Edgar Filing: Regency Energy Partners LP

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

RGP-9.30.11-10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2011



¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 001-35262

REGENCY ENERGY PARTNERS LP

(Exact name of registrant as specified in its charter)



DELAWARE		16-1731691
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

2001 BRYAN STREET, SUITE 3700 DALLAS, TX		75201
(Address of principal executive offices)		(Zip Code)

(214) 750-1771

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer, accelerated filer and small reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No ý

The issuer had 157,343,942 common units outstanding as of October 25, 2011.

Table of Contents

FORM 10-Q

TABLE OF CONTENTS

Regency Energy Partners LP



PART I – FINANCIAL INFORMATION

ITEM 1.	FINANCIAL STATEMENTS (Unaudited)

Condensed Consolidated Balance Sheets		2

Condensed Consolidated Statements of Operations		3

Condensed Consolidated Statements of Comprehensive Income		5

Condensed Consolidated Statements of Cash Flows		6

Condensed Consolidated Statement of Partners’ Capital and Noncontrolling Interest		7

Notes to Condensed Consolidated Financial Statements		8

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	26

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	40

ITEM 4.	CONTROLS AND PROCEDURES	41

PART II – OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS	42

ITEM 1A.	RISK FACTORS	42

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	42

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	42

ITEM 4.	[REMOVED AND RESERVED]	42

ITEM 5.	OTHER INFORMATION	43

ITEM 6.	EXHIBITS	43

SIGNATURE		44

Table of Contents

Introductory Statement

References in this report to the “Partnership,” “we,” “our,” “us” and similar terms, when used in an historical context, refer to Regency Energy Partners LP and its subsidiaries. When used in the present tense or prospectively, these terms refer to the Partnership and its subsidiaries. We use the following definitions in this quarterly report on Form 10-Q:



	Name		Definition or Description
	/d		Per day
	AOCI		Accumulated Other Comprehensive Income
	Bbls		Barrels
	BTU		A unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit
	EPD		Enterprise Products Partners L.P.
	ETC		Energy Transfer Company, the name assumed by La Grange Acquisition, L.P. for conducting business and shared services, a wholly owned subsidiary of ETP
	ETE		Energy Transfer Equity, L.P.
	ETE GP		ETE GP Acquirer LLC
	ETP		Energy Transfer Partners, L.P.
	FASB		Financial Accounting Standards Board
	Finance Corp.		Regency Energy Finance Corp., a wholly-owned subsidiary of the Partnership
	GAAP		Accounting principles generally accepted in the United States of America
	GE EFS		General Electric Energy Financial Services, combined with Regency GP Acquirer, L.P. and Regency LP Acquirer, L.P.
	General Partner		Regency GP LP, the general partner of the Partnership, or Regency GP LLC, the general partner of Regency GP LP, which effectively manages the business and affairs of the partnerships
	GPM		Gallons per minute
	GP Seller		Regency GP Acquirer, L.P.
	HPC		RIGS Haynesville Partnership Co., a general partnership in which the Partnership owns a 49.99% interest and its 100% owned subsidiary, Regency Intrastate Gas LP
	IDRs		Incentive Distribution Rights
	IRS		Internal Revenue Service
	LDH		LDH Energy Asset Holdings LLC
	LIBOR		London Interbank Offered Rate
	Lone Star		Lone Star NGL LLC, a joint venture that is 30% owned by the Partnership and 70% owned by ETP
	LTIP		Long-Term Incentive Plan
	MEP		Midcontinent Express Pipeline LLC, a joint venture in which the Partnership currently owns a 50% interest
	MMBtu		One million BTUs
	NGLs		Natural gas liquids, including ethane, propane, normal butane, iso butane and natural gasoline
	NYMEX		New York Mercantile Exchange
	Partnership		Regency Energy Partners LP
	RGS		Regency Gas Services LP, a wholly-owned subsidiary of the Partnership
	RIGS		Regency Intrastate Gas System
	SEC		Securities and Exchange Commission
	Series A Preferred Units		Series A convertible redeemable preferred units
	Services Co.		ETE Services Company, LLC, a wholly owned subsidiary of ETE
	WTI		West Texas Intermediate Crude
	Zephyr		Zephyr Gas Services LLC, a wholly owned subsidiary of the Partnership

Table of Contents

Cautionary Statement about Forward-Looking Statements

Certain matters discussed in this report include “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “will,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may” or similar expressions help identify forward-looking statements. Although we believe our forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, we cannot give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions including without limitation the following:

•volatility in the price of oil, natural gas, and NGLs;


•	declines in the credit markets and the availability of credit for us as well as for producers connected to our pipelines and our gathering and processing facilities, and for our customers of contract compression and contract treating businesses;


