerings. In August 2008, the Partnership sold 9,020,909 common units and received $204,133,000 in proceeds, inclusive of the General Partner’s proportionate capital contribution. In December 2009, the Partnership sold 12,075,000 common units and received $225,030,000 in proceeds, inclusive of the General Partner’s proportionate capital contribution.

Subordinated Units. The subordinated units converted into common units on a one-for-one basis on February 17, 2009.

Class E Common Units. On January 7, 2008, the Partnership issued 4,701,034 of Class E common units to ASC as consideration for the FrontStreet Acquisition. The Class E common units had the same terms and conditions as the Partnership’s common units, except that the Class E common units were not entitled to participate in earnings or distributions by the Partnership. The Class E common units were issued in a private placement conducted in accordance with the exemption from the registration requirements of the Securities Act of 1933, as amended under Section 4(2) thereof. The Class E common units converted into common units on a one-for-one basis on May 5, 2008.

Class D Common Units. On January 15, 2008, the Partnership issued 7,276,506 of Class D common units to CDM as partial consideration for the CDM acquisition. The Class D common units had the same terms and conditions as the Partnership’s common units, except that the Class D common units were not entitled to participate in earnings or distributions by the Partnership. The Class D common units were issued in a private placement conducted in accordance with the exemption from the registration requirements of the Securities Act of 1933, as amended under Section 4(2) thereof. The Class D common units converted into common units without the payment of further consideration on a one-for-one basis on February 9, 2009.

Noncontrolling Interest. The Partnership operates a gas gathering joint venture in south Texas in which a third party owns a 40 percent interest, which is reflected on the balance sheet in noncontrolling interest.

F-14

Distributions. The partnership agreement requires the distribution of all of the Partnership’s Available Cash (defined below) within 45 days after the end of each quarter to unitholders of record on the applicable record date, as determined by the general partner.

Available Cash. Available Cash, for any quarter, generally consists of all cash and cash equivalents on hand at the end of that quarter less the amount of cash reserves established by the general partner to: (i) provide for the proper conduct of the Partnership’s business; (ii) comply with applicable law, any debt instruments or other agreements; or (iii) provide funds for distributions to the unitholders and to the General Partner for any one or more of the next four quarters and plus, all cash on hand on that date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made.

General Partner Interest and Incentive Distribution Rights. The General Partner is entitled to 2 percent of all quarterly distributions that the Partnership makes prior to its liquidation. This General Partner interest is represented by 1,901,803 equivalent units as of December 31, 2009. The General Partner has the right, but not the obligation, to contribute a proportionate amount of capital to the Partnership to maintain its current general partner interest. The General Partner’s initial 2 percent interest in these distributions will be reduced if the Partnership issues additional units in the future and the General Partner does not contribute a proportionate amount of capital to the Partnership to maintain its 2 percent General Partner interest.

The incentive distribution rights held by the General Partner entitles it to receive an increasing share of Available Cash when pre-defined distribution targets are achieved. The General Partner’s incentive distribution rights are not reduced if the Partnership issues additional units in the future and the general partner does not contribute a proportionate amount of capital to the Partnership to maintain its 2 percent general partner interest.

Distributions of Available Cash. The partnership agreement requires that it make distributions of Available Cash from operating surplus for any quarter after the subordination period in the following manner:

• first, 98 percent to all unitholders, pro rata, and 2 percent to the General Partner, until each unitholder receives a total of $0.35 per unit for that quarter;

• second, 98 percent to all unitholders, pro rata, and 2 percent to the General Partner, until each unitholder receives a total of $0.4025 per unit for that quarter;

• third, 85 percent to all unitholders, pro rata, 13 percent to holders of the incentive distribution rights, and 2 percent to the General Partner, until the aggregate distributions equal $0.4375 per unit outstanding for that quarter;

• fourth, 75 percent to all unitholders, pro rata, 23 percent to holders of the incentive distribution rights, and 2 percent to the General Partner, until the aggregate distributions equal $0.525 per unit outstanding for that quarter; and

• thereafter, 50 percent to all unitholders, pro rata, 48 percent to holders of the incentive distribution rights, and 2 percent to the General Partner.

F-15

Distributions. The Partnership made the following cash distributions per unit during the years ended December 31, 2009 and 2008:

Distribution Date	Cash Distribution
		(per Unit	)
November 13, 2009	$	0.445
August 14, 2009		0.445
May 14, 2009		0.445
February 13, 2009		0.445
November 14, 2008		0.445
August 14, 2008		0.445
May 14, 2008		0.420
February 14, 2008		0.400

4. Income (Loss) per Limited Partner Unit

The following table provides a reconciliation of the numerator and denominator of the basic and diluted earnings per unit computations for the years ended December 31, 2009 and 2008.

	For the Year Ended December 31, 2009					For the Year Ended December 31, 2008
	Income (Numerator)		Units (Denominator)	Per-Unit Amount		Income (Numerator)		Units (Denominator)	Per-Unit Amount
	(in thousands except unit and per unit data)
Basic Earnings per Unit
Limited partners' interests	$	129,366	80,582,705	$	1.61	$	88,645	66,190,626	$	1.34
Effect of Dilutive Securities
Restricted (non-vested) common units		—	—				—	5,451
Common unit options		—	—				—	30,580
Phantom units		—	100,764				—	—
Class D common units		820	797,425				7,199	6,978,289
Class E common units		—	—				—	1,618,389
Diluted Earnings per Unit	$	130,186	81,480,894	$	1.60	$	95,844	74,823,335	$	1.28

For the year ended December 31, 2007, diluted earnings per unit equals basic because all instruments were antidilutive.

In connection with the CDM acquisition discussed below, the Partnership issued 7,276,506 Class D common units. At the commitment date, the sales price of $30.18 per unit represented a $1.10 discount from the fair value of the Partnership’s common units. This discount represented a beneficial conversion feature that is treated as a non-cash distribution for purposes of calculating earnings per unit. The beneficial conversion feature is reflected in income per unit using the effective yield method over the period the Class D common units were outstanding, as indicated on the statements of operations in the line item entitled “beneficial conversion feature for Class D common units.”

In connection with the FrontStreet acquisition, the Partnership issued 4,701,034 Class E common units to ASC, an affiliate of GECC. Because this transaction represented the acquisition of an entity under common control, the Partnership applied a method of accounting similar to a pooling of interests. The amount of net income allocated to the Class E common units represents amounts earned by FrontStreet between the date of common control and the transaction date. The amount of distributions per unit reflects amounts paid out to the owners of FrontStreet prior to the acquisition.

F-16

The following data show securities that could potentially dilute earnings per unit in the future that were not included in the computation of diluted earnings per unit because to do so would have been antidilutive for the periods presented.

	For the Year Ended December 31,
	2009	2008	2007
Restricted (non-vested) common units	566,493	—	397,500
Common unit options	357,489	—	738,668
Convertible redeemable preferred units	1,449,211	—	—

The partnership agreement requires that the General Partner shall receive a 100 percent allocation of income until its capital account is made whole for all of the net losses allocated to it in prior years.

5. Acquisitions and Dispositions

2009

HPC. In March 2009, the Partnership completed a joint venture arrangement among Regency HIG, EFS Haynesville, and the Alinda Investors. The Partnership contributed RIG, which owns the Regency Intrastate Gas System, with a fair value of $401,356,000, to HPC, in exchange for a 38 percent interest in HPC. EFS Haynesville and Alinda Investors contributed $126,928,000 and $528,284,000 in cash, respectively, to HPC in return for a 12 percent and a 50 percent interest, respectively. The disposition and deconsolidation resulted in the recording of a $133,451,000 gain (of which $52,813,000 represents the remeasurement of the Partnership’s retained 38 percent interest to its fair value), net of transaction costs of $5,530,000.

In September 2009, the Partnership purchased a five percent interest in HPC from EFS Haynesville for $63,000,000, increasing the Partnership’s ownership percentage from 38 percent to 43 percent. Because the transaction occurred between two entities under common control, the Partnership’s general partner interest was reduced by $10,197,000, which represented a deemed distribution of the excess purchase price over EFS Haynesville’s carrying amount.

2008

FrontStreet. In January 2008, the Partnership completed the FrontStreet Acquisition. FrontStreet owned a gas gathering system located in Kansas and Oklahoma, which is operated by a third party. The total purchase price consisted of (a) 4,701,034 Class E common units of the Partnership issued to ASC in exchange for its 95 percent interest and (b) $11,752,000 in cash to EnergyOne in exchange for its five percent minority interest and the termination of a management services contract valued at $3,888,000. The Partnership financed the cash portion of the purchase price with borrowings under its revolving credit facility.

Because the acquisition of ASC’s 95 percent interest was a transaction between commonly controlled entities, the Partnership accounted for this portion of the acquisition in a manner similar to the pooling of interest method. Information included in these financial statements is presented as if the FrontStreet Acquisition had been combined throughout the periods presented in which common control existed, June 18, 2007 forward. Conversely, the acquisition of the five percent minority interest is a transaction between independent parties, for which the Partnership applied the purchase method of accounting.

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The following table summarizes the book value of the assets acquired and the liabilities assumed at the date of common control, following the as if pooled method of accounting.

