Exhibit 99.3

Exhibit 99.3. Financial Statements and Supplementary Data

Index to Consolidated Financial Statements

	Page
Report of Independent Registered Public Accounting Firm as of and for the years ended December 31, 2008 and 2007	2
Report of Independent Registered Public Accounting Firm as of December 31, 2008	3
Report of Independent Registered Public Accounting Firm for the year ended December 31, 2006	4
Consolidated Balance Sheets as of December 31, 2008 and 2007	5
Consolidated Statements of Operations for the years ended December 31, 2008, 2007, and 2006	6
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2008, 2007, and 2006	7
Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007, and 2006	8
Consolidated Statements of Member Interest and Partners’ Capital for the years ended December  31, 2008, 2007, and 2006	9

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, 2008 and 2007 and the related consolidated statements of operations, comprehensive income (loss), cash flows, and partners’ capital for the years then ended. 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. The accompanying consolidated financial statements of Regency Energy Partners LP and subsidiaries as of December 31, 2006, were audited by other auditors whose report thereon dated March 29, 2007 (February 28, 2008 as to Note 4), expressed an unqualified opinion on those statements, before the effects of the adjustments to retrospectively apply the changes in accounting discussed in Note 2 and to retrospectively adjust the disclosures for a change in the composition of reportable segments discussed in Note 14 to the consolidated financial statements.

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 2008 and 2007 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, 2008 and 2007 and the results of their operations and their cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

We also have audited the adjustments to the 2006 consolidated financial statements to retrospectively apply the changes in accounting discussed in Note 2 and to retrospectively adjust the disclosures for a change in the composition of reportable segments discussed in Note 14 to the consolidated financial statements. In our opinion, such adjustments are appropriate and have been properly applied. We were not engaged to audit, review, or apply any procedures to the 2006 consolidated financial statements of the Partnership other than with respect to the adjustments and, accordingly, we do not express an opinion or any other form of assurance on the 2006 consolidated financial statements taken as a whole.

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, 2008, 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, 2009 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

/s/ KPMG LLP

Dallas, Texas

March 1, 2009, except for Notes 2, 4, 5, 7, 14, 16 and 17,

which are as of May 14, 2009

2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Partners

Regency Energy Partners LP:

We have audited Regency Energy Partners LP’s internal control over financial reporting as of December 31, 2008, 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 maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Regency Energy Partners LP acquired CDM Resource Management, Ltd. (CDM) during 2008, and management excluded from its assessment of the effectiveness of Regency Energy Partners LP’s internal control over financial reporting as of December 31, 2008, CDM’s internal control over financial reporting associated with total assets of $881,552,000 and total revenues of $132,549,000 included in the consolidated financial statements of Regency Energy Partners LP and subsidiaries as of and for the year ended December 31, 2008. Our audit of internal control over financial reporting of Regency Energy Partners LP also excluded an evaluation of the internal control over financial reporting of CDM.

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 as of December 31, 2008 and 2007, and the related consolidated statements of operations, comprehensive income (loss), cash flows, and partners’ capital for the years then ended, and our report dated March 1, 2009 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Dallas, Texas

March 1, 2009

3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Regency GP LLC and Unitholders of Regency Energy Partners LP:

We have audited, before (1) the effects of the adjustments to retrospectively apply the changes in accounting discussed in Note 2 to the consolidated financial statements and (2) the effects of the retrospective adjustments to the disclosures for a change in the composition of reportable segments discussed in Note 14 to the consolidated financial statements, the consolidated statements of operations, member interest and partners’ capital, comprehensive income (loss) and cash flows of Regency Energy Partners LP and subsidiaries (the “Partnership”) for the year ended December 31, 2006 (the 2006 consolidated financial statements before the effects of the adjustments discussed in Notes 2 and 14 to the consolidated financial statements are not presented herein). These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements 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 the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such 2006 consolidated financial statements, before (1) the effects of the adjustments to retrospectively apply the changes in accounting discussed in Note 2 to the consolidated financial statements and (2) the effects of the retrospective adjustments to the disclosures for a change in the composition of reportable segments discussed in Note 14 to the consolidated financial statements, present fairly, in all material respects, the results of the Partnership’s operations and cash flows for the year ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

We were not engaged to audit, review, or apply any procedures to (1) the adjustments to retrospectively apply the changes in accounting discussed in Note 2 to the consolidated financial statements or (2) the retrospective adjustments to the disclosures for a change in the composition of reportable segments discussed in Note 14 to the consolidated financial statements and, accordingly, we do not express an opinion or any other form of assurance about whether such retrospective adjustments are appropriate and have been properly applied. Those retrospective adjustments were audited by other auditors.

As discussed in Note 1, the Partnership accounted for its acquisition of TexStar Field Services, L.P. and its general partner, TexStar GP, LLC as acquisitions of entities under common control in a manner similar to a pooling of interests.

/s/ Deloitte & Touche LLP

Dallas, Texas

March 29, 2007 (February 28, 2008 as to Note 4)

4

Regency Energy Partners LP

Consolidated Balance Sheets

(in thousands except unit data)

	December 31, 2008			December 31, 2007
ASSETS
Current Assets:
Cash and cash equivalents	$	599		$	32,971
Restricted cash		10,031			6,029
Trade accounts receivable, net of allowance of $941 in 2008 and $61 in 2007		40,875			16,487
Accrued revenues		96,712			117,622
Related party receivables		855			61
Assets from risk management activities		73,993			—
Other current assets		13,338			6,723
Total current assets		236,403			179,893
Property, plant and equipment
Gathering and transmission systems		652,267			635,206
Compression equipment		799,527			145,555
Gas plants and buildings		156,246			134,300
Other property, plant and equipment		167,256			105,399
Construction-in-progress		154,852			33,552
Total property, plant and equipment		1,930,148			1,054,012
Less accumulated depreciation		(226,594	)		(140,903	)
Property, plant and equipment, net		1,703,554			913,109
Other Assets:
Intangible assets, net of accumulated amortization of $22,517 in 2008 and $8,929 in 2007		205,646			77,804
Long-term assets from risk management activities		36,798			—
Goodwill		262,358			94,075
Other, net of accumulated amortization of debt issuance costs of $5,246 in 2008 and $2,488 in 2007		13,880			13,529
Total other assets		518,682			185,408
TOTAL ASSETS	$	2,458,639		$	1,278,410
LIABILITIES & PARTNERS’ CAPITAL
Current Liabilities:
Trade accounts payable	$	65,483		$	48,904
Accrued cost of gas and liquids		76,599			96,026
Related party payables		—			50
Escrow payable		10,031			6,029
Liabilities from risk management activities		42,691			37,852
Other current liabilities		22,146			9,397
Total current liabilities		216,950			198,258
Long-term liabilities from risk management activities		560			15,073
Other long-term liabilities		15,487			15,393
Long-term debt		1,126,229			481,500
Commitments and contingencies
Partners’ Capital:
Common units (55,519,903 and 41,283,079 units authorized; 54,796,701 and 40,514,895 units issued and outstanding at December 31, 2008 and 2007)		764,161			490,351
Class D common units (7,276,506 units authorized, issued and outstanding at December 31, 2008)		226,759			—
Class E common units (4,701,034 units authorized, issued and outstanding at December 31, 2007)		—			92,962
Subordinated units (19,103,896 units authorized, issued and outstanding at December 31, 2008 and 2007)		(1,391	)		7,019
General partner interest		29,283			11,286
Accumulated other comprehensive income (loss)		67,440			(38,325	)
Noncontrolling interest		13,161			4,893
Total partners’ capital		1,099,413			568,186
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	2,458,639		$	1,278,410

See accompanying notes to consolidated financial statements

5

Regency Energy Partners LP

Consolidated Statements of Operations

(in thousands except unit data and per unit data)

	Year Ended December 31,
	2008			2007			2006
REVENUES
Gas sales	$	1,126,760		$	744,681		$	560,620
NGL sales		409,476			347,737			256,672
Gathering, transportation and other fees, including related party amounts of $3,763, $1,350 and $2,160		286,507			100,644			63,071
Net realized and unrealized loss from risk management activities		(21,233	)		(34,266	)		(7,709	)
Other		62,294			31,442			24,211
Total revenues		1,863,804			1,190,238			896,865
OPERATING COSTS AND EXPENSES
Cost of sales, including related party amounts of $1,878, $14,165 and $1,630		1,408,333			976,145			740,446
Operation and maintenance		131,629			58,000			39,496
General and administrative		51,323			39,713			22,826
Loss on asset sales, net		472			1,522			—
Management services termination fee		3,888			—			12,542
Transaction expenses		1,620			420			2,041
Depreciation and amortization		102,566			55,074			39,654
Total operating costs and expenses		1,699,831			1,130,874			857,005
OPERATING INCOME		163,973			59,364			39,860
Interest expense, net		(63,243	)		(52,016	)		(37,182	)
Loss on debt refinancing		—			(21,200	)		(10,761	)
Other income and deductions, net		332			1,252			839
INCOME (LOSS) BEFORE INCOME TAXES		101,062			(12,600	)		(7,244	)
Income tax expense (benefit)		(266	)		931			—
NET INCOME (LOSS)		101,328			(13,531	)		(7,244	)
Net income attributable to noncontrolling interest		(312	)		(305	)		—
NET INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP	$	101,016		$	(13,836	)	$	(7,244	)
Less: Net income from January 1-31, 2006		—			—			1,564
Net income (loss) for partners	$	101,016		$	(13,836	)	$	(8,808	)
General partner’s interest in current period net income (loss), including IDR		4,303			(366	)		(164	)
Net income (loss) allocated to non-vested units		869			(103	)		(110	)
Amount allocated to Class B common units		—			—			(886	)
Beneficial conversion feature for Class C common units		—			1,385			3,587
Beneficial conversion feature for Class D common units		7,199			—			—
Amount allocated to Class E common units		—			5,792			—
Limited partners’ interest in net income (loss)	$	88,645		$	(20,544	)	$	(11,235	)
Basic and Diluted earnings per unit:
Amount allocated to common and subordinated units	$	88,645		$	(20,544	)	$	(11,235	)
Weighted average number of common and subordinated units outstanding		66,190,626			51,056,769			38,207,792
Basic income (loss) per common and subordinated unit	$	1.34		$	(0.40	)	$	(0.29	)
Diluted income (loss) per common and subordinated unit	$	1.28		$	(0.40	)	$	(0.29	)
Distributions per unit	$	1.71		$	1.52		$	0.9417
Amount allocated to Class B common units	$	—		$	—		$	(886	)
Weighted average number of Class B common units outstanding		—			651,964			5,173,189
Income per Class B common unit	$	—		$	—		$	(0.17	)
Distributions per unit	$	—		$	—		$	—
Amount allocated to Class C common units	$	—		$	1,385		$	3,587
Total number of Class C common units outstanding		—			2,857,143			2,857,143
Income per Class C common unit due to beneficial conversion feature	$	—		$	0.48		$	1.26
Distributions per unit	$	—		$	—		$	—
Amount allocated to Class D common units	$	7,199		$	—		$	—
Total number of Class D common units outstanding		7,276,506			—			—
Income per Class D common unit due to beneficial conversion feature	$	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		$	—