•	the level of creditworthiness of, and performance by, our counterparties and customers;


•	our access to capital to fund organic growth projects and acquisitions, and our ability to obtain debt or equity financing on satisfactory terms;


•	our use of derivative financial instruments to hedge commodity and interest rate risks;


•	the amount of collateral required to be posted from time-to-time in our transactions;


•	changes in commodity prices, interest rates and demand for our services;


•	changes in laws and regulations impacting the midstream sector of the natural gas industry, including those that relate to climate change and environmental protection and safety;


•	weather and other natural phenomena;


•	industry changes including the impact of consolidations and changes in competition;


•	regulation of transportation rates on our natural gas pipelines;


•	our ability to obtain indemnification related to cleanup liabilities and to clean up any hazardous materials release on satisfactory terms;


•	our ability to obtain required approvals for construction or modernization of our facilities and the timing of production from such facilities; and


•	the effect of accounting pronouncements issued periodically by accounting standard setting boards.

If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may differ materially from those anticipated, estimated, projected or expected.

Other factors that could cause our actual results to differ from our projected results are discussed in Item 1A of our December 31, 2010 Annual Report on Form 10-K, our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2011 and June 30, 2011 and "Part II – Other Information - Item 1A. Risk Factors" in this Quarterly Report on Form 10-Q.

Each forward-looking statement speaks only as of the date of the particular statement and we undertake no obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

iii

Table of Contents

PART I – FINANCIAL INFORMATION


Item 1.	Financial Statements

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 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.”

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Regency Energy Partners LP

Condensed Consolidated Balance Sheets

(in thousands)

(unaudited)



	September 30, 2011			December 31, 2010
ASSETS
Current Assets:
Cash and cash equivalents	$	5,231		$	9,400
Trade accounts receivable, net of allowance of $546 and $297	37,444			35,212
Accrued revenues	86,682			74,017
Related party receivables	34,750			32,342
Derivative assets	4,504			2,650
Other current assets	25,222			7,384
Total current assets	193,833			161,005
Property, Plant and Equipment:
Gathering and transmission systems	610,562			543,286
Compression equipment	839,606			812,428
Gas plants and buildings	189,251			185,741
Other property, plant and equipment	115,411			81,295
Construction-in-progress	227,527			97,439
Total property, plant and equipment	1,982,357			1,720,189
Less accumulated depreciation	(157,767		)	(59,971		)
Property, plant and equipment, net	1,824,590			1,660,218
Other Assets:
Investment in unconsolidated affiliates	1,924,183			1,351,256
Long-term derivative assets	3,696			23
Other, net of accumulated amortization of debt issuance costs of $8,393 and $3,326	41,447			37,758
Total other assets	1,969,326			1,389,037
Intangible Assets and Goodwill:
Intangible assets, net of accumulated amortization of $37,538 and $15,584	748,201			770,155
Goodwill	789,789			789,789
Total intangible assets and goodwill	1,537,990			1,559,944
TOTAL ASSETS	$	5,525,739		$	4,770,204
LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST
Current Liabilities:
Trade accounts payable	$	64,955		$	50,208
Accrued cost of gas and liquids	92,468			80,756
Related party payables	11,633			3,338
Deferred revenues, including related party amounts of $41 and $8,765	16,838			25,257
Derivative liabilities	12,435			13,172
Other current liabilities	48,252			23,419
Total current liabilities	246,581			196,150
Long-term derivative liabilities	36,633			61,127
Other long-term liabilities	6,167			6,521
Long-term debt, net	1,800,380			1,141,061
Commitments and contingencies
Series A Preferred Units, redemption amount of $84,659 and $83,891	71,091			70,943
Partners’ capital and noncontrolling interest:
Common units	3,003,341			2,940,732
General partner interest	330,783			333,077
Accumulated other comprehensive loss	(2,002		)	(11,099		)
Total partners’ capital	3,332,122			3,262,710
Noncontrolling interest	32,765			31,692
Total partners’ capital and noncontrolling interest	3,364,887			3,294,402
TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST	$	5,525,739		$	4,770,204

See accompanying notes to condensed consolidated financial statements

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Regency Energy Partners LP

Condensed Consolidated Statements of Operations

(in thousands except unit data and per unit data)

(unaudited)