	At June 18, 2007
	(in thousands)
Current assets	$	8,840
Property, plant and equipment		91,556
Total assets acquired		100,396
Current liabilities		(12,556	)
Net book value of assets acquired	$	87,840

CDM Resource Management, Ltd. In January 2008, the Partnership acquired CDM by (a) issuing an aggregate of 7,276,506 Class D common units of the Partnership, which were valued at $219,590,000 and (b) paying an aggregate of $478,445,000 in cash, $316,500,000 of which was used to retire CDM’s debt obligations.

The total purchase price of $699,841,000, including direct transaction costs, was allocated as follows.

	At January 15, 2008
	(in thousands)
Current assets	$	19,463
Other assets		4,658
Gas plants and buildings		1,528
Gathering and transmission systems		420,974
Other property, plant and equipment		2,728
Construction-in-process		36,239
Identifiable intangible assets		80,480
Goodwill		164,882
Assets acquired		730,952
Current liabilities		(31,054	)
Other liabilities		(57	)
Net assets acquired	$	699,841

Nexus Gas Holdings, LLC. In March 2008, the Partnership acquired Nexus (“Nexus Acquisition”) for $88,486,000 in cash. The Partnership funded the Nexus Acquisition through borrowings under its existing credit facility.

The total purchase price of $88,640,000 was allocated as follows.

	At March 25, 2008
	(in thousands)
Current assets	$	3,457
Buildings		13
Gathering and transmission systems		16,960
Other property, plant and equipment		4,440
Identifiable intangible assets		61,100
Goodwill		3,341
Assets acquired		89,311
Current liabilities		(671	)
Net assets acquired	$	88,640

F-18

2007

Palafox Joint Venture. The Partnership acquired the outstanding interest in the Palafox Joint Venture not owned (50 percent) for $5,000,000 effective February 1, 2007. The Partnership allocated $10,057,000 to gathering and transmission systems in the three months ended March 31, 2007. The allocated amount consists of the investment in unconsolidated subsidiary of $5,650,000 immediately prior to the Partnership’s acquisition and the Partnership’s $5,000,000 purchase of the remaining interest offset by $593,000 of working capital accounts acquired.

Significant Asset Dispositions. The Partnership sold selected non-core pipelines, related rights of way and contracts located in south Texas for $5,340,000 on March 31, 2007 and recorded a loss on sale of $1,808,000. Additionally, the Partnership sold two small gathering systems and associated contracts located in the Mid-continent region for $1,750,000 on May 31, 2007 and recorded a loss on the sale of $469,000. The Partnership also sold its 34 mile NGL pipeline located in east Texas for $3,000,000 on June 29, 2007 and simultaneously entered into transportation and operating agreements with the buyer. The Partnership accounted for this transaction as a sale-leaseback whereby the $3,000,000 gain was deferred and will be amortized to earnings over a 20 year period. The Partnership recorded $3,000,000 in gathering and transmission systems and the related obligations under capital lease. On August 31, 2007, the Partnership sold an idle processing plant for $1,300,000 and recorded a $740,000 gain.

Acquisition of Pueblo Midstream Gas Corporation. In April 2007, the Partnership and its indirect wholly-owned subsidiary, Pueblo Holdings, acquired all the outstanding equity of Pueblo. The purchase price for the Pueblo acquisition consisted of (1) the issuance of 751,597 common units of the Partnership to the members, valued at $19,724,000 and (2) the payment of $34,855,000 in cash, exclusive of outstanding Pueblo liabilities of $9,822,000 and certain working capital amounts acquired of $108,000. The cash portion of the consideration was financed out of the proceeds of the Partnership’s credit facility.

The Pueblo acquisition offered the opportunity to reroute gas to one of the Partnership’s existing gas processing plants to provide cost savings. The total purchase price was allocated as follows based on estimates of the fair values of assets acquired and liabilities assumed.

	At April 2, 2007
	(in thousands)
Current assets	$	1,295
Gas plants and buildings		8,994
Gathering and transmission systems		13,079
Other property, plant and equipment		180
Intangible assets subject to amortization (contracts)		5,242
Goodwill		36,523
Assets acquired		65,313
Current liabilities		(1,187	)
Long-term liabilities		(9,492	)
Total Purchase price	$	54,634

F-19

The following unaudited pro forma financial information has been prepared as if the acquisitions of FrontStreet, CDM, Nexus and Pueblo, as well as the contribution of RIG to HPC as well as the acquisition of additional five percent HPC interest had occurred as of the beginning of the earliest period presented. Such unaudited pro forma financial information does not purport to be indicative of the results of operations that would have been achieved if the transactions to which the Partnership is giving pro forma effect actually occurred on the date referred to above or the results of operations that may be expected in the future.

	Pro Forma Results for the Year Ended December  31,
	2009			2008		2007
	(in thousands except unit and per unit data)
Revenue	$	1,077,524		$	1,822,722	$	1,274,829
Net income attributable to Regency Energy Partners LP		5,844			81,691		112,474
Less:
Amounts attributable to Series A Convertible Redeemable Preferred Units		7,781			7,781		7,781
General partner's interest, including IDR		2,485			3,769		1,980
Amount allocated to non-vested common units		(266	)		491		669
Beneficial conversion feature for Class C common units		—			—		1,385
Beneficial conversion feature for Class D common units		820			7,199		—
Amount allocated to Class E common units		—			—		5,792
Limited partners' interest	$	(4,976	)	$	62,451	$	94,867
Basic and Diluted earnings per unit:
Amount allocated to common and subordinated units	$	(4,976	)	$	62,451	$	94,867
Weighted average number of common and subordinated units outstanding		80,582,705			66,190,626		51,056,769
Basic (loss) income per common and subordinated unit	$	(0.06	)	$	0.94	$	1.86
Diluted (loss) income per common and subordinated unit	$	(0.06	)	$	0.94	$	1.59
Distributions paid per unit	$	1.78		$	1.71	$	1.52
Amount allocated to Class B common units	$	—		$	—	$	—
Weighted average number of Class B common units outstanding		—			—		651,964
Income per Class B common unit	$	—		$	—	$	—
Distributions per unit	$	—		$	—	$	—
Amount allocated to Class C common units	$	—		$	—	$	1,385
Total number of Class C common units outstanding		—			—		2,857,143
Income per Class C common unit due to beneficial conversion feature	$	—		$	—	$	0.48
Distributions per unit	$	—		$	—	$	—
Amount allocated to Class D common units	$	820		$	7,199	$	—
Total number of Class D common units outstanding		7,276,506			7,276,506		7,276,506
Income per Class D common unit due to beneficial conversion feature	$	0.11		$	0.99	$	—
Distributions per unit	$	—		$	—	$	—
Amount allocated to Class E common units	$	—		$	—	$	5,792
Total number of Class E common units outstanding		—			—		4,701,034
Income per Class E common unit	$	—		$	—	$	1.23
Distributions per unit	$	—		$	—	$	2.06

F-20

6. Investment in Unconsolidated Subsidiary

As described in the Acquisitions and Dispositions footnote, the Partnership contributed RIG to HPC for a 38 percent partner’s interest in HPC. Subsequently, on September 2, 2009, the Partnership purchased an additional five percent partner’s interest in HPC from EFS Haynesville for $63,000,000. The Partnership recognized $7,886,000 in income from unconsolidated subsidiary for its ownership interest and received $8,926,000 of distributions from HPC from inception (March 18, 2009) to December 31, 2009. The summarized financial information of HPC for the period from inception (March 18, 2009) to December 31, 2009 is disclosed below.

RIGS Haynesville Partnership Co.

Condensed Consolidated Balance Sheet

December 31, 2009

(in thousands)

ASSETS
Total current assets	$	39,239
Restricted cash, non-current		33,595
Property, plant and equipment, net		861,570
Total other assets		149,755
TOTAL ASSETS	$	1,084,159
LIABILITIES & PARTNERS' CAPITAL
Total current liabilities	$	30,967
Partners' capital		1,053,192
TOTAL LIABILITIES & PARTNERS' CAPITAL	$	1,084,159

RIGS Haynesville Partnership Co.

Condensed Consolidated Income Statement

From Inception (March 18, 2009) to December 31, 2009

(in thousands)

Total revenues	$	43,483
Total operating costs and expenses		24,926
OPERATING INCOME		18,557
Interest expense		(158	)
Other income and deductions, net		1,335
NET INCOME	$	19,734

The HPC partnership agreement requires the distribution of 100 percent of “available cash” to the partners in accordance with their sharing ratios within 30 days after the end of each calendar quarter. Available cash is defined as cash on hand (excluding cash restricted for the Haynesville Expansion Project), less amounts reserved for normal operating expenses.

7. Derivative Instruments

Policies. The Partnership established comprehensive risk management policies and procedures to monitor and manage the market risks associated with commodity prices, counterparty credit, and interest rates. The General Partner is responsible for delegation of transaction authority levels, and the Risk Management Committee of the General Partner is responsible for the overall management of these risks, including monitoring exposure limits. The Risk Management Committee receives regular briefings on exposures and overall risk management in the context of market activities.

