Exhibit 99.8

As disclosed in Note 1, on May 26, 2010 GP Seller sold all of the outstanding membership interests of the Partnership’s General Partner to ETE, effecting a change in control of the Partnership. In connection with this transaction, the Partnership’s assets and liabilities were required to be adjusted to fair value at the acquisition date by application of “push-down” accounting. As a result, the Partnership’s unaudited condensed consolidated financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting between the periods presented: (1) the period prior to the acquisition date (May 26, 2010), identified as “Predecessor” and (2) the period from May 26, 2010 forward, identified as “Successor”.

Page | 1

Regency Energy Partners LP

Condensed Consolidated Balance Sheets

(in thousands except unit data)

	Successor			Predecessor
	June 30, 2010			December 31, 2009
	(unaudited)
ASSETS
Current Assets:
Cash and cash equivalents	$	4,296		$	9,827
Restricted cash		1,011			1,511
Trade accounts receivable, net of allowance of $475 and $1,130		22,801			30,433
Accrued revenues		76,272			95,240
Related party receivables		33,444			6,222
Derivative assets		19,833			24,987
Other current assets		8,420			10,556
Total current assets		166,077			178,776
Property, Plant and Equipment:
Gathering and transmission systems		488,336			465,959
Compression equipment		785,685			823,060
Gas plants and buildings		131,537			159,596
Other property, plant and equipment		101,046			162,433
Construction-in-progress		125,528			95,547
Total property, plant and equipment		1,632,132			1,706,595
Less accumulated depreciation		(8,740	)		(250,160	)
Property, plant and equipment, net		1,623,392			1,456,435
Other Assets:
Investment in unconsolidated subsidiaries		1,369,921			453,120
Long-term derivative assets		1,241			207
Other, net of accumulated amortization of debt issuance costs of $564 and $10,743		34,206			19,468
Total other assets		1,405,368			472,795
Intangible Assets and Goodwill:
Intangible assets, net of accumulated amortization of $2,159 and $33,929		666,781			197,294
Goodwill		733,674			228,114
Total intangible assets and goodwill		1,400,455			425,408
TOTAL ASSETS	$	4,595,292		$	2,533,414
LIABILITIES & PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST
Current Liabilities:
Trade accounts payable	$	43,513		$	44,912
Accrued cost of gas and liquids		75,619			76,657
Related party payables		4,417			2,312
Deferred revenues, including related party amounts of $0 and $338		11,244			11,292
Derivative liabilities		3,576			12,256
Escrow payable		1,011			1,511
Other current liabilities, including related party amounts of $630 and $0		14,985			12,368
Total current liabilities		154,365			161,308
Long-term derivative liabilities		52,609			48,903
Other long-term liabilities		14,249			14,183
Long-term debt, net		1,276,640			1,014,299
Commitments and contingencies
Series A convertible redeemable preferred units, redemption amount of $83,891 and $83,891		70,850			51,711
Partners’ Capital and Noncontrolling Interest:
Common units (120,676,002 and 94,243,886 units authorized; 119,614,719 and 93,188,353 units issued and outstanding at June 30, 2010 and December 31, 2009)		2,659,907			1,211,605
General partner interest		335,193			19,249
Accumulated other comprehensive loss		—			(1,994	)
Noncontrolling interest		31,479			14,150
Total partners’ capital and noncontrolling interest		3,026,579			1,243,010
TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST	$	4,595,292		$	2,533,414

See accompanying notes to condensed consolidated financial statements

Page | 2

Regency Energy Partners LP

Condensed Consolidated Statements of Operations

Unaudited

(in thousands except unit data and per unit data)

	Successor			Predecessor
	Period from  Acquisition (May 26, 2010) to June 30, 2010			Period from April  1, 2010 to May 25, 2010			Three Months Ended June 30, 2009
REVENUES
Gas sales, including related party amounts of $447, $0, and $0	$	48,103		$	89,170		$	106,897
NGL sales including related party amounts of $18,054, $0, and $0		28,766			69,033			57,676
Gathering, transportation and other fees, including related party amounts of $2,086, $3,680, and $2,239		22,884			45,733			69,231
Net realized and unrealized (loss) gain from derivatives		(130	)		223			12,515
Other		3,357			7,336			7,223
Total revenues		102,980			211,495			253,542
OPERATING COSTS AND EXPENSES
Cost of sales, including related party amounts of $2,281, $3,198, and $1,453		74,081			147,262			157,347
Operation and maintenance		11,942			21,430			31,974
General and administrative, including related party amounts of $833, $0, and $0		7,104			21,809			14,127
Loss on asset sales, net		10			19			651
Depreciation and amortization		10,995			18,609			26,236
Total operating costs and expenses		104,132			209,129			230,335
OPERATING (LOSS) INCOME		(1,152	)		2,366			23,207
Income from unconsolidated subsidiaries		8,121			7,959			1,587
Interest expense, net		(8,109	)		(14,114	)		(19,568	)
Other income and deductions, net		(3,510	)		(624	)		214
(LOSS) INCOME BEFORE INCOME TAXES		(4,650	)		(4,413	)		5,440
Income tax expense (benefit)		245			83			(515	)
NET (LOSS) INCOME	$	(4,895	)	$	(4,496	)	$	5,955
Net income attributable to noncontrolling interest		(29	)		(244	)		(65	)
NET (LOSS) INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP	$	(4,924	)	$	(4,740	)	$	5,890
Amounts attributable to Series A convertible redeemable preferred units		668			1,335			—
General partner’s interest, including IDR		803			—			741
Amount allocated to non-vested common units		—			—			(137	)
Limited partners’ interest	$	(6,395	)	$	(6,075	)	$	5,286
Basic and Diluted (loss) earnings per unit:
Amount allocated to common units	$	(6,395	)	$	(6,075	)	$	5,286
Weighted average number of common units outstanding		119,600,652			92,832,219			80,550,149
Basic (loss) income per common unit	$	(0.05	)	$	(0.07	)	$	0.07
Diluted (loss) income per common unit	$	(0.05	)	$	(0.07	)	$	0.06
Distributions paid per unit	$	0.445		$	—		$	0.445

See accompanying notes to condensed consolidated financial statements

Page | 3

Regency Energy Partners LP

Condensed Consolidated Statements of Operations

Unaudited

(in thousands except unit data and per unit data)

	Successor			Predecessor
	Period from Acquisition (May 26, 2010) to June 30, 2010			Period from January 1, 2010 to May 25, 2010			Six Months Ended June 30, 2009
REVENUES
Gas sales, including related party amounts of $447, $0, and $0	$	48,103		$	232,063		$	254,793
NGL sales including related party amounts of $18,054, $0, and $0		28,766			166,362			107,261
Gathering, transportation and other fees, including related party amounts of $2,086, $12,200 and $3,376		22,884			116,061			142,079
Net realized and unrealized (loss) gain from derivatives		(130	)		(716	)		26,970
Other		3,357			15,477			12,417
Total revenues		102,980			529,247			543,520
OPERATING COSTS AND EXPENSES
Cost of sales, including related party amounts of $2,281, $6,564 and $1,700		74,081			371,871			339,875
Operation and maintenance		11,942			53,841			68,016
General and administrative, including related party amounts of $833, $0, and $0		7,104			37,212			29,205
Loss (gain) on asset sales, net		10			303			(133,280	)
Depreciation and amortization		10,995			46,084			54,125
Total operating costs and expenses		104,132			509,311			357,941
OPERATING (LOSS) INCOME		(1,152	)		19,936			185,579
Income from unconsolidated subsidiaries		8,121			15,872			1,923
Interest expense, net		(8,109	)		(36,459	)		(33,795	)
Other income and deductions, net		(3,510	)		(3,891	)		256
(LOSS) INCOME BEFORE INCOME TAXES		(4,650	)		(4,542	)		153,963
Income tax expense (benefit)		245			404			(416	)
NET (LOSS) INCOME	$	(4,895	)	$	(4,946	)	$	154,379
Net income attributable to noncontrolling interest		(29	)		(406	)		(100	)
NET (LOSS) INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP	$	(4,924	)	$	(5,352	)	$	154,279
Amounts attributable to Series A convertible redeemable preferred units		668			3,336			—
General partner’s interest, including IDR		803			662			4,274
Amount allocated to non-vested common units		—			(79	)		1,217
Beneficial conversion feature for Class D common units		—			—			820
Limited partners’ interest	$	(6,395	)	$	(9,271	)	$	147,968
Basic and Diluted (loss) earnings per unit:
Amount allocated to common units	$	(6,395	)	$	(9,271	)	$	147,968
Weighted average number of common units outstanding		119,600,652			92,788,319			78,920,074
Basic (loss) income per common unit	$	(0.05	)	$	(0.10	)	$	1.87
Diluted (loss) income per common unit	$	(0.05	)	$	(0.10	)	$	1.85
Distributions paid per unit	$	0.445		$	0.445		$	0.89
Amount allocated to Class D common units	$	—		$	—		$	820
Total number of Class D common units outstanding		—			—			7,276,506
Income per Class D common unit due to beneficial conversion feature	$	—		$	—		$	0.11
Distributions paid per unit	$	—		$	—		$	—