See accompanying notes to consolidated financial statements

6

Regency Energy Partners LP

Consolidated Statements of Comprehensive Income (Loss)

(in thousands)

	Year Ended December 31,
	2008			2007			2006
Net income (loss)	$	101,328		$	(13,531	)	$	(7,244	)
Net hedging amounts reclassified to earnings		35,512			19,362			1,815
Net change in fair value of cash flow hedges		70,253			(58,706	)		10,166
Comprehensive income (loss)		207,093			(52,875	)		4,737
Comprehensive income attributable to noncontrolling interest		(312	)		(305	)		—
Comprehensive income attributable to Regency Energy Partners LP	$	206,781		$	(53,180	)	$	4,737

See accompanying notes to consolidated financial statements

7

Regency Energy Partners LP

Consolidated Statements of Cash Flows

(in thousands)

	Year Ended December 31,
	2008			2007			2006
OPERATING ACTIVITIES
Net income (loss)	$	101,328		$	(13,531	)	$	(7,244	)
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:
Depreciation and amortization, including debt issuance cost amortization		105,324			57,069			39,287
Write-off of debt issuance costs		—			5,078			10,761
Income from unconsolidated subsidiaries		—			(43	)		(532	)
Risk management portfolio valuation changes		(14,700	)		14,667			(2,262	)
Loss on asset sales		472			1,522			—
Unit based compensation expenses		4,306			15,534			2,906
Gain on insurance settlements		(3,282	)		—			—
Cash flow changes in current assets and liabilities:
Trade accounts receivable and accrued revenues, and related party receivables		18,648			(28,789	)		(5,506	)
Other current assets		(6,615	)		(1,394	)		104
Trade accounts payable, accrued cost of gas and liquids, and related party payables		(40,772	)		30,089			(1,359	)
Other current liabilities		12,749			(149	)		3,640
Proceeds from early termination of interest rate swap		—			—			4,940
Amount of swap termination proceeds reclassified into earnings		—			(1,078	)		(3,862	)
Other assets and liabilities		3,840			554			3,283
Net cash flows provided by operating activities		181,298			79,529			44,156
INVESTING ACTIVITIES
Capital expenditures		(375,083	)		(129,784	)		(142,423	)
Acquisitions		(577,668	)		(34,855	)		(81,695	)
Acquisition of investment in unconsolidated subsidiary, net of $100 cash		—			(5,000	)		—
Proceeds from asset sales		840			11,706			—
Proceeds from insurance settlements		3,282			—			—
Other		—			—			468
Net cash flows used in investing activities		(948,629	)		(157,933	)		(223,650	)
FINANCING ACTIVITIES
Net borrowings under revolving credit facilities		644,729			59,300			14,700
Borrowings under credit facilities		—			—			599,650
Repayments under credit facilities		—			(50,000	)		(858,600	)
Proceeds (repayments) of senior notes, net of debt issuance costs		—			(192,500	)		536,175
Partner contributions		11,746			7,735			3,786
Partner distributions		(120,591	)		(79,933	)		(37,144	)
Proceeds from option exercises		2,700			—			—
Debt issuance costs		(2,940	)		(2,427	)		(10,488	)
Proceeds from equity issuances, net of issuance costs		199,315			353,546			312,700
FrontStreet distributions		—			(9,695	)		—
FrontStreet contributions		—			13,417			—
Acquisition of assets between entities under common control		—			—			(62,074	)
Borrowings under TexStar loan agreement		—			—			85,000
Repayments under TexStar loan agreement		—			—			(155,000	)
Cash distribution to HM Capital		—			—			(243,758	)
Proceeds from exercise of over allotment option		—			—			26,163
Over allotment option proceeds to HM Capital		—			—			(26,163	)
Net cash flows provided by financing activities		734,959			99,443			184,947
Net increase (decrease) in cash and cash equivalents		(32,372	)		21,039			5,453
Cash and cash equivalents at beginning of period		32,971			9,139			3,686
Cash acquired from FrontStreet		—			2,793			—
Cash and cash equivalents at end of period	$	599		$	32,971		$	9,139
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	59,969		$	67,844		$	33,347
Income taxes paid		605			—			—
Non-cash capital expenditures in accounts payable		25,845			7,761			23,822
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			—

See accompanying notes to consolidated financial statements

8

Regency Energy Partners LP

Consolidated Statements of Member Interest and Partners’ Capital

(in thousands except unit data)

	Regency Energy Partners LP
	Units										Member Interest			Common Unitholders
	Common		Class B		Class C		Class D	Class E		Subordinated
Balance—December 31, 2005	—		—		—		—	—		—	$	241,924		$	—
Net income through January 31, 2006	—		—		—		—	—		—		1,564			—
Net hedging loss reclassified to earnings	—		—		—		—	—		—		—			—
Net change in fair value of cash flow hedges	—		—		—		—	—		—		—			—
Balance—January 31, 2006	—		—		—		—	—		—		243,488			—
Contribution of net investment to unitholders	5,353,896		—		—		—	—		19,103,896		(182,320	)		89,337
Proceeds from IPO, net of issuance costs	13,750,000		—		—		—	—		—		—			125,907
Net proceeds from exercise of over allotment option	1,400,000		—		—		—	—		—		—			26,163
Over allotment option net proceeds to HM Capital Investors	(1,400,000	)	—		—		—	—		—		—			(26,163	)
Capital reimbursement to HM Capital Partners	—		—		—		—	—		—		—			(119,441	)
Offering costs	—		—		—		—	—		—		—			(2,056	)
Issuance of Class B Common Units for TexStar member interest	—		5,173,189		—		—	—		—		(61,168	)		—
Payment to HM Capital for TexStar net of repayment of promissory note	—		—		—		—	—		—		—			(30,418	)
Other	—		—		—		—	—		—		—			(64	)
Issuance of Class C Common Units net of costs	—		—		2,857,143		—	—		—		—			—
Issuance of restricted common units	516,500		—		—		—	—		—		—			—
Unit based compensation expenses	—		—		—		—	—		—		—			1,339
General partner contributions					—		—	—		—		—			—
Partner distributions	—		—		—		—	—		—		—			(18,409	)
Net loss from February 1 through December 31, 2006	—		—		—		—	—		—		—			(4,003	)
Net hedging loss reclassified to earnings	—		—		—		—	—		—		—			—
Net change in fair value of cash flow hedges	—		—		—		—	—		—		—			—
Balance—December 31, 2006	19,620,396		5,173,189		2,857,143		—	—		19,103,896		—			42,192
Conversion of Class B and C to common units	8,030,332		(5,173,189	)	(2,857,143	)	—	—		—		—			120,663
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
General partner contributions	—		—		—		—	—		—		—			—
Partner distributions	—		—		—		—	—		—		—			(49,296	)
Acquisition of FrontStreet	—		—		—		—	4,701,034		—		—			—
FrontStreet contributions	—		—		—		—	—		—		—			—
FrontStreet distributions	—		—		—		—	—		—		—			—
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	—		—		—		—	—		—		—			—
Conversion of Class E common units	4,701,034		—		—		—	(4,701,034	)	—		—			92,104
Unit based compensation expenses	—		—		—		—	—		—		—			4,306
General partner contributions	—		—		—		—	—		—		—			—
Partner distributions	—		—		—		—	—		—		—			(84,207	)
Net income	—		—		—		—	—		—		—			59,592
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

See accompanying notes to the consolidated financial statements

9

Regency Energy Partners LP

Consolidated Statements of Member Interest and Partners’ Capital—(Continued)

(in thousands except unit data)

	Regency Energy Partners LP
	Class B Unitholders			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, 2005	$	—		$	—		$	—	$	—		$	—		$	—		$	(10,962	)	$	—		$	230,962
Net income through January 31, 2006		—			—			—		—			—			—			—			—			1,564
Net hedging loss reclassified to earnings		—			—			—		—			—			—			616			—			616
Net change in fair value of cash flow hedges		—			—			—		—			—			—			2,581			—			2,581
Balance—January 31, 2006		—			—			—		—			—			—			(7,765	)		—			235,723
Contribution of net investment to unitholders		—			—			—		—			89,337			3,646			—			—			—
Proceeds from IPO, net of issuance costs		—			—			—		—			125,907			5,139			—			—			256,953
Net proceeds from exercise of over allotment option		—			—			—		—			—			—			—			—			26,163
Over allotment option net proceeds to HM Capital Investors		—			—			—		—			—			—			—			—			(26,163	)
Capital reimbursement to HM Capital Partners		—			—			—		—			(119,441	)		(4,876	)		—			—			(243,758	)
Offering costs		—			—			—		—			(2,056	)		(83	)		—			—			(4,195	)
Issuance of Class B Common Units for TexStar member interest		61,168			—			—		—			—			—			—			—			—
Payment to HM Capital for TexStar net of repayment of promissory note		—			—			—		—			(29,744	)		(1,214	)		—			—			(61,376	)
Other		(17	)		(9	)		—		—			(63	)		(2	)		—			—			(155	)
Issuance of Class C Common Units net of costs		—			59,942			—		—			—			—			—			—			59,942
Issuance of restricted common units		—			—			—		—			—			—			—			—			—
Unit based compensation expenses		146			59			—		—			1,304			58			—			—			2,906
General partner contributions		—			—			—		—			—			3,786			—			—			3,786
Partner distributions		—			—			—		—			(18,001	)		(735	)		—			—			(37,145	)
Net loss from February 1 through December 31, 2006		(626	)		—			—		—			(4,003	)		(176	)		—			—			(8,808	)
Net hedging loss reclassified to earnings		—			—			—		—			—			—			7,585			—			7,585
Net change in fair value of cash flow hedges		—			—			—		—			—			—			1,199			—			1,199
Balance—December 31, 2006		60,671			59,992			—		—			43,240			5,543			1,019			—			212,657
Conversion of Class B and C to common units		(60,671	)		(59,992	)		—		—			—			—			—			—			—
Issuance of common units for acquisition		—			—			—		—			—			—			—			—			19,724
Issuance of common units		—			—			—		—			—			—			—			—			353,446
Issuance of restricted common units		—			—			—		—			—			—			—			—			—
Exercise of common unit options		—			—			—		—			—			—			—			—			100
Unit based compensation expenses		—			—			—		—			—			—			—			—			15,534
General partner contributions		—			—			—		—			—			7,735			—			—			7,735
Partner distributions		—			—			—		—			(29,038	)		(1,599	)		—			—			(79,933	)
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 income (loss)		—			—			—		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	)
Acquire noncontrolling interest		—			—			—		—			—			—			—			(4,893	)		(4,893	)
Conversion of Class E common units		—			—			—		(92,104	)		—			—			—			—			—
Unit based compensation expenses		—			—			—		—			—			—			—			—			4,306
General partner contributions		—			—			—		—			—			11,746			—			—			11,746
Partner distributions		—			—			—		—			(32,668	)		(3,716	)		—			—			(120,591	)
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