F-21

Commodity Price Risk. The Partnership is a net seller of NGLs, condensate and natural gas as a result of its gathering and processing operation. The prices of these commodities are impacted by changes in the supply and demand as well as market focus. Both the Partnership’s profitability and cash flow are affected by the inherent volatility of these commodities which could adversely affect its ability to make distributions to its unitholders. The Partnership manages this commodity price exposure through an integrated strategy that includes management of its contract portfolio, matching sales prices of commodities with purchases, optimization of its portfolio by monitoring basis and other price differentials in operating areas, and the use of derivative contracts. In some cases, the Partnership may not be able to match pricing terms or to cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk. It is the Partnership’s policy not to take any speculative positions with its derivative contracts.

The Partnership has executed swap contracts settled against NGLs (ethane, propane, butane, and natural gasoline), condensate and natural gas market prices for expected exposure in the approximate percentages set for below.

	As of December 31, 2009
	2010		2011
NGLs	80	%	33	%
Condensate	84	%	21	%
Natural gas	85	%	27	%

At December 31, 2009, the 2010 and 2011 natural gas and 2010 condensate swaps are accounted for as cash flow hedges; the 2011 condensate swaps are accounted for using mark-to-market accounting; and the 2010 and 2011 NGLs swaps are accounted for using a combination of cash flow hedge accounting and mark-to-market accounting.

Interest Rate Risk. The Partnership is exposed to variable interest rate risk as a result of borrowings under its credit facility. As of December 31, 2009, the Partnership had $419,642,000 of outstanding borrowings exposed to variable interest rate risk. In February 2008, the Partnership entered into two-year interest rate swaps related to $300,000,000 of borrowings under its credit facility, effectively locking the base rate for these borrowings at 2.4 percent, plus the applicable margin (3.0 percent as of December 31, 2009) through March 5, 2010. These interest rate swaps were designated as cash flow hedges.

Credit Risk. The Partnership’s resale of natural gas exposes it to credit risk, as the margin on any sale is generally a very small percentage of the total sales price. Therefore, a credit loss can be very large relative to overall profitability on these transactions. The Partnership attempts to ensure that it issues credit only to credit-worthy counterparties and that in appropriate circumstances any such extension of credit is backed by adequate collateral such as a letter of credit or a guarantee from a parent company with potentially better credit.

The Partnership is exposed to credit risk from its derivative counterparties. The Partnership does not require collateral from these counterparties. The Partnership deals primarily with financial institutions when entering into financial derivatives. The Partnership has entered into Master International Swap Dealers Association (“ISDA”) Agreements that allow for netting of swap contract receivables and payables in the event of default by either party. If the Partnership's counterparties failed to perform under existing swap contracts, the Partnership's maximum loss is $25,246,000, which would be reduced by $13,284,000 due to the netting feature. The Partnership has elected to present assets and liabilities under Master ISDA Agreements gross on the consolidated balance sheets.

Embedded Derivatives. The Series A Preferred Units contain embedded derivatives which are required to be bifurcated and accounted for separately, such as the holders’ conversion option and the Partnership’s call option. These embedded derivatives are accounted for using mark-to-market accounting. Changes in the fair value are recorded in other income and deductions, net within the consolidated statement of operations. The Partnership

F-22

does not expect the embedded derivatives to affect its cash flows. During the year ended December 31, 2009, the loss recognized related to these embedded derivatives was $15,686,000 and is reflected in other income and deductions, net on the consolidated statement of operations.

Quantitative Disclosures. The Partnership expects to reclassify $1,271,000 of net hedging losses to revenue or interest expense from accumulated other comprehensive income in the next 12 months.

The Partnership’s derivative assets and liabilities, including credit risk adjustment, for the years ending December 31, 2009 and 2008 are detailed below.

	Assets						Liabilities
	December 31, 2009			December 31, 2008			December 31, 2009			December 31, 2008
	(in thousands)
Derivatives designated as cash flow hedges
Current amounts
Interest rate contracts	$	—		$	—		$	1,067		$	4,680
Commodity contracts		9,525			59,882			11,200			—
Long-term amounts
Interest rate contracts		—			—			—			560
Commodity contracts		207			13,373			931			—
Total cash flow hedging instruments		9,732			73,255			13,198			5,240
Derivatives not designated as cash flow hedges
Current amounts
Commodity contracts		15,514			16,001			31			38,402
Long-term amounts
Commodity contracts		—			23,425			3,378			—
Embedded derivatives in Series A Preferred Units		—			—			44,594			—
Total derivatives not designated as cash flow hedges		15,514			39,426			48,003			38,402
Credit Risk Assessment
Current amounts		(52	)		(1,890	)		(42	)		(391	)
Total derivatives	$	25,194		$	110,791		$	61,159		$	43,251

Derivatives designated as cash flow hedges

	Year Ended December 31, 2009									Year Ended December 31, 2008
	Interest Rate			Commodity			Total			Interest Rate			Commodity			Total
	(in thousands)
Gain (loss) recorded in accumulated OCI (Effective)	$	(2,082	)	$	(19,958	)	$	(22,040	)	$	(4,555	)	$	74,808		$	70,253
Gain (loss) reclassified from accumulated OCI into income (Effective)*		(6,255	)		54,260			48,005			676			(35,942	)		(35,266	)
Gain (loss) recognized in income (Ineffective)*		—			108			108			—			543			543

F-23

Derivatives not designated as cash flow hedges

	Year Ended December 31, 2009									Year Ended December 31, 2008
	Embedded Derivatives			Commodity			Total			Embedded Derivatives		Commodity			Total
	(in thousands)
Loss from dedesignation amortized from accumulated OCI into income*	$	—		$	(611	)	$	(611	)	$	—	$	(246	)	$	(246	)
(Loss) gain recognized in income*		(15,686	)		(13,669	)		(29,355	)		—		15,911			15,911

Credit risk assessment for commodity and interest rate swaps

	Year Ended December 31,
	2009		2008			2007
	(in thousands)
Gain (loss) recognized in income*	$	1,489	$	(1,499	)	$	—

* Gain and loss related to commodity swaps, interest swaps and embedded derivatives were included in revenue, interest expense, and other income and deductions, net, respectively, in the Partnership’s consolidated statements of operations.

8. Long-term Debt

Obligations in the form of senior notes and borrowings under the credit facilities are as follows.

	December 31, 2009			December 31, 2008
	(in thousands)
Senior notes	$	594,657		$	357,500
Revolving loans		419,642			768,729
Total		1,014,299			1,126,229
Less: current portion		—			—
Long-term debt	$	1,014,299		$	1,126,229
Availability under revolving credit facility:
Total credit facility limit	$	900,000		$	900,000
Unfunded Lehman commitments		(10,675	)		(8,646	)
Revolving loans		(419,642	)		(768,729	)
Letters of credit		(16,257	)		(16,257	)
Total available	$	453,426		$	106,368

Long-term debt maturities as of December 31, 2009 for each of the next five years are as follows.

Year Ended December 31,	Amount
	(in thousands)
2010	$	—
2011		419,642
2012		—
2013		357,500
2014		—
Thereafter		250,000	*
Total	$	1,027,142

* As of December 31, 2009, the carrying value of the senior notes due 2016 was $237,157,000 which included an unamortized discount of $12,843,000.

F-24

In the year ended December 31, 2009, the Partnership borrowed $191,693,000 under its credit facility; these borrowings were primarily to fund capital expenditures. During the same period, the Partnership repaid $540,780,000 with proceeds from an equity offering and issuance of senior notes due 2016. In the years ended December 31, 2008 and 2007, the Partnership borrowed $844,729,000 and $283,230,000, respectively; these funds were used primarily to finance capital expenditures. During the same periods, the Partnership repaid $200,000,000 and $421,430,000, respectively, of these borrowings with proceeds from equity offerings.

Senior Notes due 2016. In May 2009, the Partnership and Finance Corp. issued $250,000,000 of senior notes in a private placement that mature on June 1, 2016. The senior notes bear interest at 9.375 percent with interest payable semi-annually in arrears on June 1 and December 1. The Partnership paid a $13,760,000 discount upon issuance. The net proceeds were used to partially repay revolving loans under the Partnership’s credit facility.

At any time before June 1, 2012, up to 35 percent of the senior notes can be redeemed at a price of 109.375 percent plus accrued interest. Beginning June 1, 2013, the Partnership may redeem all or part of these notes for the principal amount plus a declining premium until June 1, 2015, and thereafter at par, plus accrued and unpaid interest. At any time prior to June 1, 2013, the Partnership may also redeem all or part of the notes at a price equal to 100 percent of the principal amount of notes redeemed plus accrued interest and the applicable premium, which equals to the greater of (1) one percent of the principal amount of the note; or (2) the excess of the present value at such redemption date of (i) the redemption price of the note at June 1, 2013 plus (ii) all required interest payments due on the note through June 1, 2013, computed using a discount rate equal to the treasury rate (as defined) as of such redemption date plus 50 basis points over the principal amount of the note.

Upon a change of control, each noteholder will be entitled to require the Partnership to purchase all or a portion of its notes at a purchase price of 101 percent plus accrued interest and liquidated damages, if any. The Partnership’s ability to purchase the notes upon a change of control will be limited by the terms of its debt agreements, including its credit facility.

The senior notes contain various covenants that limit, among other things, the Partnership’s ability, and the ability of certain of its subsidiaries, to:

• incur additional indebtedness;

• pay distributions on, or repurchase or redeem equity interests;

• make certain investments;

• incur liens;

• enter into certain types of transactions with affiliates; and

• sell assets, consolidate or merge with or into other companies.