See accompanying notes to condensed consolidated financial statements

Page | 4

Regency Energy Partners LP

Condensed Consolidated Statements of Comprehensive (Loss) Income

Unaudited

(in thousands)

	Three Months Ended June 30, 2010 and 2009
	Successor			Predecessor
	Period from Acquisition (May 26, 2010) to June 30, 2010			Period from April 1, 2010 to May 25, 2010			Three Months Ended June 30, 2009
Net (loss) income	$	(4,895	)	$	(4,496	)	$	5,955
Net hedging amounts reclassified to earnings		—			(512	)		(13,644	)
Net change in fair value of cash flow hedges		—			8,649			(14,622	)
Comprehensive (loss) income	$	(4,895	)	$	3,641		$	(22,311	)
Comprehensive income attributable to noncontrolling interest		29			244			65
Comprehensive (loss) income attributable to Regency Energy Partners LP	$	(4,924	)	$	3,397		$	(22,376	)
	Six Months Ended June 30, 2010 and 2009
	Successor			Predecessor
	Period from Acquisition (May 26, 2010) to June 30, 2010			Period from January 1, 2010 to May 25, 2010			Six Months Ended June 30, 2009
Net (loss) income	$	(4,895	)	$	(4,946	)	$	154,379
Net hedging amounts reclassified to earnings		—			2,145			(27,894	)
Net change in fair value of cash flow hedges		—			18,486			(9,242	)
Comprehensive (loss) income	$	(4,895	)	$	15,685		$	117,243
Comprehensive income attributable to noncontrolling interest		29			406			100
Comprehensive (loss) income attributable to Regency Energy Partners LP	$	(4,924	)	$	15,279		$	117,143

See accompanying notes to condensed consolidated financial statements

Page | 5

Regency Energy Partners LP

Condensed Consolidated Statements of Cash Flows

Unaudited

(in thousands)

	Successor			Predecessor
	Period from Acquisition (May 26, 2010) to June 30, 2010			Period from January 1, 2010 to May 25, 2010			Six Months Ended June 30, 2009
OPERATING ACTIVITIES
Net (loss) income	$	(4,895	)	$	(4,946	)	$	154,379
Adjustments to reconcile net (loss) income to net cash flows provided by (used in) operating activities:
Depreciation and amortization, including debt issuance cost amortization		11,330			49,363			56,750
Write-off of debt issuance costs		—			1,780			—
Income from unconsolidated subsidiaries		(8,121	)		(15,872	)		(1,923	)
Derivative valuation changes		6,921			12,004			(6,293	)
Loss (gain) on asset sales, net		10			303			(133,280	)
Unit-based compensation expenses		137			12,070			2,750
Cash flow changes in current assets and liabilities:
Trade accounts receivable, accrued revenues, and related party receivables		13,843			(11,272	)		38,073
Other current assets		585			2,516			3,728
Trade accounts payable, accrued cost of gas and liquids, related party payables and deferred revenues		(15,460	)		8,649			(39,185	)
Other current liabilities		(20,497	)		22,614			(7,396	)
Distributions received from unconsolidated subsidiaries		—			12,446			1,900
Other assets and liabilities		(60	)		(234	)		(232	)
Net cash flows (used in) provided by operating activities		(16,207	)		89,421			69,271
INVESTING ACTIVITIES
Capital expenditures		(20,875	)		(63,787	)		(119,185	)
Capital contribution to unconsolidated subsidiaries		(38,922	)		(20,210	)		—
Acquisitions, net of cash received		12,848			(75,114	)		—
Proceeds from asset sales		14			10,661			83,182
Net cash flows (used in) investing activities		(46,935	)		(148,450	)		(36,003	)
FINANCING ACTIVITIES
Net borrowings (repayments) under revolving credit facility		37,000			199,008			(177,249	)
Proceeds from issuance of senior notes, net of discount		—			—			236,240
Debt issuance costs		(132	)		(15,728	)		(11,939	)
Partner contributions		7,436			—			—
Partner distributions		—			(86,078	)		(71,644	)
Acquisition of assets between entities under common control in excess of historical cost		—			(16,973	)		—
Distributions to noncontrolling interest		—			(1,135	)		—
Proceeds from option exercises		150			120			—
Equity issuance costs		—			(89	)		—
Distributions to redeemable convertible preferred units		—			(1,945	)		—
Tax withholding on unit-based vesting		—			(4,994	)		—
Net cash flows provided by (used in) financing activities		44,454			72,186			(24,592	)
Net change in cash and cash equivalents		(18,688	)		13,157			8,676
Cash and cash equivalents at beginning of period		22,984			9,827			599
Cash and cash equivalents at end of period	$	4,296		$	22,984		$	9,275
Supplemental cash flow information:
Non-cash capital expenditures	$	16,159		$	18,051		$	9,480
Issuance of common units for an acquisition		584,436			—			—
Deemed contribution from acquisition of assets between entities under common control		17,152			—			—
Release of escrow payable from restricted cash		—			500			—
Contribution of fixed assets, goodwill and working capital to HPC		—			—			263,921
Contribution receivable		12,288			—			—

See accompanying notes to condensed consolidated financial statements

Page | 6

Regency Energy Partners LP

Condensed Consolidated Statements of Partners’ Capital and Noncontrolling Interest

Unaudited

(in thousands except unit data)

	Regency Energy Partners LP
	Units
	Common	Common Unitholders			General Partner Interest			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total
Predecessor
Balance - December 31, 2009	93,188,353	$	1,211,605		$	19,249		$	(1,994	)	$	14,150		$	1,243,010
Issuance of common units under LTIP, net of forfeitures and tax withholding	152,075		(4,994	)		—			—			—			(4,994	)
Issuance of common units, net of costs	—		(89	)		—			—			—			(89	)
Exercise of common unit options	—		120			—			—			—			120
Unit-based compensation expenses	—		12,070			—			—			—			12,070
Accrued distributions to phantom units	—		(473	)		—			—			—			(473	)
Acquisition of assets between entities under common control in excess of historical cost	—		—			(16,973	)		—			—			(16,973	)
Partner distributions	—		(84,504	)		(1,574	)		—			—			(86,078	)
Distributions to noncontrolling interest	—		—			—			—			(1,135	)		(1,135	)
Net (loss) income	—		(6,014	)		662			—			406			(4,946	)
Distributions to Series A convertible redeemable preferred units	—		(1,906	)		(39	)		—			—			(1,945	)
Accretion of Series A convertible redeemable preferred units	—		(55	)		—			—			—			(55	)
Net cash flow hedge amounts reclassified to earnings	—		—			—			2,145			—			2,145
Net change in fair value of cash flow hedges	—		—			—			18,486			—			18,486
Balance - May 25, 2010	93,340,428	$	1,125,760		$	1,325		$	18,637		$	13,421		$	1,159,143

	Regency Energy Partners LP
	Units
	Common	Common Unitholders			General Partner Interest		Accumulated Other Comprehensive Income (Loss)		Noncontrolling Interest		Total
Successor
Balance - May 26, 2010	93,340,428	$	2,073,532		$	304,950	$	—	$	31,450	$	2,409,932
Issuance of common units, net of costs	26,266,791		584,436			—		—		—		584,436
Exercise of common unit options	7,500		150			—		—		—		150
Unit-based compensation expenses	—		137			—		—		—		137
Acquisition of assets between entities under common control below historical cost	—		—			17,152		—		—		17,152
Partner contributions	—		7,436			12,288		—		—		19,724
Net (loss) income	—		(5,727	)		803		—		29		(4,895	)
Accretion of Series A convertible redeemable preferred units	—		(57	)		—		—		—		(57	)
Balance - June 30, 2010	119,614,719	$	2,659,907		$	335,193	$	—	$	31,479	$	3,026,579

See accompanying notes to condensed consolidated financial statements

Page | 7

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements

1. Organization and Summary of Significant Accounting Policies

Organization. The unaudited condensed consolidated financial statements presented herein contain the results of Regency Energy Partners LP (the “Partnership”) and its subsidiaries. The Partnership and its subsidiaries are engaged in the business of gathering, processing and transporting of natural gas and NGLs as well as providing contract compression services.