See accompanying notes to consolidated financial statements

10

Regency Energy Partners LP

Notes to Consolidated Financial Statements

For the Year Ended December 31, 2008

1. Organization and Basis of Presentation

Organization. The consolidated financial statements presented herein contain the results of Regency Energy Partners LP (“Partnership”), a Delaware limited partnership, and its predecessor, Regency Gas Services LLC (“Predecessor”). The Partnership was formed on September 8, 2005; on February 3, 2006, in conjunction with its IPO, the Predecessor was converted to a limited partnership, Regency Gas Services LP (“RGS”), and became a wholly owned subsidiary of the Partnership. The Partnership and its subsidiaries are engaged in the business of gathering, treating, processing, transporting, and marketing 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 August 15, 2006, the Partnership acquired all the outstanding equity of TexStar Field Services, L.P. and its general partner, TexStar GP, LLC (collectively “TexStar”), from HMTF Gas Partners II, L.P. (“HMTF Gas Partners”), an affiliate of HM Capital Partners LLC (“HM Capital Partners”) (“TexStar Acquisition”). Because the TexStar Acquisition was a transaction between commonly controlled entities, the Partnership accounted for the TexStar Acquisition in a manner similar to a pooling of interests. Information included in these financial statements is presented as if the Partnership and TexStar had been combined throughout the periods presented in which common control existed, December 1, 2004 forward. See Note 5.

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”).

On January 7, 2008, the Partnership acquired all of the outstanding equity and noncontrolling interest (the “FrontStreet Acquisition”) of FrontStreet from ASC and EnergyOne. FrontStreet owns 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 noncontrolling 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.

In connection with the FrontStreet Acquisition, the Partnership amended the Partnership Agreement to create the Class E common units. 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 of operating surplus 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 afforded by Section 4(2) thereof. The Class E common units converted into common units on a one-for-one basis on May 5, 2008.

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 noncontrolling 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 values of the assets acquired and 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

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 necessarily include 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.

Restricted Cash. Restricted cash of $10,031,000 is held in escrow for purchase indemnifications related to the Nexus 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.

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. Gas 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, 2008, 2007, and 2006, the Partnership capitalized interest of $2,409,000, $1,754,000, and $511,000, 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 assesses long-lived 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 2008, 2007 or 2006.

The Partnership accounts for its asset retirement obligations in accordance with SFAS No. 143 “Accounting for Asset Retirement Obligations” and FIN 47 “Accounting for Conditional Asset Retirement Obligations.” These accounting standards require the Partnership to recognize 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

12

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 $88,828,000, $50,719,000, and $36,880,000 for the years ended December 31, 2008, 2007, and 2006, 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 thirty years.

The Partnership evaluates the carrying value of intangible assets whenever certain events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. In assessing the recoverability, the Partnership compares the carrying value to the undiscounted future cash flows the intangible assets are expected to generate. If the total of the undiscounted future cash flows is less than the carrying amount of the intangible assets, the intangibles are written down to their fair value. The Partnership did not record any impairment in 2008, 2007, or 2006.

Goodwill. Goodwill represents the excess of the purchase price over the fair value of net assets acquired in a business combination. Goodwill is not amortized, but is tested for impairment annually based on 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, 2008, 2007, or 2006.

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 as allowed under EITF 06-03, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement.”

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, 2008 and 2007 were immaterial.

Revenue Recognition. The Partnership earns revenues from (i) domestic sales of natural gas, NGLs and condensate, (ii) natural gas gathering, processing and transportation, and (iii) contract compression services. Revenues 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. Revenues

13

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 revenues gross in the consolidated statements of operations, in accordance with EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.” Except for fee-based agreements, the Partnership acts as the principal in these transactions, takes title to the product, and incurs the risks and rewards of ownership. Allowance for doubtful accounts is determined based on historical write-off experience and specific identification.

Risk Management Activities. 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. The Partnership accounts for derivative financial instruments in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended (“SFAS 133”), whereby all derivative financial instruments are recorded in 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 against 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 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 loss from risk management activities 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 or 5 years. The amount of matching contributions for the years ended December 31, 2008, 2007, and 2006 was $395,000, $469,000 and $201,000, respectively, and is 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. Effective January 1, 2007, the Partnership became 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 $8,156,000 and $8,642,000 as of December 31, 2008

14

and 2007 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 adopted the provisions of FIN No. 48 “Accounting for Uncertainty in Income Taxes—An Interpretation of FASB Statement 109”, on January 1, 2007. Upon adoption, the Partnership did not identify or record any uncertain tax positions not meeting the more likely than not standard. The Partnership’s entities that are required to pay federal income tax recognized current income tax expense of $ 62,000 and deferred income tax benefit of $486,000 using a 35 percent effective rate.

Equity-Based Compensation. The Partnership adopted SFAS No. 123(R) “Share-Based Payment” in the first quarter of 2006 upon the creation of LTIP. The adoption had no impact on the consolidated financial position, results of operations or cash flows as no LTIP awards were granted prior to adoption.

Earnings per unit. Basic net income per limited partner unit is computed in accordance with SFAS No. 128, “Earnings Per Share,” as interpreted by EITF Issue No. 03-6 (“EITF 03-6”), “Participating Securities and the Two-Class method under FASB Statement No. 128.” 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. 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. In periods when the Partnership’s aggregate net income exceeds the aggregate distributions, EITF 03-6 requires the Partnership to present earnings per unit as if all of the earnings for the periods were distributed. Diluted net income per limited partner 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 the effect of non-vested restricted 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.

Retrospective Application of Recently Adopted Accounting Standards. The Partnership has recast its consolidated financial statements as of December 31, 2008 and 2007 and for the years ended December 31, 2008, 2007, and 2006 for the retrospective adoption of EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships”, SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51”, and FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (See Note. 4). Additionally, the Partnership has restated its segment information for the realignment of its segments subsequent to formation of the Haynesville Joint Venture (see Note 14).

Recently Issued Accounting Standards. In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS 141(R)”), which significantly changes the accounting for business acquisitions both during the period of the acquisition and in subsequent periods. SFAS 141(R) is effective for fiscal years beginning after December 15, 2008. Generally, the effects of SFAS No. 141(R) will depend on future acquisitions.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51” (“SFAS No. 160”), which significantly changes the accounting and reporting related to noncontrolling interests in a consolidated subsidiary. The Partnership adopted SFAS No. 160 for all periods presented. This statement requires the recognition of a noncontrolling interest (formerly styled as a minority interest) in partners’ capital in the consolidated financial statements and separate from the partners’ interest. Also, the amount of net income attributable to the noncontrolling interest is included in the consolidated net income on the face of the income statement.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (“SFAS 161”). SFAS 161 requires enhanced disclosures about derivative and hedging activities. These enhanced disclosures will address (a) how and why a company uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations and (c) how derivative instruments and related hedged items affect a company’s financial position, results of operations and cash flows. SFAS 161 is effective for fiscal years and interim periods beginning on or after November 15, 2008, with earlier adoption allowed. The Partnership is currently evaluating the potential impacts on its financial position, results of operations or cash flows of the adoption of this standard.

        In March 2008, the FASB issued EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships” (“EITF 07-4”). EITF 07-4 defines how to allocate net income among the various classes of equity, including incentive distribution rights (or “IDRs”), narrowing the number of currently acceptable methods. The standard became effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. The Partnership has applied this guidance retrospectively for all periods presented. The adoption of this standard changes the Partnership’s method of allocating net income to holders of the IDRs in periods where net income exceeds cash distributed. Because the Partnership Agreement restricts the amount of distributions to holders of IDRs based on cash available for distribution, undistributed net income will be allocated based on the ownership interest of the general partner and unitholders. Further, because the IDR’s are deemed to have no ownership interest, no undistributed net income will be allocated to this class of security. All prior period earnings per unit data have been adjusted.

15

In April 2008, FASB issued FSP No. 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP 142-3”), which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of intangible assets. The objective of FSP 142-3 is to better match the useful life of intangible assets to the cash flow generated. FSP 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years. Early adoption of this statement is not permitted. The Partnership is currently evaluating the potential impact of this standard on its financial position, results of operations and cash flows.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS 162”), which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements that are presented in conformity of GAAP. SFAS 162’s effective date is November 15, 2008. The adoption of SFAS 162 is not expected to have a material impact on the Partnership’s financial position, results of operations or cash flows.

In June 2008, the FASB issued FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”) and is effective for fiscal years beginning after December 15, 2008. The adoption of this standard was applied retrospectively and had an immaterial impact on the Partnership’s earnings per unit.

3. Partners’ Capital and Distributions

Initial Public Offering. On February 3, 2006, the Partnership offered and sold 13,750,000 common units, representing a 35.3 percent limited partner interest in the Partnership, in its IPO, at a price of $20.00 per unit. Total proceeds from the sale of the units were $275,000,000, before offering costs and underwriting commissions. On March 8, 2006, the Partnership sold an additional 1,400,000 common units at a price of $20.00 per unit as the underwriters exercised a portion of their over allotment option.

Class B Common Units. On August 15, 2006, the Partnership issued 5,173,189 of Class B common units to HMTF Gas Partners as partial consideration for the TexStar Acquisition. The Class B common units had the same terms and conditions as the Partnership’s common units, except that the Class B common units were not entitled to participate in earnings or distributions by the Partnership. The Class B common units were converted into common units without the payment of further consideration on a one-for-one basis on February 15, 2007.

Class C Common Units. On September 21, 2006, the Partnership entered into a Class C Unit Purchase Agreement with certain purchasers, pursuant to which the purchasers purchased 2,857,143 Class C common units representing limited partner interests in the Partnership at a price of $21.00 per unit. The Class C common units had the same terms and conditions as the Partnership’s common units, except that the Class C common units were not entitled to participate in earnings or distributions by the Partnership. The Class C common units were converted into common units without the payment of further consideration on a one-for-one basis on February 8, 2007.

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

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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 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 Resource Management Ltd. 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 under Section 4(2) thereof. The Class D common units were converted into common units without the payment of further consideration on a one-for-one basis on February 9, 2009.

Common Unit Offerings. On July 26, 2007, the Partnership sold 10,000,000 common units for and received $307,680,000 in proceeds, excluding the General Partner’s proportionate capital contribution of $6,279,000 and offering expenses of $386,000. On July 31, 2007, the Partnership sold an additional 1,500,000 and received $46,152,000 from this sale after deducting underwriting discounts and commissions and excluding the general partner’s proportionate capital contribution of $942,000. On August 1, 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.