If the senior notes achieve investment grade ratings by both Moody’s and S&P and no default or event of default has occurred and is continuing, the Partnership will no longer be subject to many of the foregoing covenants. At December 31, 2009, the Partnership was in compliance with these covenants.

The senior notes are jointly and severally guaranteed by all of the Partnership’s current consolidated subsidiaries, other than Finance Corp., and by certain of its future subsidiaries. The senior notes and the guarantees are unsecured and rank equally with all of the Partnership’s and the guarantors’ existing and future unsubordinated obligations. The senior notes and the guarantees will be senior in right of payment to any of the Partnership’s and the guarantors’ future obligations that are, by their terms, expressly subordinated in right of payment to the notes and the guarantees. The senior notes and the guarantees will be effectively subordinated to the Partnership’s and the guarantors’ secured obligations, including the Partnership’s credit facility, to the extent of the value of the assets securing such obligations.

F-25

Senior Notes due 2013. In 2006, the Partnership and Finance Corp. issued $550,000,000 senior notes that mature on December 15, 2013 in a private placement. The senior notes bear interest at 8.375 percent and interest is payable semi-annually in arrears on each June 15 and December 15. In August 2007, the Partnership exercised its option to redeem 35 percent or $192,500,000 of these senior notes at a price of 108.375 percent of the principal amount plus accrued interest. Accordingly, a redemption premium of $16,122,000 and a loss on debt refinancing and unamortized loan origination costs of $4,575,000 were charged to loss on debt refinancing in the year ended December 31, 2007. Under the senior notes terms, no further redemptions are permitted until December 15, 2010.

The Partnership may redeem the outstanding senior notes, in whole or in part, at any time on or after December 15, 2010, at a redemption price equal to 100 percent of the principal amount thereof, plus a premium declining ratably to par and accrued and unpaid interest and liquidated damages, if any, to the redemption date.

Upon a change of control, each noteholder will be entitled to require the Partnership to purchase all or a portion of its notes at a purchase price of 101 percent plus accrued interest and liquidated damages, if any. The Partnership’s ability to purchase the notes upon a change of control will be limited by the terms of its debt agreements, including its credit facility.

The senior notes contain various covenants that limit, among other things, the Partnership’s ability, and the ability of certain of its subsidiaries, to:

• incur additional indebtedness;

• pay distributions on, or repurchase or redeem equity interests;

• make certain investments;

• incur liens;

• enter into certain types of transactions with affiliates; and

• sell assets, consolidate or merge with or into other companies.

If the senior notes achieve investment grade ratings by both Moody’s and S&P and no default or event of default has occurred and is continuing, the Partnership will no longer be subject to many of the foregoing covenants. At December 31, 2009, the Partnership was in compliance with these covenants.

The senior notes are jointly and severally guaranteed by all of the Partnership’s current consolidated subsidiaries, other than Finance Corp., and by certain of its future subsidiaries. The senior notes and the guarantees are unsecured and rank equally with all of the Partnership’s and the guarantors’ existing and future unsubordinated obligations. The senior notes and the guarantees will be senior in right of payment to any of the Partnership’s and the guarantors’ future obligations that are, by their terms, expressly subordinated in right of payment to the notes and the guarantees. The senior notes and the guarantees will be effectively subordinated to the Partnership’s and the guarantors’ secured obligations, including the Partnership’s credit facility, to the extent of the value of the assets securing such obligations.

Finance Corp. has no operations and will not have revenue other than as may be incidental as co-issuer of the senior notes. Since the Partnership has no independent operations, the guarantees are fully unconditional and joint and several of its subsidiaries, except certain wholly owned subsidiaries, the Partnership has not included condensed consolidated financial information of guarantors of the senior notes.

GECC Credit Facility. On February 26, 2009, the Partnership entered into a $45,000,000 unsecured revolving credit agreement with GECC. The proceeds of the GECC Credit Facility were available for

F-26

expenditures made in connection with the Haynesville Expansion Project prior to the effectiveness of the March 17, 2009 amendment discussed below. The commitments under the GECC Credit Facility terminated on March 17, 2009. The Partnership paid a commitment fee of $2,718,000 to GECC related to this GECC Credit Facility, which was recorded as a decrease to gain on asset sales, net.

Fourth Amended and Restated Credit Agreement. In February 2008, RGS’ Fourth Amended and Restated Credit Agreement was expanded to $900,000,000 and the availability for letters of credit was increased to $100,000,000. The Partnership also has the option to request an additional $250,000,000 in revolving commitments with ten business days written notice provided that no event of default has occurred or would result due to such increase, and all other additional conditions for the increase of the commitments set forth in the credit facility have been met. The maturity date of the Credit Facility is August 15, 2011.

Effective March 17, 2009, RGS amended the credit facility to authorize the contribution of RIG to HPC and allow for a future investment of up to $135,000,000 in HPC. The amendment imposed additional financial restrictions that limit the ratio of senior secured indebtedness to EBITDA. The alternate base rate used to calculate interest on base rate loans will be calculated based on the greatest to occur of a base rate, a federal funds effective rate plus 0.50 percent and an adjusted one-month LIBOR rate plus 1.50 percent. The applicable margin shall range from 1.50 percent to 2.25 percent for base rate loans, 2.50 percent to 3.25 percent for Eurodollar loans, and a commitment fee will range from 0.375 to 0.500 percent. On July 24, 2009, RGS further amended its credit facility to allow for a $25,000,000 working capital facility for RIG. These amendments did not materially change other terms of the RGS revolving credit facility.

On September 15, 2008, Lehman filed a petition in the United States Bankruptcy Court seeking relief under Chapter 11 of the United States Bankruptcy Code. As a result, a subsidiary of Lehman that is a committed lender under the Partnership’s credit facility has declined requests to honor its commitment to lend. The total amount committed by Lehman was $20,000,000 and as of December 31, 2009, the Partnership had borrowed all but $10,675,000 of that amount. Since Lehman has declined requests to honor its remaining commitment, the Partnership’s total size of the credit facility’s capacity has been reduced from $900,000,000 to $889,325,000. Further, if the Partnership makes repayments of loans against the credit facility which were, in part, funded by Lehman, the amounts funded by Lehman may not be reborrowed.

The outstanding balance of revolving loans under the credit facility bears interest at LIBOR plus a margin or Alternative Base Rate (equivalent to the U.S. prime lending rate) plus a margin, or a combination of both. The weighted average interest rates for the revolving loans and senior notes, including interest rate swap settlements, commitment fees, and amortization of debt issuance costs were 6.69 percent, 6.27 percent, and 8.78 percent for the years ended December 31, 2009, 2008, and 2007, respectively. The senior notes pay fixed interest rates and the weighted average rate is 8.787 percent.

RGS must pay (i) a commitment fee equal to 0.50 percent per annum of the unused portion of the revolving loan commitments, (ii) a participation fee for each revolving lender participating in letters of credit equal to 3.0 percent per annum of the average daily amount of such lender’s letter of credit exposure, and (iii) a fronting fee to the issuing bank of letters of credit equal to 0.125 percent per annum of the average daily amount of the letter of credit exposure.

The credit facility contains financial covenants requiring RGS and its subsidiaries to maintain debt to adjusted EBITDA (as defined in the credit agreement) ratio less than 5.25, and adjusted EBITDA to interest expense ratio greater than 2.75 times. At December 31, 2009 and 2008, RGS and its subsidiaries were in compliance with these covenants.

The credit facility restricts the ability of RGS to pay dividends and distributions other than reimbursements of the Partnership for expenses and payment of dividends to the Partnership to the extent of the Partnership’s determination of available cash (so long as no default or event of default has occurred or is continuing). The

F-27

credit facility also contains various covenants that limit (subject to certain exceptions and negotiated baskets), among other things, the ability of RGS to:

• incur indebtedness;

• grant liens;

• enter into sale and leaseback transactions;

• make certain investments, loans and advances;

• dissolve or enter into a merger or consolidation;

• enter into asset sales or make acquisitions;

• enter into transactions with affiliates;

• prepay other indebtedness or amend organizational documents or transaction documents (as defined in the credit facility);

• issue capital stock or create subsidiaries; or

• engage in any business other than those businesses in which it was engaged at the time of the effectiveness of the credit facility or reasonable extensions thereof.

9. Other Assets

Intangible assets, net. Intangible assets, net consist of the following.

	Permits and Licenses			Contracts			Trade Names			Customer Relations			Total
	(in thousands)
Balance at January 1, 2008	$	9,368		$	68,436		$	—		$	—		$	77,804
Additions		—			64,770			35,100			41,710			141,580
Amortization		(786	)		(6,407	)		(2,252	)		(4,293	)		(13,738	)
Balance at December 31, 2008		8,582			126,799			32,848			37,417			205,646
Disposals		(2,921	)		—			—			—			(2,921	)
Other		—			7,000			—			—			7,000
Amortization		(569	)		(7,467	)		(2,340	)		(2,055	)		(12,431	)
Balance at December 31, 2009	$	5,092		$	126,332		$	30,508		$	35,362		$	197,294

The average remaining amortization periods for permits and licenses, contracts, trade names, and customer relations are 10, 16, 13 and 18 years, respectively. The expected amortization of the intangible assets for each of the five succeeding years is as follows.