Basis of Presentation. On May 26, 2010, GP Seller completed the sale of all of the outstanding membership interests of the General Partner pursuant to a Purchase Agreement (the “Purchase Agreement”) among itself, ETE and ETE GP (the “ETE Acquisition”). Prior to the closing of the Purchase Agreement, GP Seller, an affiliate of GE EFS, owned all the outstanding limited partners’ interests in the General Partner, which is the sole general partner of the Partnership, and the entire member’s interest in the Managing General Partner, which is the sole general partner of the General Partner and, by virtue of that position, controlled the Partnership. Control of the Partnership transferred from GE EFS to ETE as a result of the ETE Acquisition. In connection with this transaction, the Partnership’s assets and liabilities were required to be adjusted to fair value on the closing date (May 26, 2010) by application of “push-down” accounting (the “Push-down Adjustments”). Total enterprise value of the Partnership as of May 26, 2010 was $3,783,680,000, giving effect to the transaction and the associated Push-down Adjustments, which is calculated below:

	(in thousands)
Fair value of limited partners interest, based on the number of outstanding
Partnership common units and the trading price on May 26, 2010	$	2,073,532
Fair value of consideration paid for general partner interest		304,950
Noncontrolling interest		31,450
Series A convertible redeemable preferred units		70,793
Fair value of long-term debt		1,239,863
Other long-term liabilities		63,092
Enterprise value	$	3,783,680

The Partnership has developed the preliminary amount of the fair value of its assets and liabilities. Management is reviewing the valuation and confirming results to determine the final purchase price allocation. The Partnership allocated the enterprise value to the following assets and liabilities based on their respective estimated fair values as of May 26, 2010:

	At May 26, 2010
	(in thousands)
Working capital	$	(3,286	)
Gathering and transmission systems		487,792
Compression equipment		779,634
Gas plants and buildings		131,537
Other property, plant and equipment		100,267
Construction-in-progress		114,146
Other long-term assets		36,839
Investment in unconsolidated subsidiary		734,137
Intangible assets		668,940
Goodwill		733,674
	$	3,783,680

Due to the Push-down Adjustments, the Partnership’s unaudited condensed consolidated financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting between the periods presented: (1) the period prior to the acquisition date (May 26, 2010), identified as “Predecessor” and (2) the period from May 26, 2010 forward, identified as “Successor”.

The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2009. In the opinion

Page | 8

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All inter-company items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.

Use of Estimates. The unaudited condensed consolidated financial statements have been prepared in conformity with GAAP and, of necessity, include the use of estimates and assumptions by management. Actual results could differ from these estimates.

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

Predecessor	Contracts			Customer Relations			Trade Names			Permits and Licenses			Total
							(in thousands)
Balance at December 31, 2009	$	126,332		$	35,362		$	30,508		$	5,092		$	197,294
Amortization		(3,322	)		(817	)		(975	)		(214	)		(5,328	)
Balance at May 25, 2010	$	123,010		$	34,545		$	29,533		$	4,878		$	191,966
Successor	Customer Relations			Trade Names			Total
				(in thousands)
Balance at May 26, 2010	$	604,840		$	64,100		$	668,940
Amortization		(1,905	)		(254	)		(2,159	)
Balance at June 30, 2010	$	602,935		$	63,846		$	666,781

As of June 30, 2010, customer relations and trade names are amortized over 30 and 20 years, respectively. The expected amortization of the intangible assets for each of the five succeeding years is as follows.

Year ending December 31,	Total
	(in thousands)
2010 (remaining)	$	11,606
2011		23,211
2012		23,211
2013		23,211
2014		23,211

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

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

In February 2010, the FASB clarified the type of embedded credit derivative that is exempt from embedded derivative bifurcation requirements. The Partnership evaluated the impact of this update on its accounting for embedded derivatives and determined that it had no impact on its financial position, results of operations or cash flows.

2. (Loss) Income per Limited Partner Unit

On September 2, 2009, the Partnership issued 4,371,586 Series A Convertible Redeemable Preferred Units (“Series A Preferred Units”). The Series A Preferred Units receive fixed quarterly cash distributions of $0.445 per unit beginning with the quarter ending March 31, 2010. Distributions for the quarters ended September 30, 2009 and December 31, 2009 were accrued, effectively increasing the conversion value of the Series A Preferred Units. Distributions are cumulative, and must be paid before any distributions to the general partner and common unitholders. For the purpose of calculating income per limited partner unit, any form of distributions, whether paid or not, as well as the accretion of the Series A Preferred Units, are treated as a reduction in net income (loss) available to the general partner and limited partner interests.

The following table provides a reconciliation of the numerator and denominator of the basic and diluted earnings per common unit computations for the three and six months ended June 30, 2010 and 2009.

Page | 9

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

	Three Months Ended June 30, 2010 and 2009
	Successor							Predecessor
	Period from Acquisition (May 26, 2010)  to June 30, 2010							Period from April 1, 2010 to Disposition (May 25, 2010)							Three Months Ended June 30, 2009
	Loss (Numerator)			Units (Denominator)	Per-Unit Amount			Loss (Numerator)			Units (Denominator)	Per-Unit Amount			Income (Numerator)			Units (Denominator)	Per-Unit Amount
	(in thousands except unit and per unit data)							(in thousands except unit and per unit data)
Basic (Loss) Earnings per Unit
Limited partners’ interests	$	(6,395	)	119,600,652	$	(0.05	)	$	(6,075	)	92,832,219	$	(0.07	)	$	5,286		80,550,149	$	0.07
Effect of Dilutive Securities
Restricted (non-vested) common units		—		—					—		—					(137	)	621,337
Diluted (Loss) Earnings per Unit	$	(6,395	)	119,600,652	$	(0.05	)	$	(6,075	)	92,832,219	$	(0.07	)	$	5,149		81,171,486	$	0.06
	Six Months Ended June 30, 2010 and 2009
	Successor							Predecessor
	Period from Acquisition (May 26, 2010) to June 30, 2010							Period from January 1, 2010 to Disposition (May 25, 2010)							Six Months Ended June 30, 2009
	Loss (Numerator)			Units (Denominator)	Per-Unit Amount			Income (Numerator)			Units (Denominator)	Per-Unit Amount			Income (Numerator)			Units (Denominator)	Per-Unit Amount
	(in thousands except unit and per unit data)							(in thousands except unit and per unit data)
Basic (Loss) Earnings per Unit
Limited partners’ interest	$	(6,395	)	119,600,652	$	(0.05	)	$	(9,271	)	92,788,319	$	(0.10	)	$	147,968		78,920,074	$	1.87
Effect of Dilutive Securities
Restricted (non-vested) common units		—		—					—		—					1,217		652,740
Class D common units		—		—					—		—					820		1,608,068
Diluted (Loss) Earnings per Unit	$	(6,395	)	119,600,652	$	(0.05	)	$	(9,271	)	92,788,319	$	(0.10	)	$	150,005		81,180,882	$	1.85

The following table shows the weighted average outstanding amount of securities that could potentially dilute earnings per unit in the future that were not included in the computation of diluted earnings per unit because to do so would have been antidilutive.

	Successor	Predecessor
	Period from Acquisition (May 26, 2010) to June 30, 2010	Period from April 1, 2010 to Disposition (May 25, 2010)	Three Months Ended June 30, 2009	Period from January 1, 2010 to Disposition (May 25, 2010)	Six Months Ended June 30, 2009
Restricted (non-vested) common units	—	356,954	—	396,918	—
Phantom units *	322,750	351,345	332,860	369,346	332,860
Common unit options	290,150	290,150	372,768	298,400	376,518
Convertible redeemable preferred units	4,584,192	4,584,192	—	4,584,192	—

* Amount disclosed assumes maximum conversion rate for market condition awards.