	Three Months Ended September 30, 2011			Three Months Ended September 30, 2010
REVENUES
Gas sales, including related party amounts of $3,840 and $1,680	$	118,754		$	132,130
NGL sales, including related party amounts of $103,892 and $51,062	174,537			91,489
Gathering, transportation and other fees, including related party amounts of $6,141 and $5,680	91,596			72,184
Net realized and unrealized loss from derivatives	(5,380		)	(6,218		)
Other, including related party amounts of $2,665 and $1,111	10,760			7,303
Total revenues	390,267			296,888
OPERATING COSTS AND EXPENSES
Cost of sales, including related party amounts of $5,049 and $4,768	279,526			213,032
Operation and maintenance	37,950			34,306
General and administrative, including related party amounts of $4,225 and $2,500	17,350			18,072
(Gain) loss on asset sales, net	(131		)	200
Depreciation and amortization	41,956			32,205
Total operating costs and expenses	376,651			297,815
OPERATING INCOME (LOSS)	13,616			(927		)
Income from unconsolidated affiliates	30,946			21,754
Interest expense, net	(28,852		)	(20,379		)
Other income and deductions, net	15,050			7,524
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	30,760			7,972
Income tax (benefit) expense	(89		)	450
INCOME FROM CONTINUING OPERATIONS	$	30,849		$	7,522
DISCONTINUED OPERATIONS
Net income from operations of east Texas assets, including gain on disposal of $20 in 2010	—			324
NET INCOME	$	30,849		$	7,846
Net income attributable to noncontrolling interest	(549		)	(58		)
NET INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP	$	30,300		$	7,788
Amounts attributable to Series A Preferred Units	1,997			1,991
General partner’s interest, including IDRs	2,060			1,166
Limited partners’ interest in net income	$	26,243		$	4,631
Income from continuing operations per common unit:
Amount allocated to common units	$	26,243		$	4,314
Weighted average number of common units outstanding	145,842,735			128,387,929
Basic income from continuing operations per common unit	$	0.18		$	0.03
Diluted income from continuing operations per common unit	$	0.09		$	0.03
Distributions per unit	$	0.455		$	0.445
Basic and diluted income from discontinued operations per common unit	$	—		$	—
Basic and diluted net income per common unit:
Amount allocated to common units	$	26,243		$	4,631
Basic net income per common unit	$	0.18		$	0.04
Diluted net income per common unit	$	0.09		$	0.04

See accompanying notes to condensed consolidated financial statements

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Regency Energy Partners LP

Condensed Consolidated Statements of Operations

(in thousands except unit data and per unit data)

(unaudited)



	Successor						Predecessor
	Nine Months Ended September 30, 2011			Period from Acquisition (May 26, 2010) to September 30, 2010			Period from January 1, 2010 to May 25, 2010
REVENUES
Gas sales, including related party amounts of $15,479, $2,127 and $0	$	361,641		$	179,371		$	228,097
NGL sales, including related party amounts of $253,933, $69,116 and $0	430,876			117,529			152,803
Gathering, transportation and other fees, including related party amounts of $17,611, $7,766 and $12,200	255,249			94,755			114,526
Net realized and unrealized loss from derivatives	(14,636		)	(6,348		)	(716		)
Other, including related party amounts of $7,455, $1,111 and $0	30,887			8,561			10,340
Total revenues	1,064,017			393,868			505,050
OPERATING COSTS AND EXPENSES
Cost of sales, including related party amounts of $16,070, $7,049 and $6,564	755,262			283,206			357,778
Operation and maintenance	105,506			44,708			47,842
General and administrative, including related party amounts of $12,354, $3,333 and $0	54,010			25,176			37,212
Loss on asset sales, net	50			210			303
Depreciation and amortization	122,695			42,750			41,784
Total operating costs and expenses	1,037,523			396,050			484,919
OPERATING INCOME (LOSS)	26,494			(2,182		)	20,131
Income from unconsolidated affiliates	86,921			29,875			15,872
Interest expense, net	(73,548		)	(28,460		)	(36,321		)
Other income and deductions, net	20,105			4,003			(3,897		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	59,972			3,236			(4,215		)
Income tax (benefit) expense	(19		)	695			404
INCOME (LOSS) FROM CONTINUING OPERATIONS	$	59,991		$	2,541		$	(4,619	)
DISCONTINUED OPERATIONS
Net income (loss) from operations of east Texas assets, including gain on disposal of $20 in 2010 Successor period	—			410			(327		)
NET INCOME (LOSS)	$	59,991		$	2,951		$	(4,946	)
Net income attributable to noncontrolling interest	(1,073		)	(87		)	(406		)
NET INCOME (LOSS) ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP	$	58,918		$	2,864		$	(5,352	)
Amounts attributable to Series A Preferred Units	5,985			2,659			3,336
General partner’s interest, including IDRs	4,902			1,969			662
Amount allocated to non-vested common units	—			—			(79		)
Limited partners’ interest in net income (loss)	$	48,031		$	(1,764	)	$	(9,271	)
Income (loss) from continuing operations per common unit:
Amount allocated to common units	$	48,031		$	(2,165	)	$	(8,966	)
Weighted average number of common units outstanding	142,058,631			125,916,507			92,788,319
Basic income (loss) from continuing operations per common unit	$	0.34		$	(0.02	)	$	(0.10	)
Diluted income (loss) from continuing operations per common unit	$	0.23		$	(0.02	)	$	(0.10	)
Distributions per unit	$	1.35		$	0.445		$	0.89
Basic and diluted income from discontinued operations per common unit	$	—		$	—		$	—
Basic and diluted net income (loss) per common unit:
Amount allocated to common units	$	48,031		$	(1,764	)	$	(9,271	)
Basic net income (loss) per common unit	$	0.34		$	(0.01	)	$	(0.10	)
Diluted net income (loss) per common unit	$	0.23		$	(0.01	)	$	(0.10	)