Year ending December 31,	Total
	(in thousands)
2010	$	12,553
2011		11,244
2012		11,002
2013		11,002
2014		11,002

F-28

Goodwill. Goodwill activity consists of the following.

	Gathering and Processing		Transportation			Contract Compression		Total
	(in thousands)
Balance at January 1, 2008	$	59,831	$	34,244		$	—	$	94,075
Additions		3,401		—			164,882		168,283
Balance at December 31, 2008		63,232		34,244			164,882		262,358
Disposals		—		(34,244	)		—		(34,244	)
Balance at December 31, 2009	$	63,232	$	—		$	164,882	$	228,114

On March 17, 2009, the Partnership contributed all assets of RIG, which owns the Regency Intrastate Gas System, to HPC, in exchange for an interest in HPC. As a result, goodwill associated with the transportation segment was removed from the balance sheet.

10. Fair Value Measures

On January 1, 2008, the Partnership adopted the fair value measurement provisions for financial assets and liabilities and on January 1, 2009, the Partnership applied the fair value measurement provisions to non-financial assets and liabilities, such as goodwill, indefinite-lived intangible assets, property, plant and equipment and asset retirement obligations. These provisions establish a three-tiered fair value hierarchy that prioritizes inputs to valuation techniques used in fair value calculations. The three levels of inputs are defined as follows:

• Level 1—unadjusted quoted prices for identical assets or liabilities in active accessible markets;

• Level 2—inputs that are observable in the marketplace other than those classified as Level 1; and

• Level 3—inputs that are unobservable in the marketplace and significant to the valuation.

Entities are encouraged to maximize the use of observable inputs and minimize the use of unobservable inputs. If a financial instrument uses inputs that fall in different levels of the hierarchy, the instrument will be categorized based upon the lowest level of input that is significant to the fair value calculation.

Derivatives. The Partnership’s financial assets and liabilities measured at fair value on a recurring basis are derivatives related to interest rate and commodity swaps and embedded derivatives in the Series A Preferred Units. Derivatives related to interest rate and commodity swaps are valued using discounted cash flow techniques. These techniques incorporate Level 1 and Level 2 inputs such as future interest rates and commodity prices. These market inputs are utilized in the discounted cash flow calculation considering the instrument’s term, notional amount, discount rate and credit risk and are classified as Level 2 in the hierarchy. Derivatives related to Series A Preferred Units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected volatility, and are classified as Level 3 in the hierarchy. The change in fair value of the derivatives related to Series A Preferred Units is recorded in other income and deductions, net within the statement of operations.

The following table presents the Partnership’s derivative assets and liabilities measured at fair value on a recurring basis.

	December 31, 2009				December 31, 2008
	Assets		Liabilities		Assets		Liabilities
	(in thousands)
Level 1	$	—	$	—	$	—	$	—
Level 2		25,194		16,565		110,791		43,251
Level 3		—		44,594		—		—
Total	$	25,194	$	61,159	$	110,791	$	43,251

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The following table presents the changes in Level 3 derivatives measured on a recurring basis for the year ended December 31, 2009. There were no Level 3 derivatives for the years ended December 31, 2008 or 2007.

	Derivatives related to Series A Preferred Units
	For the Year Ended December 31, 2009
	(in thousands)
Beginning Balance	$	—
Issuance		28,908
Net unrealized losses included in other income and deductions, net		15,686
Ending Balance	$	44,594

The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to their short-term maturities. Restricted cash and related escrow payable approximates fair value due to the relatively short-term settlement period of the escrow payable. Long-term debt, other than the senior notes, is comprised of borrowings under which, interest accrues under a floating interest rate structure. Accordingly, the carrying value approximates fair value. The estimated fair value of the senior notes due 2013 based on third party market value quotations as of December 31, 2009 and 2008 was $364,650,000 and $244,888,000, respectively. The estimated fair value of the senior notes due 2016 based on third party market value quotations as of December 31, 2009 was $265,625,000.

11. Leases

The Partnership leases office space and certain equipment and the following table is a schedule of future minimum lease payments for leases that had initial or remaining noncancelable lease terms in excess of one year as of December 31, 2009.

For the year ending December 31,	Operating		Capital
	(in thousands)
2010	$	3,838	$	589
2011		3,801		422
2012		3,426		436
2013		2,714		448
2014		2,351		462
Thereafter		9,975		7,101
Total minimum lease payments	$	26,105	$	9,458
Less: Amount representing estimated executory costs (such as maintenance and insurance), including profit thereon, included in minimum lease payments				1,890
Net minimum lease payments				7,568
Less: Amount representing interest				4,365
Present value of net minimum lease payments			$	3,203

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The following table sets forth the Partnership’s assets and obligations under the capital lease which are included in other current and long-term liabilities on the consolidated balance sheet.

	December 31, 2009
	(in thousands)
Gross amount included in gathering and transmission systems	$	3,000
Gross amount included in other property, plant and equipment		560
Less accumulated depreciation		(755	)
	$	2,805
Current obligation under capital lease		529
Non-current obligation under capital lease		2,674
	$	3,203

Total rent expense for operating leases, including those leases with terms of less than one year, was $5,465,000, $2,576,000, and $1,597,000, for the years ended December 31, 2009, 2008, and 2007, respectively.

12. Commitments and Contingencies

Legal. The Partnership is involved in various claims and lawsuits incidental to its business. These claims and lawsuits in the aggregate are not expected to have a material adverse effect on the Partnership’s business, financial condition, results of operations or cash flows.

Escrow Payable. At December 31, 2009, $1,511,000 remained in escrow pending the completion by El Paso of environmental remediation projects pursuant to the purchase and sale agreement (“El Paso PSA”) related to assets in north Louisiana and the mid-continent area and a subsequent 2008 settlement agreement between the Partnership and El Paso. In the El Paso PSA, El Paso indemnified Regency Gas Services LLC, now known as Regency Gas Services LP, against losses arising from pre-closing and known environmental liabilities subject to a limit of $84,000,000 and certain deductible limits. Upon completion of a Phase II environmental study, the Partnership notified El Paso of remediation obligations amounting to $1,800,000 with respect to known environmental matters and $3,600,000 with respect to pre-closing environmental liabilities. This escrow amount will be further reduced under a specified schedule as El Paso completes its cleanup obligations and the remainder will be released upon completion.

Environmental. A Phase I environmental study was performed on certain assets located in west Texas in connection with the pre-acquisition due diligence process in 2004. Most of the identified environmental contamination had either been remediated or was being remediated by the previous owners or operators of the properties. The aggregate potential environmental remediation costs at specific locations were estimated to range from $1,900,000 to $3,100,000. No governmental agency has required the Partnership to undertake these remediation efforts. Management believes that the likelihood that it will be liable for any significant potential remediation liabilities identified in the study is remote. Separately, the Partnership acquired an environmental pollution liability insurance policy in connection with the acquisition to cover any undetected or unknown pollution discovered in the future. The policy covers clean-up costs and damages to third parties, and has a 10-year term (expiring 2014) with a $10,000,000 limit subject to certain deductibles. No claims have been made against the Partnership or under the policy.

TCEQ Notice of Enforcement. In February 2008, the TCEQ issued a Notice of Enforcement (“NOE”) concerning one of the Partnership’s processing plants located in McMullen County, Texas. The NOE alleged that, between March 9, 2006, and May 8, 2007, this plant experienced 15 emission events of various durations from four hours to 41 days, which were not reported to TCEQ and other agencies within 24 hours of occurrence. In January 2010, the TCEQ notified the Partnership in writing that it had concluded that there had been no violation and that the TCEQ would take no further action.

F-31

Keyes Litigation. In August 2008, Keyes Helium Company, LLC (“Keyes”) filed suit against Regency Gas Services LP, the Partnership, the General Partner and various other subsidiaries. Keyes entered into an output contract with the Partnership’s predecessor-in-interest in 1996 under which it purchased all of the helium produced at the Lakin, Kansas processing plant. In September 2004, the Partnership decided to shut down its Lakin plant and contract with a third party for the processing of volumes processed at Lakin; as a result, the Partnership no longer delivered any helium to Keyes. In its suit, Keyes alleges it is entitled to damages for the costs of covering its purchases of helium. Discovery ended in October 2009. A hearing on cross-motions for summary judgment took place in December 2009. A decision is expected in the first quarter of 2010. If the Partnership does not win its motion, a jury trial is scheduled for April 2010.

Kansas State Severance Tax. In August 2008, a customer began remitting severance tax to the state of Kansas based on the value of condensate purchased from one of the Partnership’s Mid-Continent gathering fields and deducting the tax from its payments to the Partnership. The Kansas Department of Revenue advised the customer that it was appropriate to remit such taxes and withhold the taxes from its payments to the Partnership, absent an order or legal opinion from the Kansas Department of Revenue stating otherwise. The Partnership has requested a determination from the Kansas Department of Revenue regarding the matter since severance taxes were already paid on the gas from which the condensate is collected and no additional tax is due. The Kansas Department of Revenue has initiated an audit of the Partnership’s condensate sales in Kansas. If the Kansas Department of Revenue determines that the condensate sales are taxable, then the Partnership may be subject to additional taxes, interest and possible penalties for past and future condensate sales.

Caddo Gas Gathering LLC v. Regency Intrastate Gas LLC. Regency Intrastate Gas LLC was a defendant in a lawsuit filed by Caddo Gas Gathering LLC (“Caddo Gas”). In February 2010, the dispute was resolved and the lawsuit dismissed with prejudice without material expense.