3. Acquisitions

On April 30, 2010, the Partnership purchased an additional 6.99 percent general partner interest in HPC from EFS Haynesville, bringing its total general partner interest in HPC to 49.99 percent. The purchase price of $92,087,000 was funded by borrowings under the Partnership’s revolving credit facility. Because this transaction occurred between two entities under common control, partners’ capital was decreased by $16,973,000, which represented a deemed distribution of the excess purchase price over EFS Haynesville’s carrying amount of $75,114,000.

On May 26, 2010, the Partnership purchased a 49.9 percent interest in MEP from ETE. The Partnership issued 26,266,791 common units to ETE, valued at $584,436,000, and received a working capital adjustment of $12,848,000 from ETE that was recorded as an adjustment to investment in unconsolidated subsidiaries. Because this transaction occurred between two entities under common control, partners’ capital was increased by $17,152,000, which represented a deemed contribution of the excess carrying amount of ETE’s investment of $588,740,000 over the purchase price. MEP is a 500 mile natural gas pipeline system that extends from the southeast corner of Oklahoma, across northeast Texas, northern Louisiana, central Mississippi and into Alabama. In June 2010, the Partnership made an additional capital contribution of $38,922,000 to MEP.

The following unaudited pro forma financial information has been prepared as if the transactions involving the purchase of 6.99 percent general partner interest in HPC, purchase of the 49.9 percent interest in MEP, together with the Push-down Adjustments described in Note 1 occurred as of the beginning of the earliest period presented. Such unaudited pro forma financial information does not purport to be indicative of the results of operations that would have been achieved if the transactions to which the Partnership is giving pro forma effect actually occurred on the dates referred to above or the results of operations that may be expected in the future.

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Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

	Pro Forma Results for the
	Period from April 1, 2010 to May 25, 2010			Three Months Ended June 30, 2009			Period from January 1, 2010 to May 25, 2010			Six Months Ended June 30, 2009
	(in thousands except unit and per unit data)
Total revenues	$	211,495		$	253,542		$	529,247		$	531,547
Net (loss) income attributable to Regency Energy Partners LP	$	(4,361	)	$	(2,581	)	$	(6,108	)	$	133,911
Amounts attributable to Series A convertible redeemable preferred units		1,335			—			3,336			—
General partner’s interest, including IDR		801			773			1,641			4,270
Amount allocated to non-vested common units		—			(196	)		(80	)		711
Beneficial conversion feature for Class D common units		—			—			—			820
Limited partners’ interest	$	(6,497	)	$	(3,158	)	$	(11,005	)	$	128,110
Basic and Diluted earnings (loss) per unit:
Amount allocated to common units	$	(6,497	)	$	(3,158	)	$	(11,005	)	$	128,110
Weighted average number of common units outstanding		119,099,010			106,816,940			119,055,110			105,186,865
Basic (loss) income per common unit	$	(0.05	)	$	(0.03	)	$	(0.09	)	$	1.22
Diluted (loss) income per common unit	$	(0.05	)	$	(0.03	)	$	(0.09	)	$	1.21
Distributions paid per unit	$	0.445		$	0.445		$	0.445		$	0.890
Amount allocated to Class D common units	$	—		$	—		$	—		$	820
Total number of Class D common units outstanding		—			—			—			7,276,506
Income per Class D common unit due to beneficial conversion feature	$	—		$	—		$	—		$	0.11
Distributions per unit	$	—		$	—		$	—		$	—

4. Investment in Unconsolidated Subsidiaries

Investment in HPC. HPC was established in March 2009 and as of June 30, 2010, the Partnership owns 49.99 percent interest in HPC. Following table summarizes the changes in the Partnership’s investment in HPC.

	Successor		Predecessor
	Period from Acquisition (May 26, 2010) to June 30, 2010		Period from April 1, 2010 to Disposition (May 25, 2010)		Three Months Ended June 30, 2009		Period from January 1, 2010 to Disposition (May 25, 2010)		Six Months Ended June 30, 2009
	(in thousands)		(in thousands)
Contributions to HPC	$	—	$	20,210	$	—	$	20,210	$	400,000
Distributions received from HPC		—		8,920		1,900		12,446		1,900
Partnership’s share of HPC’s net income		4,460		7,959		1,587		15,872		1,923

As discussed in Note 1, the Partnership’s investment in HPC was adjusted to its fair value on May 26, 2010 and the excess fair value over net book value was comprised of two components: (1) $143,757,000 was attributed to HPC’s long-lived assets and is being amortized as a reduction of income from unconsolidated subsidiaries over the useful lives of the respective assets, which vary from 15 to 30 years, and (2) $38,510,000 could not be attributed to a specific asset and therefore will not be amortized in future periods. For the period from May 26, 2010 to June 30, 2010, the Partnership recorded $365,000 as a reduction of income from unconsolidated subsidiaries due to the amortization of the excess fair value of long-lived assets.

The summarized financial information of HPC is disclosed below.

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Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

RIGS Haynesville Partnership Co.

Condensed Consolidated Balance Sheets

(in thousands)

	June 30, 2010		December 31, 2009
	(Unaudited)
ASSETS
Total current assets	$	48,383	$	39,239
Restricted cash, non-current		43,314		33,595
Property, plant and equipment, net		888,542		861,570
Total other assets		149,065		149,755
TOTAL ASSETS	$	1,129,304	$	1,084,159
LIABILITIES & PARTNERS’ CAPITAL
Total current liabilities	$	17,273	$	30,967
Partners’ capital		1,112,031		1,053,192
TOTAL LIABILITIES & PARTNERS’ CAPITAL	$	1,129,304	$	1,084,159

RIGS Haynesville Partnership Co.

Condensed Consolidated Income Statements

(in thousands)

						For the Six Months Ended June 30, 2010			From Inception (March 18, 2009) to June 30, 2009
	For the Three Months Ended June 30,
	2010			2009
	(Unaudited)					(Unaudited)
Total revenues	$	44,375		$	11,707	$	79,564		$	13,533
Total operating costs and expenses		18,425			8,038		35,148			9,084
OPERATING INCOME		25,950			3,669		44,416			4,449
Interest expense		(99	)		—		(201	)		—
Other income and deductions, net		20			508		59			612
NET INCOME	$	25,871		$	4,177	$	44,274		$	5,061

Investment in MEP. On May 26, 2010, the Partnership purchased a 49.9 interest in the MEP from ETE. In June 2010, the Partnership made an additional capital contribution of $38,922,000 to MEP. During the period from May 26, 2010 to June 30, 2010, the Partnership recognized $4,026,000 in income from unconsolidated subsidiaries for its ownership interest.

The summarized financial information of MEP is disclosed below.

Midcontinent Express Pipeline LLC

Condensed Balance Sheet

(in thousands)

	June 30, 2010
	(Unaudited)
ASSETS
Total current assets	$	32,987
Property, plant and equipment, net		2,225,383
Total other assets		5,588
TOTAL ASSETS	$	2,263,958
LIABILITIES & PARTNERS’ CAPITAL
Total current liabilities	$	92,795
Long-term debt		800,000
Partners’ capital		1,371,163
TOTAL LIABILITIES & PARTNERS’ CAPITAL	$	2,263,958

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Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

Midcontinent Express Pipeline LLC

Condensed Income Statement

(in thousands)

	Month Ended June 30, 2010
	(Unaudited)
Total revenues	$	21,269
Total operating costs and expenses		9,770
OPERATING INCOME		11,499
Interest expense, net		(3,431	)
NET INCOME	$	8,068

5. Derivative Instruments

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

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

On May 26, 2010, all of the Partnership’s outstanding commodity swaps that were previously accounted for as cash flow hedges were de-designated and are currently accounted for under the mark-to-market method of accounting.

The Partnership executes natural gas, NGLs’ and WTI trades on a periodic basis to hedge its anticipated equity exposure. Subsequent to June 30, 2010, the Partnership has executed additional NGL swaps to hedge its 2011 and 2012 price exposure.

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

	As of June 30, 2010						As of August 8, 2010
	2010		2011		2012		2010		2011		2012
NGLs	87	%	52	%	0	%	87	%	67	%	6	%
Condensate	96	%	74	%	7	%	96	%	74	%	7	%
Natural gas	74	%	42	%	0	%	74	%	42	%	0	%

Interest Rate Risk. The Partnership is exposed to variable interest rate risk as a result of borrowings under its revolving credit facility. As of June 30, 2010, the Partnership had $655,650,000 of outstanding borrowings exposed to variable interest rate risk. The Partnership’s $300,000,000 interest rate swaps expired in March 2010. In April 2010, the Partnership entered into additional two-year interest rate swaps related to $250,000,000 of borrowings under its revolving credit facility, effectively locking the base rate, exclusive of applicable margins, for these borrowings at 1.325 percent through April 2012.