Distributions. Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of the Partnership’s Available Cash (defined below) 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 1,656,676 equivalent units as of December 31, 2008. 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. Please read the Distributions of Available Cash during the Subordination Period and Distributions of Available Cash after the Subordination Period sections below for more details about the distribution targets and their impact on the general partner’s incentive distribution rights.

Subordinated Units. All of the subordinated units are held by GE EFS and members of senior management. The partnership agreement provides that, during the subordination period, the common units will have the right to receive distributions of Available Cash each quarter in an amount equal to $0.35 per common unit, or the “Minimum Quarterly Distribution,” plus any arrearages in the payment of the Minimum Quarterly Distribution

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on the common units from prior quarters, before any distributions of Available Cash may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the Minimum Quarterly Distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be Available Cash to be distributed on the common units. The subordination period will end, and the subordinated units will convert to common units, on a one for one basis, when certain distribution requirements, as defined in the partnership agreement, have been met. The earliest date at which the subordination period may end is the first day of any quarter beginning after December 31, 2008. The rights of the subordinated unitholders, other than the distribution rights described above, are substantially the same as the rights of the common unitholders. The subordinated units converted into common units on a one-for-one basis on February 17, 2009.

Distributions of Available Cash During the Subordination Period. The partnership agreement requires that we make distributions of Available Cash for any quarter during the subordination period in the following manner:

• first, 98 percent to the common unitholders, pro rata, and 2 percent to the general partner, until we distribute for each outstanding common unit an amount equal to the Minimum Quarterly Distribution for that quarter;

• second, 98 percent to the common unitholders, pro rata, and 2 percent to the general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the Minimum Quarterly Distribution on the common units for any prior quarters during the subordination period;

• third, 98 percent to the subordinated unitholders, pro rata, and 2 percent to the general partner, until we distribute for each subordinated unit an amount equal to the Minimum Quarterly Distribution for that quarter;

• fourth, 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;

• fifth, 85 percent to all unitholders, pro rata, and 15 percent to the general partner, until each unitholder receives a total of $0.4375 per unit for that quarter;

• sixth, 75 percent to all unitholders, pro rata, and 25 percent to the general partner, until each unitholder receives a total of $0.525 per unit for that quarter; and

• thereafter, 50 percent to all unitholders, pro rata, and 50 percent to the general partner.

Distributions of Available Cash After the Subordination Period. The partnership agreement requires that we 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 $0.4025 per unit for that quarter;

• second, 85 percent to all unitholders, pro rata, and 15 percent to the general partner, until each unitholder receives a total of $0.4375 per unit for that quarter;

• third, 75 percent to all unitholders, pro rata, and 25 percent to the general partner, until each unitholder receives a total of $0.525 per unit for that quarter; and

• thereafter, 50 percent to all unitholders, pro rata, and 50 percent to the general partner.

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Distributions. The Partnership made the following cash distributions per unit during the years ended December 31, 2008 and 2007:

Distribution Date	Cash Distribution
	(per Unit)
November 14, 2008	$	0.4450
August 14, 2008		0.4450
May 14, 2008		0.4200
February 14, 2008		0.4000
November 14, 2007		0.3900
August 14, 2007		0.3800
May 15, 2007		0.3800
February 14, 2007		0.3700
November 14, 2006		0.3700
August 14, 2006		0.3500
May 15, 2006		0.2217

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 year ended December 31, 2008.

	For the Year Ended December 31, 2008
	Income (Numerator)		Units (Denominator)	Per-Unit Amount
	(in thousands except unit and per unit data)
Basic Earnings per Unit
Limited partner’s interest in net income	$	88,645	66,190,626	$	1.34
Effect of Dilutive Securities
Common unit options		—	30,580
Restricted common units		—	5,451
Class D common units		7,199	6,978,289
Class E common units		—	1,618,389
Diluted Earnings per Unit	$	95,844	74,823,335	$	1.28

Diluted earnings per unit equals basic because all instruments were antidilutive for the years ended December 31, 2007 and 2006. Loss per unit for the year ended December 31, 2006 reflects only the eleven months since the closing of the Partnership’s IPO on February 3, 2006. Accordingly, results for January 2006 have been excluded from the calculation of loss per unit.

In connection with the TexStar acquisition, the Partnership issued 5,173,189 of Class B common units to HMTF Gas Partners, an affiliate of HM Capital, which at the time owned a controlling interest in the Partnership. 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 B common units represents amounts earned by TexStar between the date of common control and the transaction date.

On September 21, 2006, the Partnership issued 2,857,143 Class C common units. The beneficial conversion feature is reflected in income per unit using the effective yield method over the period the Class C common units are outstanding, as indicated on the statements of operations in the line item entitled “beneficial conversion feature for Class C common units.”

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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 are 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.

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

	December 31, 2007	December 31, 2006
Restricted common units	397,500	516,500
Common unit options	738,668	909,600

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.

The Partnership adopted EITF 07-4, “Application of the Two-Class Method Under FASB Statement No. 128 to Master Limited Partnerships” and FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities.” These new accounting standards affect the earnings per unit calculation by limiting the amount of net income allocable to the incentive distribution rights (or “IDRs”) to the amount of cash actually paid to holders of the IDRs, and by requiring the calculation of earnings per unit on non-vested units awarded under a share-based compensation plan as a separate class of security. Further, the Partnership made an immaterial correction to the weighted average outstanding units for the twelve months ended December 31, 2008.

	2008				2007						2006
	As previously reported in the December 31, 2008 Form 10-K		As adjusted for adoption of new accounting principles		As previously reported in the December 31, 2008 Form 10-K			As adjusted for adoption of new accounting principles			As previously reported in the December 31, 2008 Form 10-K			As adjusted for adoption of new accounting principles
NET INCOME (LOSS) ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP	$	101,016	$	101,016	$	(13,836	)	$	(13,836	)	$	(7,244	)	$	(7,244	)
Less: Net income from January 1-31, 2006		—		—		—			—			1,564			1,564
Net income (loss) for partners		101,016		101,016		(13,836	)		(13,836	)		(8,808	)		(8,808	)
General partners’s interest in current period net income (loss), including IDR		9,967		4,303		(393	)		(366	)		(176	)		(164	)
Net income allocated to non-vested units		—		869		—			(103	)		—			(110	)
Amount allocated to Class B common units		—		—		—			—			(886	)		(886	)
Beneficial conversion feature for Class C common units		—		—		1,385			1,385			3,587			3,587
Beneficial conversion feature for Class D common units		7,199		7,199		—			—			—			—
Amount allocated to Class E common units		—		—		5,792			5,792			—			—
Limited partners’ interest in net income (loss)	$	83,850	$	88,645	$	(20,620	)	$	(20,544	)	$	(11,333	)	$	(11,235	)
Basic and Diluted earnings per unit:
Amount allocated to common and subordinated units	$	83,850	$	88,645	$	(20,620	)	$	20,544		$	(11,333	)	$	(11,235	)
Weighted average number of common and subordinated units outstanding		66,042,830		66,190,626		51,056,769			51,056,769			38,207,792			38,207,792
Basic income (loss) per common and subordinated unit	$	1.27	$	1.34	$	(0.40	)	$	(0.40	)	$	(0.30	)	$	(0.29	)
Diluted income (loss) per common and subordinated unit	$	1.24	$	1.28	$	(0.40	)	$	(0.40	)	$	(0.30	)	$	(0.29	)
Distributions per unit	$	1.71	$	1.71	$	1.52		$	1.52		$	0.9417		$	0.9417
Amount allocated to Class B common units	$	—	$	—	$	—		$	—		$	(886	)	$	(886	)
Weighted average number of Class B common units outstanding		—		—		651,964			651,964			5,173,189			5,173,189
Income per Class B common unit	$	—	$	—	$	—		$	—		$	(0.17	)	$	(0.17	)
Distributions per unit	$	—	$	—	$	—		$	—		$	—		$	—
Amount allocated to Class C common units	$	—	$	—	$	1,385		$	1,385		$	3,587		$	3,587
Total number of Class C common units outstanding		—		—		2,857,143			2,857,143			2,857,143			2,857,143
Income per Class C common unit	$	—	$	—	$	0.48		$	0.48		$	1.26		$	1.26
Distributions per unit	$	—	$	—	$	—		$	—		$	—		$	—
Amount allocated to Class D common units	$	7,199	$	7,199	$	—		$	—		$	—		$	—
Total number of Class D common units outstanding		7,276,506		7,276,506		—			—			—			—
Income per Class D common unit	$	0.99	$	0.99	$	—		$	—		$	—		$	—
Distributions per unit	$	—	$	—	$	—		$	—		$	—		$	—
Amount allocated to Class E common units	$	—	$	—	$	5,792		$	5,792		$	—		$	—
Total number of Class E common units outstanding		—		—		4,701,034			4,701,034			—			—
Income per Class E common unit	$	—	$	—	$	1.23		$	1.23		$	—		$	—
Distributions per unit	$	—	$	—	$	2.06		$	2.06		$	—		$	—

As previously disclosed in the December 31, 2007 Form 10-K, the Partnership identified and corrected an error in the calculation of earnings per unit resulting from the issuance of Class C common units at a discount. At the commitment date to sell the Class C common units the purchase price of $21.00 per unit represented a $1.74 discount from the fair value of the Partnership’s common units. Under EITF No. 98-5, “Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios,” the discount represented a beneficial conversion feature (“BCF”) that should have been treated as a non-cash distribution for purposes of calculating earnings per unit. The BCF is reflected in loss per unit using the effective yield method over the period the Class C common units are outstanding, as indicated on the statements of operations in the line item entitled “beneficial conversion feature for Class C common units”. The error is immaterial and had no impact on the Partnership’s net loss or partners’ capital.

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The following table depicts the effect on earnings per unit for the year ended December 31, 2006.