Remediation of Groundwater Contamination at Calhoun and Dubach Plants. Regency Field Services LLC (“RFS”) currently owns the Dubach and Calhoun gas processing plants in north Louisiana (the “Plants”). The Plants each have a groundwater contamination as result of historical operations. At the time that RFS acquired the Plants from El Paso, Kerr-McGee Corporation (“Kerr-McGee”) was performing remediation of the groundwater contamination, because the Plants were once owned by Kerr-McGee and when Kerr-McGee sold the Plants to a predecessor of El Paso in 1988, Kerr-McGee retained liability for any environmental contamination at the Plants. In 2005, Kerr-McGee created and spun off Tronox and Tronox allegedly assumed certain of Kerr-McGee’s environmental remediation obligations (including its obligation to perform remediation at the Plants) prior to the acquisition of Kerr-McGee by Anadarko Petroleum Corporation. In January 2009, Tronox filed for Chapter 11 bankruptcy protection. RFS filed a claim in the bankruptcy proceeding relating to the environmental remediation work at the Plants. Tronox has thus far continued its remediation efforts at the Plants.

13. Series A Convertible Redeemable Preferred Units

On September 2, 2009, the Partnership issued 4,371,586 Series A Preferred Units at a price of $18.30 per unit, less a four percent discount of $3,200,000 and issuance costs of $176,000 for net proceeds of $76,624,000, exclusive of the General Partner’s contribution of $1,633,000. The Series A Preferred Units are convertible to common units under terms described below, and if outstanding, are mandatorily redeemable on September 2, 2029 for $80,000,000 plus all accrued but unpaid distributions thereon (the “Series A Liquidation Value”). The Series A Preferred Units will receive fixed quarterly cash distributions of $0.445 per unit beginning with the quarter ending March 31, 2010.

Distributions on the Series A Preferred Units will be accrued for the first two quarters (and not paid in cash) and will result in an increase in the number of common units issuable upon conversion. For the year ended December 31, 2009, total accrued distributions per unit was $0.89. If on any distribution payment date beginning March 31, 2010, the Partnership (1) fails to pay distributions on the Series A Preferred Units, (2) reduces the distributions on the common units to zero and (3) is prohibited by its material financing agreements from paying

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cash distributions, such distributions shall automatically accrue and accumulate until paid in cash. If the Partnership has failed to pay cash distributions in full for two quarters (whether or not consecutive) from and including the quarter ending on March 31, 2010, then if the Partnership fails to pay cash distributions on the Series A Preferred Units, all future distributions on the Series A Preferred Units that are accrued rather than being paid in cash by the Partnership will consist of the following: (1) $0.35375 per Series A Preferred Unit per quarter, (2) $0.09125 per Series A Preferred Unit per quarter (the “Common Unit Distribution Amount”), payable solely in common units, and (3) $0.09125 per Series A Preferred Unit per quarter (the “PIK Distribution Additional Amount”), payable solely in common units. The total number of common units payable in connection with the Common Unit Distribution Amount or the PIK Distribution Additional Amount cannot exceed 1,600,000 in any period of 20 consecutive fiscal quarters.

Upon the Partnership’s breach of certain covenants (a “Covenant Default”), the holders of the Series A Preferred Units will be entitled to an increase of $0.1825 per quarterly distribution, payable solely in common units (the “Covenant Default Additional Amount”). All accumulated and unpaid distributions will accrue interest (i) at a rate of 2.432 percent per quarter, or (ii) if the Partnership has failed to pay all PIK Distribution Additional Amounts or Covenant Default Additional Amounts or any Covenant Default has occurred and is continuing, at a rate of 3.429 percent per quarter while such failure to pay or such Covenant Default continues.

The Series A Preferred Units are convertible, at the holder’s option, into common units commencing on March 2, 2010, provided that the holder must request conversion of at least 375,000 Series A Preferred Units. The conversion price will initially be $18.30, subject to adjustment for customary events (such as unit splits) and until December 31, 2011, based on a weighted average formula in the event the Partnership issues any common units (or securities convertible or exercisable into common units) at a per common unit price below $16.47 per common unit (subject to typical exceptions). The number of common units issuable is equal to the issue price of the Series A Preferred Units (i.e. $18.30) being converted plus all accrued but unpaid distributions and accrued but unpaid interest thereon (the “Redeemable Face Amount”), divided by the applicable conversion price.

Commencing on September 2, 2014, if at any time the volume-weighted average trading price of the common units over the trailing 20-trading day period (the “VWAP Price”) is less than the then-applicable conversion price, the conversion ratio will be increased to: the quotient of (1) the Redeemable Face Amount on the date that the holder’s conversion notice is delivered, divided by (2) the product of (x) the VWAP Price set forth in the applicable conversion notice and (y) 91 percent, but will not be less than $10.

Also commencing on September 2, 2014, the Partnership will have the right at any time to convert all or part of the Series A Preferred Units into common units, if (1) the daily volume-weighted average trading price of the common units is greater than 150 percent of the then-applicable conversion price for twenty (20) out of the trailing thirty (30) trading days, and (2) certain minimum public float and trading volume requirements are satisfied.

In the event of a change of control, the Partnership will be required to make an offer to the holders of the Series A Preferred Units to purchase their Series A Preferred Units for an amount equal to 101 percent of their Series A Liquidation Value. In addition, in the event of certain business combinations or other transactions involving the Partnership in which the holders of common units receive cash consideration exclusively in exchange for their common units (a “Cash Event”), the Partnership must use commercially reasonable efforts to ensure that the holders of the Series A Preferred Units will be entitled to receive a security issued by the surviving entity in the Cash Event with comparable powers, preferences and rights to the Series A Preferred Units. If the Partnership is unable to ensure that the holders of the Series A Preferred Units will be entitled to receive such a security, then the Partnership will be required to make an offer to the holders of the Series A Preferred Units to purchase their Series A Preferred Units for an amount equal to 120 percent of their Series A Liquidation Value. If the Partnership enters into any recapitalization, reorganization, consolidation, merger, spin-off that is not a Cash Event, the Partnership will make appropriate provisions to ensure that the holders of the Series A Preferred Units receive a security with comparable powers, preferences and rights to the Series A Preferred Units upon consummation of such transaction.

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As of December 31, 2009, accrued distributions of $3,891,000 have been added to the value of the Series A Preferred Units and increases the number of common units to 4,584,192 that may be issued upon conversion. Holders may elect to convert Series A Preferred Units to common units beginning on March 2, 2010.

Net proceeds from the issuance of Series A Preferred Units on September 2, 2009 was $76,624,000, of which $28,908,000 was allocated to the initial fair value of the embedded derivatives and recorded into long-term derivative liabilities on the balance sheet. The remaining $47,716,000 represented the initial value of the Series A Preferred Units and will be accreted to $80,000,000 by deducting the accretion amounts from partners’ capital over 20 years.

The following table provides a reconciliation of the beginning and ending balances of the Series A Preferred Units for all income statement periods presented.

	Units	Amount (in thousands)
Beginning balance as of January 1, 2009	—	$	—
Original issuance, net of discount of $3,200	4,371,586		76,624
Amount reclassed to long-term derivative liabilities	—		(28,908	)
Accrued distributions	—		3,891
Accretion to redemption value	—		104
Ending balance as of December 31, 2009	4,371,586	$	51,711

14. Related Party Transactions

In September 2008, HM Capital Partners and affiliates sold 7,100,000 common units for total consideration of $149,100,000, reducing their ownership percentage to an amount less than ten percent of the Partnership’s outstanding common units. As a result of this sale, HM Capital Partners is no longer a related party of the Partnership. During the years ended December 31, 2008 and 2007, HM Capital Partners and affiliates received cash disbursements, in conjunction with distributions by the Partnership for limited and general partner interests, of $10,308,000 and $24,392,000, respectively.

The employees operating the assets of the Partnership and its subsidiaries and all those providing staff or support services are employees of the General Partner. Pursuant to the Partnership Agreement, the General Partner receives a monthly reimbursement for all direct and indirect expenses incurred on behalf of the Partnership. Reimbursements of $33,834,000, $26,899,000, and $27,628,000, were recorded in the Partnership’s financial statements during the years ended December 31, 2009, 2008, and 2007, respectively, as operating expenses or general and administrative expenses, as appropriate.

Concurrent with the GE EFS acquisition, eight members of the Partnership’s senior management, together with two independent directors, entered into an agreement to sell an aggregate of 1,344,551 subordinated units for a total consideration of $24.00 per unit. Additionally, GE EFS entered into a subscription agreement with four officers and certain other management of the Partnership whereby these individuals acquired an 8.2 percent indirect economic interest in the General Partner.

GE EFS and certain members of the Partnership’s management made capital contributions aggregating to $6,344,000, $11,746,000 and $7,735,000 to maintain the General Partner’s two percent interest in the Partnership for the years ended December 31, 2009, 2008, and 2007, respectively.

In conjunction with distributions by the Partnership to its limited and general partner interests, GE EFS received cash distributions of $51,226,000, $35,054,000, and $14,592,000 during the years ended December 31, 2009, 2008 and 2007, respectively.