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

The Partnership is exposed to credit risk from its derivative counterparties. The Partnership does not require collateral from these counterparties. The Partnership deals primarily with financial institutions when entering into financial derivatives. The Partnership has entered into Master International Swap Dealers Association (“ISDA”) Agreements that allow for netting of swap contract

Page | 13

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

receivables and payables in the event of default by either party. If the Partnership’s counterparties fail to perform under existing swap contracts, the Partnership’s maximum loss would be $21,346,000, which would be reduced by $2,824,000 due to the netting feature. The Partnership has elected to present assets and liabilities under Master ISDA Agreements gross on the condensed consolidated balance sheets.

Embedded Derivatives. The Series A Preferred Units contain embedded derivatives which are required to be bifurcated and accounted for separately, such as the holders’ conversion option and the Partnership’s call option. These embedded derivatives are accounted for using mark-to-market accounting. The Partnership does not expect the embedded derivatives to affect its cash flows.

The Partnership’s derivative assets and liabilities, including credit risk adjustment, as of June 30, 2010 and December 31, 2009 are detailed below.

	Assets				Liabilities
	June 30, 2010 (unaudited)		December 31, 2009		June 30, 2010 (unaudited)		December 31, 2009
	(in thousands)
Derivatives designated as cash flow hedges
Current amounts
Interest rate contracts	$	—	$	—	$	—	$	1,064
Commodity contracts		—		9,521		—		11,161
Long-term amounts
Commodity contracts		—		207		—		931
Total cash flow hedging instruments		—		9,728		—		13,156
Derivatives not designated as cash flow hedges
Current amounts
Commodity contracts		19,833		15,466		2,052		31
Interest rate contracts		—		—		1,524		—
Long-term amounts
Commodity contracts		1,241		—		15		3,378
Interest rate contracts		—		—		355
Embedded derivatives in Series A Preferred Units		—		—		52,239		44,594
Total derivatives not designated as cash flow hedges		21,074		15,466		56,185		48,003
Total derivatives	$	21,074	$	25,194	$	56,185	$	61,159

The following tables detail the effect of the Partnership’s derivative assets and liabilities in the consolidated statement of operations for the period presented.

Page | 14

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

For the Three Months Ended June 30, 2010 and 2009

		Successor		Predecessor
		Period from May 26, 2010 through June 30, 2010		Period from April 1, 2010 through May 25, 2010		For the Three Months Ended June 30, 2009
		(in thousands)		(in thousands)
		Change in Value Recognized in OCI on Derivatives (Effective Portion)
Derivatives in cash flow hedging relationships:
Commodity derivatives		—		7,428		(13,946	)
Interest rate swap derivatives		—		—		(676	)
		—		7,428		(14,622	)
		Amount of Gain/(Loss) Reclassified from  AOCI into Income (Effective Portion)
	Location of Gain (Loss) Recognized in Income
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	—		(709	)	15,546
Interest rate swap derivatives	Interest expense	—		—		(1,515	)
		—		(709	)	14,031
		Amount of Gain/(Loss) Recognized in Income on Ineffective Portion
	Location of Gain (Loss) Recognized in Income
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	—		(301	)	1,616
Interest rate swap derivatives	Interest expense	—		—		—
		—		(301	)	1,616
		Amount of Gain/(Loss) from  Dedesignation Amortized from AOCI into Income
	Location of Gain (Loss) Recognized in Income
Derivatives not designated in a hedging relationship:
Commodity derivatives	Revenues	—		1,221		(387	)
Interest rate swap derivatives	Interest expense	—		—		—
		—		1,221		(387	)
		Amount of Gain/(Loss) Recognized in Income on Derivatives
	Location of Gain (Loss) Recognized in Income
Derivatives not designated in a hedging relationship:
Commodity derivatives	Revenues	(824	)	12		(5,690	)
Interest rate swap derivatives	Interest expense	(1,715	)	(824	)	—
Embedded derivative	Other income & deductions	(3,606	)	(654	)	—
		(6,145	)	(1,466	)	(5,690	)

Page | 15

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

For the Six Months Ended June 30, 2010 and 2009

		Successor		Predecessor
		Period from May 26, 2010 through June 30, 2010		Period from January 1, 2010 through May 25, 2010		For the Six Months Ended June 30, 2009
		(in thousands)				(in thousands)
		Change in Value Recognized in OCI on Derivatives (Effective Portion)
Derivatives in cash flow hedging relationships:
Commodity derivatives		—		14,371		(7,728	)
Interest rate swap derivatives		—		—		(1,514	)
		—		14,371		(9,242	)
		Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
	Location of Gain (Loss) Recognized in Income
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	—		(5,200	)	32,065
Interest rate swap derivatives	Interest expense	—		(1,060	)	(2,987	)
		—		(6,260	)	29,078
		Amount of Gain/(Loss) Recognized in Income on Ineffective Portion
	Location of Gain (Loss) Recognized in Income
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	—		(799	)	2,231
Interest rate swap derivatives	Interest expense	—		—		—
		—		(799	)	2,231
		Amount of Gain/(Loss) from Dedesignation Amortized from AOCI into Income
	Location of Gain (Loss) Recognized in Income
Derivatives not designated in a hedging relationship:
Commodity derivatives	Revenues	—		4,115		(1,184	)
Interest rate swap derivatives	Interest expense	—		—		—
		—		4,115		(1,184	)
		Amount of Gain/(Loss) Recognized in Income on Derivatives
	Location of Gain (Loss) Recognized in Income
Derivatives not designated in a hedging relationship:
Commodity derivatives	Revenues	(824	)	1,247		(7,092	)
Interest rate swap derivatives	Interest expense	(1,715	)	(824	)	—
Embedded derivative	Other income & deductions	(3,606	)	(4,039	)	—
		(6,145	)	(3,616	)	(7,092	)

6. Long-term Debt

The following table provides information on the Partnership’s long-term debt.

	June 30, 2010			December 31, 2009
	(in thousands)
Senior notes	$	620,990		$	594,657
Revolving loans		655,650			419,642
Total		1,276,640			1,014,299
Less: current portion		—			—
Long-term debt	$	1,276,640		$	1,014,299
Availability under revolving credit facility:
Total credit facility limit	$	900,000		$	900,000
Unfunded commitments		—			(10,675	)
Revolving loans		(655,650	)		(419,642	)
Letters of credit		(17,032	)		(16,257	)
Total available	$	227,318		$	453,426

Long-term debt maturities as of June 30, 2010 for each of the next five years are as follows:

Page | 16

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

Year Ending December 31,	Amount
	(in thousands)
2010	$	—
2011		—
2012		—
2013		357,500
2014		655,650
Thereafter		250,000
Total	$	1,263,150

The outstanding balance of revolving debt under the revolving credit facility bears interest at LIBOR plus a margin or Alternate Base Rate (equivalent to the U.S prime rate lending rate) plus a margin or a combination of both. The senior notes pay fixed interest rates and the weighted average coupon rate is 8.787 percent. The weighted average interest rates for the revolving loans and senior notes, including interest rate swap settlements, commitment fees, and amortization of debt issuance costs were 5.74 percent during the period from May 26, 2010 to June 30, 2010, 7.98 percent during the period from April 1, 2010 to May 25, 2010, 6.69 percent during the three months ended June 30, 2009, 7.98 percent during the period from January 1, 2010 to May 25, 2010 and 5.94 percent during the six months ended June 30, 2009.

Senior Notes. The senior notes are jointly and severally guaranteed by all of the Partnership’s current consolidated subsidiaries, other than Finance Corp., and by certain of its future subsidiaries. The senior notes and the guarantees are unsecured and rank equally with all of the Partnership’s and the guarantors’ existing and future unsubordinated obligations. The senior notes and the guarantees will be senior in right of payment to any of the Partnership’s and the guarantors’ future obligations that are, by their terms, expressly subordinated in right of payment to the notes and the guarantees. The senior notes and the guarantees will be effectively subordinated to the Partnership’s and the guarantors’ secured obligations, including the Partnership’s credit facility and the Series A Preferred Units, to the extent of the value of the assets securing such obligations. As of June 30, 2010, the Partnership was in compliance with each of the financial covenants required under the terms of the senior notes.