	As Previously Reported in the December 31, 2006 Form 10-K			As Restated in the December 31, 2007 Form 10-K*			As Adjusted for Adoption of New Accounting Standards**
NET LOSS	$	(7,244	)	$	(7,244	)	$	(7,244	)
Less: Net income from January 1-31, 2006		1,564			1,564			1,564
Net loss for partners		(8,808	)		(8,808	)	$	(8,808	)
General partner’s interest		(176	)		(176	)		(164	)
Net income allocated to non-vested units		—			—			(110	)
Amount allocated to Class B common units		(626	)		(886	)		(886	)
Beneficial conversion feature for Class C common units		—			3,587			3,587
Limited partners’ interest	$	(8,006	)	$	(11,333	)	$	(11,235	)
Basic and diluted earnings per unit:
Amount allocated to common and subordinated units	$	(8,006	)	$	(11,333	)	$	(11,235	)
Weighted average number of common and subordinated units outstanding		38,207,792			38,207,792			38,207,792
Loss per common and subordinated unit	$	(0.21	)	$	(0.30	)	$	(0.29	)
Distributions declared per unit	$	—		$	0.94		$	0.9417
Amount allocated to Class B common units	$	(626	)	$	(886	)	$	(886	)
Weighted average number of Class B common units outstanding		5,173,189			5,173,189			5,173,189
Loss per Class B common unit	$	(0.12	)	$	(0.17	)	$	0.17
Distributions declared per unit	$	—		$	—		$	—
Amount allocated to Class C common units	$	—		$	3,587		$	3,587
Total Class C common units outstanding		871,817			2,857,143			2,857,143
Income per Class C common unit due to beneficial conversion feature	$	—		$	1.26		$	1.26
Distributions declared per unit	$	—		$	—		$	—

* Amounts included in the consolidated statement of operations for the year ended December 31, 2007 have been recast for as-if pooling accounting treatment for the FrontStreet Acquisition.

** Amounts have been recast for the retrospective adoption of EITF 07-04 and FSP EITF 03-6-1.

5. Acquisitions and Dispositions

2008

FrontStreet. On January 7, 2008, the Partnership acquired all of the outstanding equity and noncontrolling interest of FrontStreet from ASC and EnergyOne, which is further described in Note 1, Organization and Basis of Presentation.

CDM Resource Management, Ltd. On January 15, 2008, the Partnership and an indirect wholly owned subsidiary of the Partnership (“Merger Sub”) consummated an agreement and plan of merger (the “Merger Agreement”) with CDM Resource Management, Ltd. CDM provides its customers with turn-key natural gas contract compression services to maximize their natural gas and crude oil production, throughput, and cash flow in Texas, Louisiana, and Arkansas. The Partnership operates and manages CDM as a separate reportable segment.

The total purchase price paid by the Partnership for the partnership interests of CDM consisted of (a) the issuance of an aggregate of 7,276,506 Class D common units of the Partnership, which were valued at $219,590,000 and (b) an aggregate of $478,445,000 in cash, $316,500,000 of which was used to retire CDM’s debt obligations. Of the Class D common units issued, 4,197,303 Class D common units were deposited with an escrow agent pursuant to an escrow agreement. Such common units constitute security to the Partnership for a period of one year after the closing with respect to any obligations under the Merger Agreement, including obligations for breaches of representation, warranties and covenants.

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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-progress		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. On March 25, 2008, the Partnership acquired Nexus (“Nexus Acquisition”) by merger for $88,486,000 in cash, including customary closing adjustments and direct transaction costs. Nexus Gas Partners LLC, the sole member of Nexus prior to the merger (“Nexus Member”), deposited $8,500,000 in an escrow account as security to the Partnership for a period of one year against indemnification obligations and any purchase price adjustment. The Partnership funded the Nexus Acquisition through borrowings under its existing revolving 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

Upon consummation of the Nexus Acquisition, the Partnership acquired Nexus’ rights under a Purchase and Sale Agreement (the “Sonat Agreement”) between Nexus and Sonat. Pursuant to the Sonat Agreement, Nexus will purchase 136 miles of pipeline from Sonat (the “Sonat Asset Acquisition”) that could facilitate the Nexus gathering system’s integration into the Partnership’s north Louisiana asset base. The Sonat Asset Acquisition is subject to abandonment approval and jurisdictional redetermination by the FERC, as well as customary closing conditions. Upon closing of the Sonat Asset Acquisition, the Partnership will pay Sonat $27,500,000, and, if the closing occurs on or prior to March 1, 2010, on certain terms and conditions as provided in the Merger Agreement, the Partnership will make an additional payment of $25,000,000 to the Nexus Member.

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

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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 Midcontinent 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 twenty 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. On April 2, 2007, the Partnership and its indirect wholly-owned subsidiary, Pueblo Holdings, acquired all the outstanding equity of Pueblo. Pueblo owned and operated natural gas gathering, treating and processing assets located in south Texas. These assets are comprised of a 75 MMcf/d gas processing and treating facility, 33 miles of gathering pipelines and approximately 6,000 horsepower of compression.

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 revolving credit facility.

The Pueblo Acquisition offers the opportunity to reroute gas to one of the Partnership’s existing gas processing plants which is expected 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
Total assets acquired	$	65,313
Current liabilities		(1,187	)
Long-term liabilities		(9,492	)
Total purchase price	$	54,634

2006

TexStar. On August 15, 2006, the Partnership acquired all the outstanding equity of TexStar by issuing 5,173,189 Class B common units valued at $119,183,000, a cash payment of $62,074,000 and the assumption of $167,652,000 of TexStar’s outstanding bank debt. Because the TexStar Acquisition is a transaction between commonly controlled entities, the Partnership accounted for the TexStar Acquisition in a manner similar to a

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pooling of interests. As a result, the historical financial statements of the Partnership and TexStar have been combined to reflect the historical operations, financial position and cash flows from the date common control began (December 1, 2004) forward.

The following table presents the revenues and net income for the previously separate entities and the combined amounts presented in these audited consolidated financial statements.

	Year Ended December 31, 2006
	(in thousands)
Revenue
Regency Energy Partners	$	812,564
TexStar Field Services		84,301
Combined	$	896,865
Net Loss
Regency Energy Partners	$	(1,639	)
TexStar Field Services		(5,605	)
Combined	$	(7,244	)

Como. On July 25, 2006, TexStar acquired certain natural gas gathering, treating and processing assets from the other parties for $81,695,000 including transaction costs. The assets acquired consisted of approximately 59 miles of pipelines and certain specified contracts (the “Como Assets”). The results of operations of the Como Assets have been included in the statements of operations beginning July 26, 2006. The Partnership’s purchase price allocation resulted in $18,493,000 being allocated to property, plant and equipment and $63,202,000 being allocated to intangible assets.

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The following unaudited pro forma financial information has been prepared as if the acquisitions of FrontStreet, CDM, Nexus, Pueblo and Como had occurred as of the beginning of the periods 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,
	2008		2007			2006
	(in thousands except unit and per unit data)
Revenue	$	1,871,011	$	1,317,365		$	952,229
Net income (loss) attributable to Regency Energy Partners LP		102,830		(6,913	)		(6,876	)
Less net income from January 1 – 31, 2006		—		—			1,564
Net income (loss) for partners		102,830		(6,913	)		(8,440	)
Less:
General partner’s interest in current period net income (loss), including IDR		4,340		(228	)		(156	)
Net income allocated to non-vested units		886		(100	)		(105	)
Amount allocated to Class B common units		—		—			(886	)
Beneficial conversion feature for Class C common units		—		1,385			3,587
Beneficial conversion feature for Class D common units		7,199		—			—
Amount allocated to Class E common units		—		5,792			—
Limited partners’ interest in net income (loss)	$	90,405	$	(13,762	)	$	(10,880	)
Basic and Diluted earnings per unit:
Amount allocated to common and subordinated units	$	90,405	$	(13,762	)	$	(10,880	)
Weighted average number of common and subordinated units outstanding		66,190,626		51,056,769			38,207,792
Basic income (loss) per common and subordinated unit	$	1.37	$	(0.27	)	$	(0.28	)
Diluted income (loss) per common and subordinated unit	$	1.30	$	(0.27	)	$	(0.28	)
Distributions per unit	$	1.71	$	1.52		$	0.9417
Amount allocated to Class B common units	$	—	$	—		$	(886	)
Weighted average number of Class B common units outstanding		—		651,964			5,173,189
Income per Class B common unit	$	—	$	—		$	(0.17	)
Distributions per unit	$	—	$	—		$	—
Amount allocated to Class C common units	$	—	$	1,385		$	3,587
Total number of Class C common units outstanding		—		2,857,143			2,857,143
Income per Class C common unit due to beneficial conversion feature	$	—	$	0.48		$	1.26
Distributions per unit	$	—	$	—		$	—
Amount allocated to Class D common units	$	7,199	$	—		$	—
Total number of Class D common units outstanding		7,276,506		—			—
Income per Class D common unit due to beneficial conversion feature	$	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		$	—

6. Risk Management Activities

The net fair value of the Partnership’s risk management activities constituted a net asset of $67,540,000 at December 31, 2008 and a net liability of $52,925,000 at December 31, 2007. The Partnership expects to

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reclassify $53,047,000 of net hedging gains to revenues or interest expense from accumulated other comprehensive income (loss) in the next twelve months. The Partnership recorded $15,655,000 of net mark-to-market gains for the year ended December 31, 2008 and $14,559,000 of mark-to-market losses for the year ended December 31, 2007 for certain hedges that, did not initially, or do not qualify for hedge accounting. The Partnership also recognized $545,000 of ineffectiveness gain for the year ended December 31, 2008 and $486,000 of ineffectiveness loss for the year ended December 31, 2007.

In the year ended December 31, 2008, the Partnership recorded in net realized and unrealized loss from risk management activities $1,500,000 of losses associated with its credit risk assessment in accordance with SFAS No. 157, “Fair Value Measurements” (“SFAS 157”).

The Partnership’s hedging positions help reduce exposure to variability of future commodity prices through 2010 and future interest rates on $300,000,000 of long-term debt under its revolving credit facility through March 5, 2010, the date the interest rate swaps expire.

Effective June 19, 2007, the Partnership elected to account for all outstanding commodity hedging instruments on a mark-to-market basis except for the portion pursuant to which all NGL products for a particular year were hedged and the hedging relationship was, for accounting purposes, effective. At December 31, 2008, the Partnership has the following commodity hedging programs that qualify for hedge accounting: the 2009 NGL, natural gas and West Texas Intermediate crude oil hedging programs and the 2010 West Texas Intermediate crude oil hedging program.

In March 2008, the Partnership entered offsetting trades against its existing 2009 NGL portfolio of mark-to-market hedges, which it believes will substantially reduce the volatility of its 2009 NGL hedges. This group of trades, along with the pre-existing 2009 NGL portfolio, will continue to be accounted for on a mark-to-market basis. Simultaneously, the Partnership executed additional 2009 NGL swaps which were designated under SFAS 133 as cash flow hedges. In May 2008, the Partnership entered into commodity swaps to hedge a portion of its 2010 NGL commodity risk, except for ethane, which are accounted for using mark-to-market accounting.

The Partnership accounts for a portion of its 2008 and, prior to August 2008, accounted for all of its 2009 West Texas Intermediate crude oil swaps using mark-to-market accounting. In August 2008, the Partnership entered into an offsetting trade against its existing 2009 West Texas Intermediate crude oil swap to minimize the volatility of the original 2009 swap. Simultaneously, the Partnership executed an additional 2009 West Texas Intermediate crude oil swap, which was designated under SFAS No. 133 as a cash flow hedge. In May 2008, the Partnership entered into a West Texas Intermediate crude oil swap to hedge its 2010 condensate price risk, which was designated as a cash flow hedge in June 2008.