F-34

As part of the August 1, 2008 common units offering, an affiliate of GECC purchased 2,272,727 common units for total consideration of $50,000,000.

The Partnership’s contract compression segment provided contract compression services to CDM MAX LLC (“CDM MAX”). In 2009, CDM MAX was purchased by a third party and, as a result, CDM MAX is no longer a related party. The Partnership’s related party revenue associated with CDM MAX was $1,101,000 and $3,712,000 during the years ended December 31, 2009 and 2008, respectively.

Under a Master Services Agreement with HPC, the Partnership operates and provides all employees and services for the operation and management of HPC. Under this agreement the Partnership received $500,000 monthly as a partial reimbursement of its general and administrative costs. The Partnership also incurs expenditures on behalf of HPC and these amounts are billed to HPC on a monthly basis. For the period from March 18, 2009 to December 31, 2009, the related party general and administrative expenses reimbursed to the Partnership were $4,726,000. On December 18, 2009, the reimbursement amount was amended to $1,400,000 per month effective on the first calendar day in the month subsequent to mechanical completion of the expansion of the Regency Intrastate Gas System (February 1, 2010), subject to an annual escalation beginning March 1, 2011. The amount is recorded as fee revenue in the Partnership’s corporate and other segment. Additionally, the Partnership’s contract compression segment provides contract compression services to HPC. On the other hand, HPC provides transportation service to the Partnership.

Upon the formation of HPC in March 2009, the Partnership was reimbursed by HPC for construction-in-progress incurred prior to formation of HPC at the cost of $80,608,000. Subsequently, the Partnership sold an additional $7,984,000 of compression equipment to HPC.

The Partnership’s related party receivables and related party payables as of December 31, 2009 relate to HPC. The Partnership’s related party receivables and related party payables as of December 31, 2008 related to CDM MAX.

As disclosed in Note 1 and in Note 5, the Partnership’s acquisition of FrontStreet and contribution of RIGS to HPC are related party transactions.

15. Concentration Risk

The following table provides information about the extent of reliance on major customers and gas suppliers. Total revenues and cost of sales from transactions with an external customer or supplier amounting to ten percent or more of revenue or cost of gas and liquids are disclosed below, together with the identity of the reporting segment.

		Year Ended
	Reportable Segment	December 31, 2009		December 31, 2008		December 31, 2007
		(in thousands)
Customer
Customer A	Gathering and Processing	$	123,524		*		*
Supplier
Supplier A	Transportation	$	14,053	$	75,464	$	17,930
Supplier A	Gathering and Processing		143,435		243,075		139,116

* Amounts are less than ten percent of the total revenue or cost of sales.

The Partnership is a party to various commercial netting agreements that allow it and contractual counterparties to net receivable and payable obligations. These agreements are customary and the terms follow standard industry practice. In the opinion of management, these agreements reduce the overall counterparty risk exposure.

F-35

16. Segment Information

In 2009, the Partnership’s management realigned the composition of its segments. Accordingly, the Partnership has restated the items of segment information for earlier periods to reflect this new alignment.

The Partnership has four reportable segments: (a) gathering and processing, (b) transportation, (c) contract compression and (d) corporate and others. Gathering and processing involves collecting raw natural gas from producer wells and transporting it to treating plants where water and other impurities such as hydrogen sulfide and carbon dioxide are removed. Treated gas is then processed to remove the natural gas liquids. The treated and processed natural gas is then transported to market separately from the natural gas liquids. Revenue and the associated cost of sales from the gathering and processing segment directly expose the Partnership to commodity price risk, which is managed through derivative contracts and other measures. The Partnership aggregates the results of its gathering and processing activities across five geographic regions into a single reporting segment. The Partnership, through its producer services function, primarily purchases natural gas from producers at gathering systems and plants connected to its pipeline systems and sells this gas at downstream outlets.

Following the initial contribution of RIG to HPC in March 2009, as well as the subsequent acquisition of an additional five percent interest in HPC, the transportation segment consists exclusively of the Partnership’s 43 percent interest in HPC, for which equity method accounting applies. Prior periods have been restated to reflect the Partnership’s then wholly-owned subsidiary of Regency Intrastate Gas LLC as the exclusive reporting unit within this segment. The transportation segment uses pipelines to transport natural gas from receipt points on its system to interconnections with other pipelines, storage facilities or end-use markets. RIG performs transportation services for shipping customers under firm or interruptible arrangements. In either case, revenue is primarily fee based and involves minimal direct exposure to commodity price fluctuations. The north Louisiana intrastate pipeline operated by this segment serves the Partnership’s gathering and processing facilities in the same area and those transactions create a portion of the intersegment revenue shown in the table below.

The contract compression segment provides customers with turn-key natural gas compression services to maximize their natural gas and crude oil production, throughput, and cash flow. The Partnership’s integrated solutions include a comprehensive assessment of a customer’s natural gas contract compression needs and the design and installation of a compression system that addresses those particular needs. The Partnership is responsible for the installation and ongoing operation, service, and repair of its compression units, which are modified as necessary to adapt to customers’ changing operating conditions. The contract compression segment also provides services to certain operations in the gathering and processing segment, creating a portion of the intersegment revenues shown in the table below.

The corporate and others segment comprises regulated entities and the Partnership’s corporate offices. Revenue in this segment includes the collection of the partial reimbursement of general and administrative costs from HPC.

Management evaluates the performance of each segment and makes capital allocation decisions through the separate consideration of segment margin and operation and maintenance expenses. Segment margin, for the gathering and processing and for the transportation segments, is defined as total revenue, including service fees, less cost of sales. In the contract compression segment, segment margin is defined as revenue minus direct costs, which primarily consist of compressor repairs. Management believes segment margin is an important measure because it directly relates to volume, commodity price changes and revenue generating horsepower. Operation and maintenance expenses are a separate measure used by management to evaluate performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of operation and maintenance expenses. These expenses fluctuate depending on the activities performed during a specific period. The Partnership does not deduct operation and maintenance expenses from total revenue in calculating segment margin because management separately evaluates commodity volume and price changes in segment margin.

F-36

Results for each income statement period, together with amounts related to balance sheets for each segment are shown below.

	Gathering and Processing			Transportation			Contract Compression		Corporate and Others			Eliminations			Total
	(in thousands)
External Revenue(1)
Year ended December 31, 2009	$	920,650		$	9,078		$	148,846	$	10,923		$	—		$	1,089,497
Year ended December 31, 2008		1,685,946			42,400			132,549		2,909			—			1,863,804
Year ended December 31, 2007		1,151,739			36,587			—		1,912			—			1,190,238
Intersegment Revenue(1)
Year ended December 31, 2009		(8,755	)		4,933			4,604		296			(1,078	)		—
Year ended December 31, 2008		42,310			11,422			4,573		339			(58,644	)		—
Year ended December 31, 2007		26,165			12,391			—		281			(38,837	)		—
Cost of Sales(1) (2)
Year ended December 31, 2009		681,383			2,297			12,422		(65	)		3,526			699,563
Year ended December 31, 2008		1,463,851			(13,066	)		11,619		—			(54,071	)		1,408,333
Year ended December 31, 2007		1,018,721			(3,570	)		—		(169	)		(38,837	)		976,145
Segment Margin(1)
Year ended December 31, 2009		230,512			11,714			141,028		11,284			(4,604	)		389,934
Year ended December 31, 2008		264,405			66,888			125,503		3,248			(4,573	)		455,471
Year ended December 31, 2007		159,183			52,548			—		2,362			—			214,093
Operation and Maintenance
Year ended December 31, 2009		88,520			2,112			45,744		426			(5,976	)		130,826
Year ended December 31, 2008		82,689			3,540			49,799		74			(4,473	)		131,629
Year ended December 31, 2007		53,496			4,407			—		97			—			58,000
Depreciation and Amortization
Year ended December 31, 2009		67,583			2,448			36,548		3,314			—			109,893
Year ended December 31, 2008		58,900			14,099			28,448		1,119			—			102,566
Year ended December 31, 2007		40,309			13,457			—		1,308			—			55,074
Income from Unconsolidated Subsidiary
Year ended December 31, 2009		—			7,886			—		—			—			7,886
Year ended December 31, 2008		—			—			—		—			—			—
Year ended December 31, 2007		—			—			—		—			—			—
Assets
December 31, 2009		1,046,619			453,120			926,213		107,462			—			2,533,414
December 31, 2008		1,101,906			325,310			881,552		149,871			—			2,458,639
Investment in Unconsolidated Subsidiary
December 31, 2009		—			453,120			—		—			—			453,120
December 31, 2008		—			—			—		—			—			—
Goodwill
December 31, 2009		63,232			—			164,882		—			—			228,114
December 31, 2008		63,232			34,244			164,882		—			—			262,358
Expenditures for Long-Lived Assets
Year ended December 31, 2009		84,097			22,367			83,707		2,912			—			193,083
Year ended December 31, 2008		124,736			59,231			186,063		5,053			—			375,083
Year ended December 31, 2007		112,813			15,658			—		1,313			—			129,784

(1) The December 31, 2008 and 2007 amounts differ from previously reported amounts primarily due to the presentation of intersegment revenue, cost of sales and segment margin elimination amounts in the elimination column as opposed to including these amounts in each respective segment column.