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

Upon a change in control, each holder of the Partnership’s senior notes may, at its option, require the Partnership to purchase all or a portion of its notes at a purchase price of 101 percent plus accrued interest and liquidated damages, if any. Subsequent to the ETE Acquisition, no noteholder has exercised this option.

As disclosed in Note 1, the Partnership’s long-term debt was adjusted to fair value on May 26, 2010. The fair value of the senior notes was adjusted based on quoted market prices. The re-measurement of the senior notes due 2013 and 2016 resulted in premium of $7,150,000 and $6,563,000, respectively.

The unamortized premium or discount on the Partnership’s senior notes as of June 30, 2010 and December 31, 2009 are as follows.

Page | 17

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

	Successor		Predecessor
	June 30, 2010		December 31, 2009
	(in thousands)
Senior Notes Due 2013
Principal amount	$	357,500	$	357,500
add:
Unamortized premium		6,998		—
Carrying value	$	364,498	$	357,500
Senior Notes Due 2016
Principal amount	$	250,000	$	250,000
add/ deduct:
Unamortized premium (discount)		6,492		(12,843	)
Carrying value	$	256,492	$	237,157

Revolving Credit Facility. On March 4, 2010, RGS executed the Fifth Amended and Restated Credit Agreement (the “new credit agreement”), to be effective as of March 4, 2010. The material differences between the Fourth Amended and Restated Credit Agreement (the “previous credit agreement”) and the new credit agreement include:

• extension of the maturity date to June 15, 2014 from August 15, 2011, subject to the following contingency:

• if the Partnership’s 8.375 percent senior notes due December 15, 2013 have not been refinanced or paid off by June 15, 2013, then the maturity date of the revolving credit facility will be June 15, 2013;

• an increase in the amount of allowed investments in HPC to $250,000,000 from $135,000,000;

• the addition of an allowance for joint venture investments (other than HPC) of up to $75,000,000, provided that (i) distributed cash and net income from joint ventures under this basket shall be excluded from consolidated net income and (ii) equity interests in joint ventures created under this basket shall be pledged as collateral;

• the modification of financial covenants to give credit for projected EBITDA associated with certain future material HPC projects on a percentage of completion basis, provided that such amount, together with adjustments related to the Haynesville Expansion Project and other material projects, does not exceed 20 percent of consolidated EBITDA (as defined in the new credit agreement) through March 31, 2010, and 15 percent thereafter;

• an increase in the annual general asset sales permitted from $20,000,000 annually to five percent of consolidated net tangible assets (as defined in the new credit agreement) annually.

The Partnership treated the amendment of the credit facility as a modification of an existing revolving credit agreement and, therefore, wrote off debt issuance costs of $1,780,000 to interest expense, net in the period from January 1, 2010 to May 25, 2010. In addition, the Partnership paid and capitalized $15,861,000 of loan fees which will be amortized over the remaining term of the credit facility.

On May 26, 2010, the Partnership entered into the first amendment to its Fifth Amended and Restated Credit Agreement. The amendment, among other things,

• amends the definition of “Consolidated EBITDA” and “Consolidated Net Income” to include MEP;

• amends the definition of “Joint Venture” in the credit agreement to include MEP;

• amends the definition of “Permitted Acquisition” in the agreement to clarify that the initial investment in MEP is a permitted acquisition;

• amends the definition of “Permitted Holder” to include to include ETE as a party that may hold the equity interest in the Managing General Partner without triggering an event of default under the credit agreement;

• allows for the pledge of the equity interest in MEP as a collateral indirectly, through the direct pledge of equity interest in Regency Midcon;

• permits certain investments in MEP by the Partnership and its affiliates;

• requires that the Partnership and its subsidiaries maintain a senior consolidated secured leverage ratio not to exceed 3 to 1.

Page | 18

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

The new credit agreement and the guarantees are senior to the Partnership’s and the guarantors’ secured obligations, including the Series A Preferred Units, to the extent of the value of the assets securing such obligations. As of June 30, 2010, the Partnership was in compliance with each of the financial covenants required under the term of the credit agreement.

7. Commitments and Contingencies

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

Escrow Payable. At June 30, 2010, $1,011,000 remained in escrow pending the completion by El Paso of environmental remediation projects pursuant to the purchase and sale agreement (“El Paso PSA”) related to assets in north Louisiana and the mid-continent area and a subsequent 2008 settlement agreement between the Partnership and El Paso. In the El Paso PSA, El Paso indemnified Regency Gas Services LLC, now known as Regency Gas Services LP, against losses arising from pre-closing and known environmental liabilities subject to a limit of $84,000,000 and certain deductible limits. Upon completion of a Phase II environmental study, the Partnership notified El Paso of remediation obligations amounting to $1,800,000 with respect to known environmental matters and $3,600,000 with respect to pre-closing environmental liabilities. This escrow amount will be further reduced under a specified schedule as El Paso completes its cleanup obligations and the remainder will be released upon completion. In connection with this matter, $500,000 was released on May 6, 2010.

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

Keyes Litigation. In August 2008, Keyes Helium Company, LLC (“Keyes”) filed suit against Regency Gas Services LP, the Partnership, the General Partner and various other subsidiaries. Keyes entered into an output contract with the Partnership’s predecessor-in-interest in 1996 under which it purchased all of the helium produced at the Lakin, Kansas processing plant. In September 2004, the Partnership decided to shut down its Lakin plant and contract with a third party for the processing of volumes processed at Lakin; as a result, the Partnership no longer delivered any helium to Keyes. In its suit, Keyes alleges it is entitled to damages for the costs of covering its purchases of helium. On May 7, 2010, the jury rendered a verdict in favor of Regency. No damages were awarded to the Plaintiffs. Plaintiffs have appealed the verdict. The hearing on appeal will take place sometime in 2011.

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

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

continued its remediation efforts at the Plants. Tronox filed a reorganization plan on July 7, 2010. The plan calls for the creation of a trust to fund environmental clean-up at the various sites where Tronox has an obligation. Tronox must file the Environmental Claims Settlement Agreement, which will set forth the amount of trust funds allocated to each site, 14 days prior to the confirmation hearing, the date for which has not yet been set.

Page | 19

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

8. Series A Convertible Redeemable Preferred Units

On September 2, 2009, the Partnership issued 4,371,586 Series A Preferred Units. As of March 31, 2010, the Series A Preferred Units were convertible to 4,584,192 common units, and if outstanding, are mandatorily redeemable on September 2, 2029 for $80,000,000 plus all accrued but unpaid distributions thereon. The Series A Preferred Units receive fixed quarterly cash distributions of $0.445 per unit beginning with the quarter ending March 31, 2010, if outstanding on the record dates of the Partnership’s common units distributions. Effective as of March 2, 2010, holders can elect to convert Series A Preferred Units to common units at any time in accordance with the partnership agreement.

Upon a change in control, each unitholder may, at its option, require the Partnership to purchase the Series A Preferred Units for an amount equal to 101 percent of the total of the face value of the Series A Preferred Units plus all accrued but unpaid distribution thereon. Subsequent to the ETE Acquisition, no unitholder has exercised this option.

As disclosed in Note 1, the Partnership’s Series A Preferred Units were adjusted to fair value of $70,793,000 on May 26, 2010. The following table provides a reconciliation of the beginning and ending balances of the Series A Preferred Units for the six months ended June 30, 2010.

	For the Six Months Ended June 30, 2010,
	Units	Amount
		(in thousands)
Beginning balance as of January 1, 2010	4,371,586	$	51,711
Accretion to redemption value from January 1, 2010 to May 25, 2010	—		55
Balance as of May 25, 2010	4,371,586		51,766
Fair value adjustment	—		19,027
Balance as of May 26, 2010	4,371,586		70,793
Accretion to redemption value from May 26, 2010 to June 30, 2010	—		57
Ending balance as of June 30, 2010	4,371,586	$	70,850	*

* This amount will be accreted to $80,000,000 plus any accrued and unpaid distributions by deducting amounts from partners’ capital over the 19.25 remaining years.

9. Related Party Transactions

The employees operating the assets of the Partnership and its subsidiaries and all those providing staff or support services are employees of the General Partner. Pursuant to the Partnership Agreement, the General Partner receives a monthly reimbursement for all direct and indirect expenses incurred on behalf of the Partnership. Reimbursements of $5,660,000, $10,370,000, $31,065,000, $8,591,000 and $16,209,000, were recorded in the Partnership’s financial statements during the periods from May 26, 2010 to June 30, 2010, from April 1, 2010 to May 25, 2010, from January 1, 2010 to May 25, 2010 and for the three and six months ended June 30, 2009, respectively, as operating expenses or general and administrative expenses, as appropriate.