On December 2, 2008, the Partnership entered into two natural gas swaps to hedge its equity exposure to natural gas for calendar year 2009. These natural gas swaps were designated as cash flow hedges under SFAS 133 on December 2, 2008.

On February 29, 2008, the Partnership entered into two-year interest rate swaps related to $300,000,000 of borrowings under its revolving credit facility, effectively locking the base rate for these borrowings at 2.4 percent, plus the applicable margin (1.5 percent as of December 31, 2008) through March 5, 2010. These interest rate swaps were designated as cash flow hedges in March 2008.

Upon the early termination of an interest rate swap with a notional debt amount of $200,000,000 that was effective from April 2007 through March 2009, the Partnership received $3,550,000 in cash from the counterparty. The Partnership reclassified $1,078,000 and $2,663,000 from accumulated other comprehensive income (loss), reducing interest expense, net in the year ended December 31, 2007 and 2006, respectively, because the hedged forecasted transaction will not occur.

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7. Long-term Debt

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

	December 31, 2008			December 31, 2007
	(in thousands)
Senior notes	$	357,500		$	357,500
Revolving loans		768,729			124,000
Total		1,126,229			481,500
Less: current portion		—			—
Long-term debt	$	1,126,229		$	481,500
Availability under revolving credit facility:
Total credit facility limit	$	900,000		$	500,000
Unfunded Lehman commitments		(8,646	)		—
Revolving loans		(768,729	)		(124,000	)
Letters of credit		(16,257	)		(27,263	)
Total available	$	106,368		$	348,737

Long-term debt maturities as of December 31, 2008 for each of the next five years are as follows.

Year Ending December 31,	Amount
	(in thousands)
2009	$	—
2010		—
2011		768,729
2012		—
2013		357,500
Thereafer		—
Total	$	1,126,229

In the year ending December 31, 2008, the Partnership borrowed $844,729,000 under its revolving credit facility; these borrowings were made primarily to fund capital expenditures. During the same period, the Partnership repaid $200,000,000 with proceeds from an equity offering. In the years ending December 31, 2007 and 2006, the Partnership borrowed $283,230,000 and $195,300,000 respectively; these funds were used primarily to finance capital expenditure projects and to temporary finance the TexStar acquisition. During the same period, the Partnership repaid $421,430,000 and $180,600,000 of these borrowings with proceeds from private equity offering and term loans.

Senior Notes. In 2006, the Partnership and Finance Corp. issued $550,000,000 senior notes that mature on December 15, 2013 in a private placement (“senior notes”). 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 its outstanding senior notes on or before December 15, 2009. Under the senior notes terms, no further redemptions are permitted until December 15, 2010. The Partnership made the redemption at a price of 108.375 percent of the principal amount plus accrued interest. Accordingly, a redemption premium of $16,122,000 was recorded as loss on debt refinancing and unamortized loan origination costs of $4,575,000 were written off and charged to loss on debt refinancing in the year ended December 31, 2007. A portion of the proceeds of an equity offering was used to redeem the senior notes. In September 2007, the Partnership exchanged its then outstanding 8.375 percent senior notes which were not registered under the Securities Act of 1933 for senior notes with identical terms that have been so registered.

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,

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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. does not guarantee the Senior Notes and does not have any operations of any kind and will not have any revenue other than as may be incidental as a co-issuer of the Senior Notes. The Partnership has no independent operations, the guarantees are full and unconditional and joint and several, and there are no subsidiaries of the Partnership other than Finance Corp. that do not guarantee the Senior Notes. The Partnership has not included condensed consolidated financial information of guarantors of the Senior Notes in accordance with Rule 3-10 of Regulation S-X.

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The Partnership may redeem the 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. At any time before December 15, 2010, the Partnership may redeem some or all of the notes at a redemption price equal to 100 percent of the principal amount plus a make-whole premium, plus accrued and unpaid interest and liquidated damages, if any, to the redemption date.

Upon a change of control, each holder of notes will be entitled to require us to purchase all or a portion of its notes at a purchase price equal to 101 percent of the principal amount thereof, plus accrued and unpaid interest and liquidated damages, if any, to the date of purchase. The Partnership’s ability to purchase the notes upon a change of control will be limited by the terms of the Partnership’s debt agreements, including the Credit Facility. Subsequent to the GE EFS Acquisition, no bond holder has exercised this option.

The senior notes contain covenants that, among other things, limit the Partnership’s ability and the ability of certain of the Partnership’s subsidiaries to: (i) incur additional indebtedness; (ii) pay distributions on, or repurchase or redeem equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into certain types of transactions with affiliates; and (vi) sell assets or 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 and its restricted subsidiaries will no longer be subject to many of the foregoing covenants.

Fourth Amended and Restated Credit Agreement. At December 31, 2007, RGS’ Fourth Amended and Restated Credit Agreement (“Credit Facility”) allowed for borrowings of $600,000,000 in term loans and $500,000,000 in a revolving credit facility. The availability for letters of credit was increased to $100,000,000. RGS has the option to increase the commitments under the revolving credit facility or the term loan facility, or both, by an amount up to $250,000,000 in the aggregate, provided that no event of default has occurred or would result due to such increase, and all other additional conditions for the increase in commitments have been met. On January 15, 2008, the revolving credit facility under the Credit Facility was expanded to $750,000,000 and on February 13, 2008, the revolving credit facility under the Credit Facility was expanded to $900,000,000. The Partnership 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. 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 of December 31, 2008, the Partnership borrowed all but $8,646,000 of the amount committed by Lehman under the Credit Facility. Lehman has declined requests to honor its remaining commitment, effectively reducing the total size of the Credit Facility’s capacity to $891,354,000. Further, if the Partnership makes repayments of loans against the revolving facility which were, in part, funded by Lehman, the amounts funded by Lehman may not be reborrowed. Further information on the status of Lehman’s commitment is described in Note 16, Subsequent Events.

The outstanding balance of revolving debt 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,

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commitment fees, and amortization of debt issuance costs were 6.27 percent, 8.78 percent and 7.70 percent for the years ended December 31, 2008, 2007, and 2006, respectively. The senior notes bear interest at a fixed rate of 8.375 percent.

RGS must pay (i) a commitment fee equal to 0.30 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 1.50 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 EBITDA and EBITDA to interest expense within certain threshold ratios. At December 31, 2008 and 2007, 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 Credit Facility also contains various covenants that limit (subject to certain exceptions and negotiated baskets), among other things, the ability of RGS (but not the Partnership):

• to incur indebtedness;

• to grant liens;

• enter into sale and leaseback transactions;

• to make certain investments, loans and advances;

• to dissolve or enter into a merger or consolidation;

• to enter into asset sales or make acquisitions;

• to enter into transactions with affiliates;

• to prepay other indebtedness or amend organizational documents or transaction documents (as defined in the Credit Facility);

• to issue capital stock or create subsidiaries; or

• to 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.

The Partnership treated the amendment of the Credit Facility as an extinguishment and reissuance of debt, and therefore recorded a charge to loss on debt refinancing of $5,626,000 in the year ended December 31, 2006.

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8. 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, 2007	$	10,247		$	66,676		$	—		$	—		$	76,923
Additions		—			5,242			—			—			5,242
Disposals		(108	)		—			—			—			(108	)
Amortization		(771	)		(3,482	)		—			—			(4,253	)
Balance at December 31, 2007		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

The weighted average remaining amortization periods for permits and licenses, contracts, trade names, and customer relations are 10.9, 17.6, 14.1 and 18.3 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)
2009	$	12,453
2010		12,359
2011		11,101
2012		10,808
2013		10,808

Goodwill. Goodwill activity consists of the following.

	Gathering and Processing		Transportation		Contract Compression		Total
Balance at January 1, 2007	$	23,309	$	34,243	$	—	$	57,552
Additions		36,523		—		—		36,523
Balance at December 31, 2007		59,832		34,243		—		94,075
Additions		3,401		—		164,882		168,283
Balance at December 31, 2008	$	63,233	$	34,243	$	164,882	$	262,358

9. Fair Value Measures

On January 1, 2008, the Partnership adopted the provisions of SFAS 157 for financial assets and liabilities. SFAS 157 became effective for financial assets and liabilities on January 1, 2008. On January 1, 2009, the Partnership will apply the provisions of SFAS 157 for non-recurring fair value measurements of non-financial assets and liabilities, such as goodwill, indefinite-lived intangible assets, property, plant and equipment and asset retirement obligations. SFAS 157 defines fair value, thereby eliminating inconsistencies in guidance found in various prior accounting pronouncements, and increases disclosures surrounding fair value calculations.

SFAS 157 establishes 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 markets accessible by the Partnership;

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• 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.

SFAS 157 encourages entities 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.

The Partnership’s financial assets and liabilities measured at fair value on a recurring basis are risk management assets and liabilities related to interest rate and commodity swaps. Risk management assets and liabilities 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. The Partnership has no financial assets and liabilities as of December 31, 2008 valued based on inputs classified as Level 3 in the hierarchy.

The estimated fair value of financial instruments was determined using available market information and valuation methodologies. 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. Risk management assets and liabilities are carried at fair value. Long-term debt other than the senior notes was comprised of borrowings under which, at December 31, 2008 and 2007, accrued interest under a floating interest rate structure. Accordingly, the carrying value approximates fair value for the long term debt amounts outstanding. The estimated fair value of the senior notes based on third party market value quotations was $244,887,500 and $367,778,000 as of December 31, 2008 and 2007, respectively.

10. Leases

The Partnership leases office space and certain equipment for various periods and determined that these leases are operating leases. The following table is a schedule of future minimum lease payments for operating leases that had initial or remaining noncancelable lease terms in excess of one year as of December 31, 2008.

For the year ended December 31,	Operating		Capital
	(in thousands)
2009	$	2,357	$	612
2010		2,526		593
2011		2,348		422
2012		1,926		448
2013		1,262		462
Thereafter		5,506		7,562
Total minimum lease payments	$	15,925		10,099
Less: Amount representing estimated executory costs (such as maintenance and insurance), including profit thereon, included in minimum capital lease payments				1,972
Net minimum capital lease payments				8,127
Less: Amount representing interest				4,742
Present value of net minimum capital lease payments			$	3,385

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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 balance sheet.

	December 31, 2008
	(in thousands)
Gross amount included in gathering and transmission systems	$	3,000
Gross amount included in other property and equipment		560
Less accumulated amortization		(421	)
	$	3,139
Current obligation under capital lease	$	535
Noncurrent obligation under capital lease		2,850
	$	3,385

Total rent expense for operating leases, including those leases with terms of less than one year, was $2,576,000, $1,597,000, and $1,721,000 for the years ended December 31, 2008, 2007, and 2006, respectively.