(2) The Partnership identified an $80,000,000 typographical error related to the gathering and processing segment cost of sales for the year ended December 31, 2007. The amount should have been $1,008,517,000 as opposed to $1,088,517,000. However this error did not have an impact to the consolidated cost of sales nor the gathering and processing segment margin for the year ended December 31, 2007. The Partnership corrected this typographical error, together with the revision of the presentation of intersegment cost of sales discussed above in its December 31, 2009 segment information disclosure.

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The table below provides a reconciliation of total segment margin to net income (loss) from continuing operations.

	Year Ended
	December 31, 2009			December 31, 2008			December 31, 2007
	(in thousands)
Net income (loss) attributable to Regency Energy Partners LP	$	140,398		$	101,016		$	(13,836	)
Add (deduct):
Operation and maintenance		130,826			131,629			58,000
General and administrative		57,863			51,323			39,713
(Gain) loss on assets sales		(133,284	)		472			1,522
Management services termination fee		—			3,888			—
Transaction expenses		—			1,620			420
Depreciation and amortization		109,893			102,566			55,074
Income from unconsolidated subsidiary		(7,886	)		—			—
Interest expense, net		77,996			63,243			52,016
Loss on debt refinancing		—			—			21,200
Other income and deductions, net		15,132			(332	)		(1,252	)
Income tax (benefit) expense		(1,095	)		(266	)		931
Net income attributable to noncontrolling interest		91			312			305
Total segment margin	$	389,934		$	455,471		$	214,093

17. Equity-Based Compensation

Common Unit Option and Restricted (Non-Vested) Units. The Partnership’s LTIP for the Partnership’s employees, directors and consultants covers an aggregate of 2,865,584 common units. Awards under the LTIP have been made since completion of the Partnership’s IPO. All outstanding, unvested LTIP awards at the time of the GE EFS Acquisition vested upon the change of control. As a result, the Partnership recorded a one-time charge of $11,928,000 during the year ended December 31, 2007 that was recorded in general and administrative expenses. LTIP awards made subsequent to the GE EFS Acquisition generally vest on the basis of one-fourth of the award each year. Options expire ten years after the grant date. LTIP compensation expense of $5,590,000, $4,318,000, and $15,534,000, is recorded in general and administrative in the statement of operations for the years ended December 31, 2009, 2008, and 2007, respectively.

The fair value of each option award is estimated on the date of grant using the Black-Scholes Option Pricing Model. The Partnership used the simplified method outlined in Staff Accounting Bulletin No. 107 for estimating the exercise behavior of option grantees, given the absence of historical exercise data to provide a reasonable basis upon which to estimate expected term due to the limited period of time its units have been publicly traded. Upon the exercise of the common unit options, the Partnership intends to settle these obligations with new issues of common units on a net basis. The following assumptions apply to the options granted during the year ended December 31, 2007.

	For the Year Ended December 31, 2007
Weighted average expected life (years)		4
Weighted average expected dividend per unit	$	1.51
Weighted average grant date fair value of options	$	2.31
Weighted average risk free rate		4.60	%
Weighted average expected volatility		16.0	%
Weighted average expected forfeiture rate		11.0	%

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The common unit options activity for the years ended December 31, 2009, 2008, and 2007 is as follows.

2009
Common Unit Options	Units		Weighted Average Exercise Price		Weighted Average Contractual Term (Years)	Aggregate Intrinsic Value *(in thousands)
Outstanding at the beginning of period	431,918		$	21.31
Granted	—			—
Exercised	—			—		$	—
Forfeited or expired	(125,267	)		20.87
Outstanding at end of period	306,651			21.50	6.3		184
Exercisable at the end of the period	306,651						184
2008
Common Unit Options	Units		Weighted Average Exercise Price		Weighted Average Contractual Term (Years)	Aggregate Intrinsic Value *(in thousands)
Outstanding at the beginning of period	738,668		$	21.05
Granted	—			—
Exercised	(245,150	)		20.55		$	1,719
Forfeited or expired	(61,600	)		21.11
Outstanding at end of period	431,918			21.31	7.3		—
Exercisable at the end of the period	431,918						—
2007
Common Unit Options	Units		Weighted Average Exercise Price		Weighted Average Contractual Term (Years)	Aggregate Intrinsic Value *(in thousands)
Outstanding at the beginning of period	909,600		$	21.06
Granted	21,500			27.18
Exercised	(149,934	)		21.78		$	1,738
Forfeited or expired	(42,498	)		21.85
Outstanding at end of period	738,668			21.05	8.2		9,104
Exercisable at the end of the period	738,668			21.05			9,104

* Intrinsic value equals the closing market price of a unit less the option strike price, multiplied by the number of unit options outstanding as of the end of the period presented. Unit options with an exercise price greater than the end of the period closing market price are excluded.

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The restricted (non-vested) common unit activity for the years ended December 31, 2009, 2008, and 2007 is as follows.

2009
Restricted (Non-Vested) Common Units	Units		Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period	704,050		$	29.26
Granted	24,500			11.13
Vested	(176,291	)		29.78
Forfeited or expired	(88,250	)		27.96
Outstanding at the end of period	464,009			28.36
2008
Restricted (Non-Vested) Common Units	Units		Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period	397,500		$	31.62
Granted	477,800			27.99
Vested	(90,500	)		31.63
Forfeited or expired	(80,750	)		30.66
Outstanding at the end of period	704,050			29.26
2007
Restricted (Non-Vested) Common Units	Units		Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period	516,500		$	21.06
Granted	615,500			30.44
Vested	(684,167	)		22.91
Forfeited or expired	(50,333	)		27.20
Outstanding at the end of period	397,500			31.62

The Partnership will make distributions to non-vested restricted common units at the same rate and on the same dates as the common units. Restricted common units are subject to contractual restrictions against transfer which lapse over time; non-vested restricted units are subject to forfeitures on termination of employment. The Partnership expects to recognize $9,517,000 of compensation expense related to the grants under LTIP primarily over the next 1.91 years.

Phantom Units. During 2009, the Partnership awarded 308,200 phantom units to senior management and certain key employees. These phantom units are in substance two grants composed of (1) service condition grants (also defined as “time-based grants” in the LTIP plan document) with graded vesting occurring on March 15 of each of the following three years; and (2) market condition grants (also defined as “performance-based grants” in the LTIP plan document) with cliff vesting based upon the Partnership’s relative ranking in total unitholder return among 20 peer companies, which peer companies are disclosed in Item 11 of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2009. At the end of the measurement period (March 15, 2012) for the market condition grants, the phantom units will convert to common units in a ratio ranging from 0 to 150 percent. Upon a change in control, the market condition based grants will convert to common units at 150 percent and the service condition grants will convert to common on a one-for-one basis. For both the service condition grants and the market condition grants, distributions will be accumulated from the grant date and paid upon vesting at the same rate as the common units.

In determining the grant date fair value, the grant date closing price of the Partnership’s common units on NASDAQ was used for the service condition awards. For the market condition awards, a Monte Carlo simulation

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was performed which incorporated variables mainly including the unit price volatility and the grant-date closing price of the Partnership’s common units on NASDAQ.

The Partnership expects to recognize $1,753,000 of compensation expense related to non-vested phantom units over a period of 2.4 years. During the year ended December 31, 2009, the Partnership recognized $418,000 of expense, which was reflected in general and administrative expense in the statement of operations.

The following table presents phantom unit activity for the year ended December 31, 2009.

Phantom Units	Units		Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period	—		$	—
Service condition grants	133,480			13.43
Market condition grants	174,720			4.64
Vested service condition	—			—
Vested market condition	—			—
Forfeited service condition	(2,600	)		12.46
Forfeited market condition	(3,900	)		4.49
Total outstanding at end of period	301,700			8.63

18. Subsequent Events

On January 26, 2010, the Partnership declared a distribution of $0.445 per outstanding common unit including units equivalent to the General Partner’s two percent interest in the Partnership, and an aggregate distribution of approximately $728,000, with respect to incentive distribution rights, that was paid on February 12, 2010 to unitholders of record at the close of business on February 5, 2010.

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19. Quarterly Financial Data (Unaudited)

Quarter Ended	Operating Revenues		Operating Income (Loss)		Net Income (Loss) Attributable to Regency Energy Partners LP			Basic Earnings per Common and Subordinated Unit			Diluted Earnings per Common and Subordinated Unit			Basic and Diluted Earnings per Class D Common Unit
	(in thousands except earnings per unit)
2009
March 31	$	290,125	$	162,373	$	148,389	(1)	$	1.85		$	1.78		$	0.11
June 30		253,542		23,207		5,890			0.07			0.06			—
September 30		250,582		21,831		(10,504	)		(0.16	)		(0.16	)		—
December 31		295,248		17,225		(3,377	)		(0.07	)		(0.07	)		—
2008
March 31(2)	$	405,235	$	25,877	$	10,348		$	0.13		$	0.13		$	0.21
June 30		546,705		26,512		9,972			0.12			0.12			0.26
September 30 (2)		547,175		64,956		48,907			0.64			0.61			0.26
December 31		364,689		46,628		31,789			0.39			0.38			0.26

(1) In March 2009, the Partnership contributed RIG to HPC, recognized a gain of $133,451,000 on the transaction. See Note 5 for further information.

(2) The operating income amount and basic and diluted earnings per Class D Common Unit disclosed above differs immaterially from the amount disclosed in the Form 10-Q.

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