In conjunction with distributions by the Partnership to its limited and general partner interests, GE EFS received cash distributions of $13,114,000, $2,603,000, $26,241,000 and $12,181,000 during the period from April 1, 2010 to May 25, 2010, the three months ended June 30, 2009, the period from January 1, 2010 to May 25, 2010 and the six months ended June 30, 2009, respectively.

Under a Master Services Agreement with HPC, the Partnership operates and provides all employees and services for the operation and management of HPC. Under this agreement, the Partnership receives $1,400,000 monthly as a partial reimbursement of its general and administrative costs. The amount is recorded as fee revenue in the Partnership’s corporate and other segment. The Partnership also incurs expenditures on behalf of HPC and these amounts are billed to HPC on a monthly basis. For the periods from May 26, 2010 to June 30, 2010, from April 1, 2010 to May 25, 2010, from January 1, 2010 to May 25, 2010, and the three and six months ended June 30, 2009, the related party general and administrative expenses reimbursed to the Partnership were $1,400,000, $2,800,000, $6,933,000, $1,500,000, and $1,726,000, respectively.

On May 26, 2010, the Partnership received $7,436,000 from ETE, which represents the portion of the estimated amount of the Partnership’s common unit distribution to be paid to ETE for the period of time those units were not outstanding (April 1, 2010 to May 25, 2010).

As of June 30, 2010, the Partnership has a related party receivable of $12,288,000 from ETE for an additional capital contribution, which was received on August 6, 2010.

Page | 20

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

On May 26, 2010, the Partnership entered into a services agreement with ETE and ETE Services Company, LLC (“Services Co.”), a subsidiary of ETE. Under the services agreement, Services Co. will perform certain general and administrative services to the Partnership. The Partnership will pay Services Co’s direct expenses for these services, plus an annual fee of $10,000,000, and will receive the benefit of any cost savings recognized for these services. The services agreement has a five year term, subject to earlier termination rights in the event of a change in control, the failure to achieve certain cost savings for the Partnership or upon an event of default.

As disclosed in Note 3, the Partnership’s acquisition of additional 6.99 percent partner’s interest in HPC from GE EFS, and the 49.9 percent interest in MEP from ETE are related party transactions.

The Partnership’s contract compression segment provides contract compression services to HPC and records revenue in gathering, transportation and other fees on the statement of operation. The Partnership also receives transportation services from HPC and records the cost as cost of sales.

Enterprise GP holds a non-controlling equity interest in ETE’s general partner and a limited partnership interest in ETE, therefore is considered a related party along with any of its subsidiaries. The Partnership, in the ordinary course of business, sells natural gas and NGLs to the subsidiaries of Enterprise GP and records the revenue in gas sales and NGL sales. The Partnership also incurs NGL processing fees with subsidiaries of Enterprise GP and records the cost to cost of sales.

As of June 30, 2010, the Partnership’s related party receivables and related party payables included $18,501,000 and $422,000, respectively, from and to subsidiaries of Enterprise GP.

10. Segment Information

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

The Partnership has four reportable segments: (a) gathering and processing, (b) transportation, (c) contract compression and (d) corporate and others. Gathering and processing involves collecting raw natural gas from producer wells and transporting it to treating plants where water and other impurities such as hydrogen sulfide and carbon dioxide are removed. Treated gas is then processed to remove the natural gas liquids. The treated and processed natural gas is then transported to market separately from the natural gas liquids. 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 of the Partnership’s 49.99 percent interest in HPC, which we operate, and the 49.9 percent interest in MEP. Prior periods have been restated to reflect the Partnership’s then wholly-owned subsidiary of Regency Intrastate Gas LLC as the exclusive reporting unit within this segment. The transportation segment uses pipelines to transport natural gas from receipt points on its system to interconnections with other pipelines, storage facilities or end-use markets. RIG performs transportation services for shipping customers under firm or interruptible arrangements. In either case, revenues are primarily fee based and involve minimal direct exposure to commodity price fluctuations. The north Louisiana intrastate pipeline operated by this segment serves the Partnership’s gathering and processing facilities in the same area and those transactions create a portion of the intersegment 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 on-going operation, service, and repair of its compression units, which are modified as necessary to adapt to customers’ changing operating conditions. The contract compression segment also provides services to certain operations in the gathering and processing segment, creating a portion of the intersegment revenues shown in the table below.

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

Management evaluates the performance of each segment and makes capital allocation decisions through the separate consideration of segment margin and operation and maintenance expenses. Segment margin, for the gathering and processing and for the transportation segments, is defined as total 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 revenues generating

Page | 21

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

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 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 Revenues
Period from May 26, 2010 to June 30, 2010	$	90,147		$	—		$	12,053	$	780		$	—		$	102,980
Period from April 1, 2010 to May 25, 2010		183,582			—			23,992		3,921			—			211,495
For the three months ended June 30, 2009		209,939			1,531			39,011		3,061			—			253,542
Period from January 1, 2010 to May 25, 2010		460,423			—			58,971		9,853			—			529,247
For the six months ended June 30, 2009		453,093			9,075			77,499		3,853			—			543,520
Intersegment Revenues
Period from May 26, 2010 to June 30, 2010		—			—			1,999		22			(2,021	)		—
Period from April 1, 2010 to May 25, 2010		—			—			3,794		53			(3,847	)		—
For the three months ended June 30, 2009		(6,745	)		(128	)		975		40			5,858			—
Period from January 1, 2010 to May 25, 2010		—			—			9,126		91			(9,217	)		—
For the six months ended June 30, 2009		(8,755	)		4,936			1,785		144			1,890			—
Cost of Sales
Period from May 26, 2010 to June 30, 2010		73,311			—			1,564		(772	)		(22	)		74,081
Period from April 1, 2010 to May 25, 2010		144,768			—			2,460		87			(53	)		147,262
For the three months ended June 30, 2009		144,816			1,243			4,186		269			6,833			157,347
Period from January 1, 2010 to May 25, 2010		366,900			—			5,741		(679	)		(91	)		371,871
For the six months ended June 30, 2009		327,284			2,297			6,504		116			3,674			339,875
Segment Margin
Period from May 26, 2010 to June 30, 2010		16,836			—			12,488		1,574			(1,999	)		28,899
Period from April 1, 2010 to May 25, 2010		38,814			—			25,326		3,887			(3,794	)		64,233
For the three months ended June 30, 2009		58,378			160			35,800		2,832			(975	)		96,195
Period from January 1, 2010 to May 25, 2010		93,523			—			62,356		10,623			(9,126	)		157,376
For the six months ended June 30, 2009		117,054			11,714			72,780		3,881			(1,784	)		203,645
Operation and Maintenance
Period from May 26, 2010 to June 30, 2010		8,814			—			4,924		203			(1,999	)		11,942
Period from April 1, 2010 to May 25, 2010		15,400			—			9,698		126			(3,794	)		21,430
For the three months ended June 30, 2009		22,044			(174	)		11,487		(181	)		(1,202	)		31,974
Period from January 1, 2010 to May 25, 2010		39,161			—			23,476		327			(9,123	)		53,841
For the six months ended June 30, 2009		44,349			2,112			24,028		132			(2,605	)		68,016
Depreciation and Amortization
Period from May 26, 2010 to June 30, 2010		7,413			—			3,323		259						10,995
Period from April 1, 2010 to May 25, 2010		11,576			—			6,353		680			—			18,609
For the three months ended June 30, 2009		16,413			—			8,955		868			—			26,236
Period from January 1, 2010 to May 25, 2010		28,864			—			15,560		1,660			—			46,084
For the six months ended June 30, 2009		33,134			2,448			16,982		1,561			—			54,125
Income from Unconsolidated Subsidiaries
Period from May 26, 2010 to June 30, 2010		—			8,121			—		—						8,121
Period from April 1, 2010 to May 25, 2010		—			7,959			—		—			—			7,959
For the three months ended June 30, 2009		—			1,587			—		—			—			1,587
Period from January 1, 2010 to May 25, 2010		—			15,872			—		—						15,872
For the six months ended June 30, 2009		—			1,923			—		—			—			1,923
Assets
June 30, 2010		1,751,253			1,369,921			1,362,549		111,569			—			4,595,292
December 31, 2009		1,046,619			453,120			926,213		107,462			—			2,533,414
Investment in Unconsolidated Subsidiaries
June 30, 2010		—			1,369,921			—		—			—			1,369,921
December 31, 2009		—			453,120			—		—			—			453,120
Goodwill
June 30, 2010		286,634			—			447,040		—			—			733,674
December 31, 2009		63,232			—			164,882		—			—			228,114
Expenditures for Long-Lived Assets
Period from May 26, 2010 to June 30, 2010		15,300			—			5,208		367			—			20,875
Period from January 1, 2010 to May 25, 2010		43,666			—			18,418		1,703						63,787
For the six months ended June 30, 2009		44,639			22,367			50,959		1,220			—			119,185