11. Commitments and Contingencies

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

Construction and Operating Agreement. Prior to the acquisition of FrontStreet by the Partnership, FrontStreet entered into a construction and operation agreement (“C&O Agreement”) contract with a third party. Under the terms of the C&O Agreement, the third party is responsible for operating, maintaining and repairing the FrontStreet gathering system. Subject to prior approval, the Partnership is responsible for paying for capital additions and expenses incurred by the operator of the FrontStreet gathering system. The C&O Agreement shall remain in effect until such time as the gathering agreement (discussed below) terminates or the third party is removed as operator in accordance with terms of the C&O Agreement.

The C&O Agreement also requires the third party to comply with all applicable environmental standards. While the Partnership would be responsible for any environmental contamination as a result of the operation of the FrontStreet gathering system, remedies are provided to the Partnership under the C&O Agreement allowing it to recover costs incurred to remediate a contaminated site. Additionally, the C&O Agreement states that the Partnership is specifically responsible for the removal, remediation, and abatement of Polychlorinated Biphenyls (“Remediation Work”). However, under the terms of the C&O Agreement, the Partnership can include up to $2,200,000 of expenditures for Remediation Work related to conditions in existence prior to October 1994. The Partnership has obtained an indemnification against any environmental losses for preexisting conditions prior to the acquisition date from the previous owner. The Partnership has escrowed $750,000 in the event the third party does not agree to include in the cost of service expenditures for Remediation Work. The C&O Agreement shall remain in effect until such time as the gathering agreement (discuss below) terminates or the third party is removed as operator in accordance with terms of the C&O Agreement. In 2008, the Partnership was reimbursed for all the remediation work done and pursuant to the C&O Agreement the escrow balance was released to the previous owners.

Gathering Agreement. Prior to the acquisition of FrontStreet by the Partnership, FrontStreet has entered into a gathering agreement (“Gathering Agreement”) contract into with a third party, whereby the third party dedicates for gathering by the FrontStreet gathering system all of the commercially producible gas in a defined list of producing fields. The Gathering Agreement allows the Partnership to charge a per unit gathering fee (the “Gathering Fee”) calculated on estimated cost of service over the total estimated units to be transported in a calendar year. The Gathering Fee is predetermined for a calendar year by November 7 of the preceding calendar year and then subject to redetermination on June 7. As part of the redetermination process, the Gathering Fee is

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trued-up, inclusive of interest, based on actual costs incurred including abandonment costs and actual units transported. The term of the Gathering Agreement is for as long as gas is capable of being produced in commercial quantities, subject to certain exceptions in the event of an ownership change of the gas field, or the removal of the third party as operator of the FrontStreet gathering system.

Annual Settlement Payment Agreement. The Partnership and the third party are also parties to an annual settlement payment agreement (“ASPA”) which provides the Partnership with a fixed return on its investment in the FrontStreet gathering system. The ASPA also provides the mechanism for recovery of the costs of current period Remediation Work. The amount due under the ASPA is calculated monthly, inclusive of interest. Payments under the ASPA for a calendar year are due on the following March 15. The term of the ASPA is the same as the Gathering Agreement.

Escrow Payable. At December 31, 2008, $1,510,000 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. In the El Paso PSA, El Paso indemnified the predecessor of our operating partnership, RGS, 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.

In January 2008, pursuant to authorization by the Board of Directors of the General Partner, the Partnership agreed to settle the El Paso environmental remediation. Under the settlement, El Paso will clean up and obtain “no further action” letters from the relevant state agencies for three Partnership-owned facilities. El Paso is not obligated to clean up properties leased by the Partnership, but it indemnified the Partnership for pre-closing environmental liabilities. All sites for which the Partnership made environmental claims against El Paso are either addressed in the settlement or have already been resolved. In May 2008, the Partnership released all but $1,500,000 from the escrow fund maintained to secure El Paso’s obligations. This amount will be further reduced under a specified schedule as El Paso completes its cleanup obligations and the remainder will be released upon completion.

Nexus Escrow. At December 31, 2008, $8,521,000 is included in an escrow account as security to the Partnership for a period of one year against indemnification obligations and any purchase price adjustments related to the Nexus Acquisition.

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.

TCEQ Notice of Enforcement. On February 15, 2008, the TCEQ issued a NOE concerning one of the Partnership’s processing plants located in McMullen County, Texas (the “Plant”). The NOE alleges that, between March 9, 2006, and May 8, 2007, the 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. On April 3, 2008, TCEQ presented the Partnership with a written offer to settle the allegation in the NOE in exchange for payment of an administrative penalty of $480,000, and it later reduced its settlement demand to $360,000 in July 2008. The Partnership was unable to settle this matter on a satisfactory basis and the TCEQ has referred the matter to its litigation division for further administrative proceedings.

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Contingent Purchase of Sonat Assets. In March of 2008, the Partnership, through the Nexus Acquisition, obtained the rights to a contingent commitment to purchase 136 miles of pipeline that could facilitate the Nexus’ system integration into the Partnership’s north Louisiana asset base. The purchase commitment is contingent upon the FERC declaring that the pipeline is no longer subject to its jurisdiction, together with approval of the current owner’s abandonment and other customary closing conditions. In the event that all contingencies are satisfactorily resolved, the Partnership will pay Sonat $27,500,000. Furthermore, if the closing occurs on or prior to March 1, 2010, the Partnership will pay an additional $25,000,000 to the sellers, subject to certain terms and conditions.

On April 3, 2008, Sonat filed an application with the FERC seeking authorization to abandon by sale to Nexus 136 miles of pipeline and related facilities. The application also requested a determination that the facilities being sold to Nexus be considered non-jurisdictional, with certain facilities being gathering and certain facilities being intrastate transmission. Four producers submitted letters in support of the application and several Sonat shippers protested the application. The matter is currently pending.

Keyes Litigation. In August 2008, Keyes Helium Company, LLC (“Keyes”) filed suit against Regency Gas Services LP, the Partnership, and the General Partner. Keyes entered into an output contract with the Partnership’s predecessor in 1996 under which it purchased all of the helium produced at the Lakin processing plant in southwest Kansas. 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 of which the Partnership no longer delivered any helium to Keyes. As a result, Keyes alleges it is entitled to an unspecified amount of damages for the costs of covering its purchases of helium. The Partnership filed an answer to this lawsuit and plans to defend itself vigorously.

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. If the Kansas Department of Revenue determines that the condensate sales are taxable, then the Partnership may be subject to additional taxes for past and future condensate sales.

Purchase Commitments. At December 31, 2008, the Partnership has purchase obligations totaling approximately $323,341,000, of which $104,852,000 relate to the purchase of major compression components unrelated to the Haynesville Expansion Project, that extend until the year ending December 31, 2010 and $218,489,000 of commitments related to the Haynesville Expansion Project that extend until the year ending December 31, 2009. Some of these commitments have cancellation provisions. See Note 16, Subsequent Events, for more information regarding the operating lease facility that we may use to finance the acquisition of compression equipment in 2009.

12. Related Party Transactions

Concurrent with the closing of the Partnership’s IPO, the Partnership paid $9,000,000 to an affiliate of HM Capital Partners to terminate a management services contract with a remaining term of nine years. TexStar paid $361,000 to HM Capital Partners for the year ended December 31, 2006 in relation to a management services contract. In connection with the TexStar Acquisition, the Partnership paid $3,542,000 to terminate TexStar’s management services contract.

BBOG is a natural gas producer on the Partnership’s gas gathering and processing system. At the time of the TexStar Acquisition, BBOG entered into an agreement providing for the long term dedication of the production from its leases to the Partnership. In July 2007, BBOG sold its interest in the largest of these leases to an

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unrelated third party. BBE is the lessee of office space in the south Texas region where the Partnership subleased offices for which it paid $151,000 and $70,000 in the years ended December 31, 2007 and 2006, respectively.

Concurrent with the TexStar Acquisition, a $600,000 promissory note was repaid in full. TexStar paid a transaction fee in the amount of $1,200,000 to an affiliate of HM Capital Partners upon completing its acquisition of the Como Assets. This amount was capitalized as a part of the purchase price.

In conjunction with distributions by the Partnership for limited and general partner interests, HM Capital Partners and affiliates received cash distributions of $10,308,000, $24,392,000, and $20,139,000 during the years ended December 31, 2008, 2007, and 2006, respectively, as a result of their ownership interests in the Partnership.

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.

Under an omnibus agreement, Regency Acquisition LP, the entity that formerly owned the General Partner, agreed to indemnify the Partnership in an aggregate not to exceed $8,600,000, generally for three years after February 3, 2006, for certain environmental noncompliance and remediation liabilities associated with the assets transferred to the Partnership and occurring or existing before that date. To date, no claims have been made against the omnibus agreement. On February 3, 2009, the omnibus agreement expired, with no claims having been filed.

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, our General Partner receives a monthly reimbursement for all direct and indirect expenses incurred on behalf of the Partnership. Reimbursements of $26,899,000, $27,628,000, and $16,789,000 were recorded in the Partnership’s financial statements during the years ended December 31, 2008, 2007, and 2006, 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. In the year ending December 31, 2008, three senior management members resigned from their positions, thus effectively reducing management interest in the General Partner to 3.8 percent.

GE EFS and certain members of the Partnership’s management made a capital contribution aggregating to $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, 2008 and 2007, respectively.

In conjunction with distributions by the Partnership to its limited and general partner interests, GE EFS and affiliates received cash distributions of $35,054,000 and $14,592,000 during the year ended December 31, 2008 and 2007, respectively, as result of their ownership interests in the Partnership.

In conjunction with distributions by the Partnership to its limited and general partner interests, certain members of management received cash distributions of $1,887,000 in the year ended December 31, 2008 as a result of their ownership interests in the Partnership.

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.

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The Partnership’s contract compression segment provides contract compression services to CDM MAX LLC, a related party. The Partnership’s related party receivables and payables as of December 31, 2008 relate to CDM MAX LLC.

13. 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 10 percent or more of revenues or cost of gas and liquids are disclosed below, together with the identity of the reporting segment.

		Year Ended
	Reportable Segment	December 31, 2008		December 31, 2007		December 31, 2006
		(in thousands)
Customer
Customer A	Transportation		*		*	$	89,736
Supplier
Supplier A	Transportation	$	75,464	$	157,046		*
Supplier A	Gathering and Processing		243,075		*		*
Supplier B	Gathering and Processing		*		*		67,751

* Amounts are less than 10 percent of the total revenues 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.

14. Segment Information

The Partnership’s management realigned the composition of its segments as a result of the formation of the Haynesville Joint Venture. Accordingly, the Partnership has restated the items of segment information for all periods presented to reflect this new alignment.

The Partnership has three principal reportable segments: (a) gathering and processing, (b) transportation, and (c) contract compression. 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. Revenues 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.