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

Page | 22

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

	Successor			Predecessor
	Period from Acquisition (May 26, 2010) to June 30, 2010			Period from April 1, 2010 to Disposition (May 25, 2010)			Three Months Ended June 30, 2009			Period from January 1, 2010 to Disposition (May 25, 2010)			Six Months Ended June 30, 2009
	(in thousands)			(in thousands)
Net (loss) income attributable to Regency Energy Partners LP	$	(4,924	)	$	(4,740	)	$	5,890		$	(5,352	)	$	154,279
Add (deduct):
Operation and maintenance		11,942			21,430			31,974			53,841			68,016
General and administrative		7,104			21,809			14,127			37,212			29,205
Loss (gain) on asset sales, net		10			19			651			303			(133,280	)
Depreciation and amortization		10,995			18,609			26,236			46,084			54,125
Income from unconsolidated subsidiaries		(8,121	)		(7,959	)		(1,587	)		(15,872	)		(1,923	)
Interest expense, net		8,109			14,114			19,568			36,459			33,795
Other income and deductions, net		3,510			624			(214	)		3,891			(256	)
Income tax expense (benefit)		245			83			(515	)		404			(416	)
Net income attributable to the noncontrolling interest		29			244			65			406			100
Total segment margin	$	28,899		$	64,233		$	96,195		$	157,376		$	203,645

11. Equity-Based Compensation

The Partnership’s LTIP for its employees, directors and consultants authorizes grants up to 2,865,584 common units. Because control changed from GE EFS to ETE, all then outstanding LTIP, exclusive of the May 7, 2010 phantom unit grant described below, vested during the predecessor period and the Partnership recorded a one-time general and administrative charge of $9,893,000 as a result of the vesting of these units on May 25, 2010. LTIP compensation expense of $137,000, $10,431,000, $12,070,000, $1,561,000 and $2,750,000 is recorded in general and administrative expense in the statement of operations for the periods from May 26, 2010 to June 30, 2010, April 1, 2010 to May 25, 2010 and January 1, 2010 to May 25, 2010, and for the three and six months ended June 30, 2009, respectively.

Common Unit Option and Restricted (Non-Vested) Units.

The common unit options activity for the six months ended June 30, 2010 is as follows.

Common Unit Options	Units		Weighted Average Exercise Price		Weighted Average Contractual Term (Years)	Aggregate Intrinsic Value *(in thousands)
Outstanding at the beginning of period	306,651		$	21.50
Granted	—			—
Exercised	(13,500	)		20.00
Forfeited or expired	(3,001	)		23.73
Outstanding at end of period	290,150			21.57	5.8	833
Exercisable at the end of the period	290,150					833

* 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.

During the six months ended June 30, 2010, the Partnership received $270,000 in proceeds from the exercise of unit options.

The restricted (non-vested) common unit activity for the six months ended June 30, 2010 is as follows.

			Weighted Average Grant Date
Restricted (Non-Vested) Common Units	Units		Fair Value
Outstanding at the beginning of the period	464,009		$	28.36
Granted	—			—
Vested	(444,759	)		28.19
Forfeited or expired	(19,250	)		32.35
Outstanding at the end of period	—			—

Phantom Units. The Partnership’s phantom units are in substance two grants composed of (1) service condition grants with graded vesting over three years; and (2) market condition grants with cliff vesting based upon the Partnership’s relative ranking in total unitholder return among 20 peer companies, as disclosed in Item 11 of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2009. As control changed from GE EFS to ETE, all outstanding phantom units, exclusive of the May 7, 2010 grant described below, vested. The service condition grants vested at a rate of 100 percent and the market condition grants vested at a rate of 150 percent pursuant to the terms of the award.

Page | 23

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

The Partnership awarded 247,500 phantom units to senior management and certain key employees on May 7, 2010. These phantom units include a provision that will accelerate vesting (1) upon a change in control and (2) within 12 months of a change in control, if termination without “Cause” (as defined) or resignation for “Good Reason” (as defined) occurs, the phantom units will vest. The Partnership expects to recognize $3,187,000 of compensation expense related to non-vested phantom units over a period of 2.8 years.

The following table presents phantom unit activity for the six months ended June 30, 2010.

Phantom Units	Units		Weighted Average  Grant Date Fair Value
Outstanding at the beginning of the period	301,700		$	8.63
Service condition grants	108,500			20.76
Market condition grants	148,500			11.89
Vested service condition	(138,313	)		13.97
Vested market condition	(168,420	)*		4.65
Forfeited service condition	(6,467	)		19.30
Forfeited market condition	(10,500	)		10.20
Total outstanding at end of period	235,000			16.31

* Upon the change in control, these awards converted into 252,630 common units.

12. Fair Value Measures

The fair value measurement provisions establish a three-tiered fair value hierarchy that prioritizes inputs to valuation techniques used in fair value calculations. The three levels of inputs are defined as follows:

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

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

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

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

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

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

	Fair Value Measurement at June 30, 2010				Fair Value Measurement at December 31, 2009
	Fair Value Total	Quoted Prices in Active Markets (Level 1)	Significant Observable Inputs (Level 2)	Unobservable Inputs (Level  3)	Fair Value Total	Quoted Prices in Active Markets (Level 1)	Significant Observable Inputs (Level 2)	Unobservable Inputs (Level 3)
	(in thousands)
Assets
Commodity Derivatives:
Natural Gas	3,125	—	3,125	—	602	—	602	—
Natural Gas Liquids	12,222	—	12,222	—	15,484	—	15,484	—
Condensate	5,727	—	5,727	—	9,108	—	9,108	—
Total Assets	21,074	—	21,074	—	25,194	—	25,194	—
Liabilities
Interest rate swaps	1,877	—	1,877	—	1,064	—	1,064	—
Commodity Derivatives:		—		—		—		—
Natural Gas	15	—	15	—	51	—	51	—
Natural Gas Liquids	2,025	—	2,025	—	15,034	—	15,034	—
Condensate	29	—	29	—	416	—	416	—
Series A Preferred Units	52,239	—	—	52,239	44,594	—	—	44,594
Total Liabilities	56,185	—	3,946	52,239	61,159	—	16,565	44,594

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Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

The following table presents the changes in Level 3 derivatives measured on a recurring basis for the six months ended June 30, 2010.

	Derivatives related to Series A Preferred Units
	(in thousands)
Beginning Balance- December 31, 2009	$	44,594
Net unrealized losses included in other income and deductions, net		4,039
Ending Balance- May 25, 2010		48,633
Net unrealized losses included in other income and deductions, net		3,606
Ending Balance- June 30, 2010	$	52,239

The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to their short-term maturities. Restricted cash and related escrow payable approximates fair value due to the relatively short-term settlement period of the escrow payable. Long-term debt, other than the senior notes, is comprised of borrowings which incur interest under a floating interest rate structure. Accordingly, the carrying value approximates fair value. The estimated fair values of the senior notes due 2013 and 2016, based on third party market value quotations as of June 30, 2010, were $369,119,000 and $265,000,000, respectively.

13. Subsequent Events

On July 27, 2010, the Partnership declared a distribution of $0.445 per outstanding common unit and Series A Preferred Unit, including units equivalent to the General Partner’s two percent interest in the Partnership, and a distribution with respect to incentive distribution rights of approximately $915,000, payable on August 13, 2010, to unitholders of record at the close of business on August 6, 2010.

On July 15, 2010, the Partnership sold its gathering and processing assets located in east Texas to an affiliate of Tristream Energy LLC for approximately $70,000,000. The Partnership plans to use the proceeds from the sale of the assets to fund future capital expenditures.

On August 6, 2010, the Partnership agreed to acquire Zephyr Gas Services, LLC, a field services company for approximately $185,000,000.

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