The transportation segment consists exclusively the Partnership’s wholly owned subsidiary of Regency Intrastate Gas Pipeline. The transportation segment uses pipelines to transport natural gas from receipt points on its system to interconnections with larger pipelines or trading hubs and other markets. RIGS performs transportation services for shipping customers under firm or interruptible arrangements. In either case, revenues are primarily fee based and involve minimal direct exposure to commodity price fluctuations. RIGS also purchases natural gas at the inlets to the pipeline and sells this gas at its outlets. 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 revenues 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 Partnership’s fourth reportable segment, corporate and others, comprises a small regulated interstate pipeline and the Partnership’s corporate offices. Revenues in this segment derive from the operations of the regulated interstate pipeline, which prior to the realignment of the segments, was reported within the transportation segment.

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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 revenues, including service fees, less cost of sales. In the contract compression segment, segment margin is defined as revenues 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 revenues in calculating segment margin because management separately evaluates commodity volume and price changes in segment margin.

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
Year ending December 31, 2008	$	1,689,728	$	40,713		$	132,549	$	814		$	—		$	1,863,804
Year ending December 31, 2007		1,169,032		20,437			—		769			—			1,190,238
Year ending December 31, 2006		863,628		32,741			—		496			—			896,865
Intersegment Revenue
Year ending December 31, 2008		—		13,576			4,573		—			(18,149	)		—
Year ending December 31, 2007		—		28,098			—		—			(28,098	)		—
Year ending December 31, 2006		—		6,600			—		—			(6,600	)		—
Cost of Sales
Year ending December 31, 2008		1,422,889		(26,175	)		11,619		—			—			1,408,333
Year ending December 31, 2007		1,088,517		(32,111	)		—		(261	)		—			976,145
Year ending December 31, 2006		748,725		(8,047	)		—		(232	)		—			740,446
Segment Margin
Year ending December 31, 2008		266,839		66,888			125,503		814			(4,573	)		455,471
Year ending December 31, 2007		160,515		52,548			—		1,030			—			214,093
Year ending December 31, 2006		114,903		40,788			—		728			—			156,419
Operation and Maintenance
Year ending December 31, 2008		82,689		3,540			49,799		74			(4,473	)		131,629
Year ending December 31, 2007		53,496		4,407			—		97			—			58,000
Year ending December 31, 2006		35,008		4,415			—		73			—			39,496
Depreciation and Amortization
Year ending December 31, 2008		58,900		14,099			28,448		1,119			—			102,566
Year ending December 31, 2007		40,309		13,457			—		1,308			—			55,074
Year ending December 31, 2006		26,831		11,897			—		926			—			39,654
Assets
December 31, 2008		1,101,906		325,310			881,552		149,871			—			2,458,639
December 31, 2007		935,794		278,949			—		63,667			—			1,278,410
Goodwill
December 31, 2008		63,233		34,243			164,882		—			—			262,358
December 31, 2007		59,832		34,243			—		—			—			94,075
Expenditures for Long-Lived Assets
Year ending December 31, 2008		124,736		59,231			186,063		5,053			—			375,083
Year ending December 31, 2007		112,813		15,658			—		1,313			—			129,784
Year ending December 31, 2006		192,115		29,785			—		1,750			—			223,650

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The table below provides a reconciliation of total segment margin to net income (loss) attributable to Regency Energy Partners LP.

	Year Ended
	December 31, 2008			December 31, 2007			December 31, 2006
	(in thousands)
Net income (loss) attributable to Regency Energy Partners LP	$	101,016		$	(13,836	)	$	(7,244	)
Add (deduct):
Operation and maintenance		131,629			58,000			39,496
General and administrative		51,323			39,713			22,826
Loss on asset sales		472			1,522			—
Management services termination fee		3,888			—			12,542
Transaction expenses		1,620			420			2,041
Depreciation and amortization		102,566			55,074			39,654
Interest expense, net		63,243			52,016			37,182
Loss on debt refinancing		—			21,200			10,761
Other income and deductions, net		(332	)		(1,252	)		(839	)
Income tax expense		(266	)		931			—
Net income attributable to the noncontrolling interest		312			305			—
Total segment margin	$	455,471		$	214,093		$	156,419

15. Equity-Based Compensation

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 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 $4,318,000, $15,534,000, and $2,906,000 is recorded in general and administrative in the statement of operations for the years ended December 31, 2008, 2007, and 2006, 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 common units on a net basis. During the year ended December 31, 2008, two former executives of the Partnership exercised 135,000 unit options. Since there were no options granted during the year ended December 31, 2008, the following assumptions apply to the options granted during the years ended December 31, 2007 and 2006.

	Year Ended
	December 31, 2007			December 31, 2006
Weighted average expected life (years)		4			4
Weighted average expected dividend per unit	$	1.51		$	1.40
Weighted average grant date fair value of options	$	2.31		$	1.32
Weighted average risk free rate		4.60	%		4.25	%
Weighted average expected volatility		16.0	%		15.0	%
Weighted average expected forfeiture rate		11.0	%		5.0	%

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The common unit options activity for the years ending December 31, 2008, 2007, and 2006 is as follows.

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

2006
Common Unit Options	Units		Weighted Average Exercise Price		Weighted Average Contractual Term (Years)	Aggregate Intrinsic Value *(in thousands)
Outstanding at the beginning of period	—		$	—
Granted	943,900			21.05
Exercised	—			—
Forfeited or expired	(34,300	)		21.75
Outstanding at end of period	909,600			21.06	9.3	$	5,522
Exercisable at the end of the period	—			—			—

* 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.

The Partnership will make distributions to non-vested restricted common units at the same rate 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 $14,856,000 of compensation expense related to the grants under LTIP primarily over the next three years.

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The restricted (non-vested) common unit activity for the years ending December 31, 2008, 2007, and 2006 is as follows.

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
2006
Restricted (Non-Vested) Common Units	Units		Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period	—		$	—
Granted	516,500			21.06
Vested	—			—
Forfeited or expired	—			—
Outstanding at the end of period	516,500			21.06

16. Subsequent Events

Partner Distributions. On January 27, 2009, the Partnership declared a distribution of $0.445 per common and subordinated unit including units equivalent to the General Partner’s two percent interest in the Partnership, and an aggregate distribution of $577,000 with respect to incentive distribution rights, payable on February 13, 2009 to unitholders of record at the close of business on February 6, 2009.

On April 27, 2009, 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 $634,000, with respect to incentive distribution rights, payable on May 14, 2009 to unitholders of record at the close of business on May 7, 2009.

On February 9, 2009 and February 17, 2009, 7,276,506 Class D and 19,103,896 subordinated units, respectively, converted into common units on a one for one basis.

Joint Venture Formation. On March 17, 2009, the Partnership announced the completion of the transactions contemplated by the Contribution Agreement (the “Contribution Agreement”) relating to a new joint venture arrangement among Regency HIG, GECC and the Alinda Investors. The Partnership contributed to HPC RIGS, which owns the Regency Intrastate Gas System, valued at $400,000,000, in exchange for a 38 percent general partnership interest in HPC. GECC and the Alinda Investors contributed $126,500,000 and $526,500,000 in cash, respectively, to HPC in return for a 12 percent and a 50 percent general partnership interest, respectively. In accordance with SFAS No. 160, the disposition and deconsolidation resulted in the recording of a $133,940,000 gain in the three months ended March 31, 2009 (of which $52,857,000 represents the remeasurement of the Partnership retained 38 percent interest to its fair value), net of transaction costs of $5,158,000.

The Partnership will serve as the operator of the joint venture, and will provide all employees and services for the operation and management of the joint venture’s assets.

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Credit Agreement Amendment. On March 17, 2009, RGS closed on Amendment No. 7 to its Credit Agreement (the “Amendment”). The Amendment authorized the contribution of RIGS to a joint venture (HPC) and allowed for future investment up to $135,000,000 in a joint venture. 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 LIBOR rate for a borrowing with a one-month interest period 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 commitment fees will range from 0.375 percent to 0.500 percent.

Revolving Credit Facility. On February 26, 2009, the Partnership entered into a $45,000,000 unsecured revolving credit agreement with GECC, as administrative agent, the lenders party thereto and the guarantors party thereto (the “Revolving Credit Facility”). The commitments under the Revolving Credit Facility terminated on March 17, 2009. The Partnership paid a commitment fee of $2,718,000 to GECC for the GECC Credit Facility, which was recorded in gain on asset sales, net.

Lehman Commitments on Revolving Credit Agreement. As of February 20, 2009, the amount of unfunded Lehman commitments has been reduced to $5,578,000 due to other banks in the syndicate increasing their commitments.

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Operating Lease Facility. On February 26, 2009, CDM entered into an operating lease facility with Caterpillar Financial Services Corporation whereby CDM has the ability to lease compression equipment with an aggregate value of up to $75,000,000. CDM paid commitment and arrangement fees of $375,000. As part of the facility, CDM will pay 150 bps on the value of the equipment funded for each lease as funded. The facility is available for leases with inception dates up to and including December 31, 2009, and mitigates the need to use available capacity under the existing Credit Facility. Each compressor acquired under this facility shall have a lease term of one hundred twenty (120) months with a fair value buyout option at the end of the lease term. At the end of the lease term, CDM shall also have an option to extend the lease term for an additional period of sixty (60) months at an adjusted rate equal to the fair market rate at that time. In the event CDM elects not to exercise the buyout option, the equipment must be returned in a manner fit for use at the end of the lease term. In addition to the fair value buyout option at the end of the lease term, early buyout option provisions exist at month sixty (60) and at month eighty four (84) of the one hundred twenty (120) month lease term. Covenants under the lease facility require CDM to maintain certain fleet utilization levels as of the end of each calendar quarter as well as a total debt to EBITDAR (Earnings Before Interest, Taxes, Depreciation, Amortization, and Rental expense) ratio of less than or equal to 4:1. In addition, covenants restrict the concentration of revenues derived from the equipment acquired under the lease facility. The terms of the lease facility do not include contingent rentals or escalation clauses.

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17. 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 B Common Unit		Basic and Diluted Earnings per Class C Common Unit		Basic and Diluted Earnings per Class D Common Unit		Basic and Diluted Earnings per Class E Common Unit
(in thousands except earnings per unit)
2008
March 31(1)	$	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		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		—
2007(2)
March 31	$	256,428	$	13,480	$	(1,295	)	$	(0.06	)	$	(0.06	)	$	—	$	0.48	$	—	$	—
June 30		302,828		8,768		(7,263	)		(0.15	)		(0.15	)		—		—		—		0.07
September 30		295,825		21,545		(9,833	)		(0.22	)		(0.22	)		—		—		—		0.63
December 31		335,157		15,571		4,555			0.03			0.03			—		—		—		0.53

(1) The operating income amount disclosed above differs immaterially from the amount disclosed in the Form 10-Q.

(2) The quarterly amounts have been recast for the FrontStreet acquisition which was accounted for as an as-if pooling transaction.

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