See accompanying notes to condensed consolidated financial statements

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Regency Energy Partners LP

Condensed Consolidated Statements of Comprehensive Income

(in thousands)

(unaudited)



	Three Months Ended September 30,
	2011		2010
Net income	$	30,849	$	7,846
Net cash flow hedge amounts reclassified to earnings	5,282		—
Change in fair value of cash flow hedges	10,287		—
Comprehensive income	46,418		7,846
Comprehensive income attributable to noncontrolling interest	549		58
Comprehensive income attributable to Regency Energy Partners LP	$	45,869	$	7,788



	Successor					Predecessor
	Nine Months Ended September 30, 2011			Period from Acquisition (May 26, 2010) to September 30, 2010		Period from January 1, 2010 to May 25, 2010
Net income (loss)	$	59,991		$	2,951	$	(4,946	)
Net cash flow hedge amounts reclassified to earnings	14,276			—		2,145
Net change in fair value of cash flow hedges	(5,179		)	—		18,486
Comprehensive income	69,088			2,951		15,685
Comprehensive income attributable to noncontrolling interest	1,073			87		406
Comprehensive income attributable to Regency Energy Partners LP	$	68,015		$	2,864	$	15,279

See accompanying notes to condensed consolidated financial statements

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Regency Energy Partners LP

Condensed Consolidated Statements Cash Flows

(in thousands)

(unaudited)



	Successor						Predecessor
	Nine Months Ended September 30, 2011			Period from Acquisition (May 26, 2010) to September 30, 2010			Period from January 1, 2010 to May 25, 2010
OPERATING ACTIVITIES:
Net income (loss)	$	59,991		$	2,951		$	(4,946	)
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:
Depreciation and amortization, including debt issuance cost amortization and bond premium amortization	127,079			44,767			49,363
Write-off of debt issuance costs	—			—			1,780
Amortization of excess fair value of unconsolidated affiliates	4,385			—			—
Equity in earnings of unconsolidated affiliates	(91,306		)	(29,875		)	(15,872		)
Derivative valuation changes	(21,660		)	14,837			12,004
Loss on asset sales, net	50			190			303
Unit-based compensation expenses	2,444			440			12,070
Cash flow changes in current assets and liabilities:
Trade accounts receivable, accrued revenues and related party receivables	(13,298		)	13,307			(11,272		)
Other current assets	186			903			2,516
Trade accounts payable, accrued cost of gas and liquids, related party payables and deferred revenues	20,467			(30,026		)	8,649
Other current liabilities	24,833			(8,186		)	22,614
Distributions received from unconsolidated affiliates	91,306			29,875			12,446
Other assets and liabilities	(61		)	(701		)	(234		)
Net cash flows provided by operating activities	204,416			38,482			89,421
INVESTING ACTIVITIES:
Capital expenditures	(290,889		)	(88,202		)	(63,787		)
Capital contributions to unconsolidated affiliates	(23,646		)	(38,922		)	(20,210		)
Distribution in excess of earnings of unconsolidated affiliates	40,354			50,262			—
Acquisitions of investments in unconsolidated affiliates, net of cash received	(593,843		)	12,848			(75,114		)
Acquisition of Zephyr, net of $1,983 cash received	—			(191,313		)	—
Proceeds from asset sales	10,232			70,302			10,661
Net cash flows used in investing activities	(857,792		)	(185,025		)	(148,450		)
FINANCING ACTIVITIES:
Net borrowings (repayments) under revolving credit facility	160,000			(243,651		)	199,008
Proceeds from issuance of senior notes	500,000			—			—
Debt issuance costs	(9,955		)	(148		)	(15,728		)
Drafts payable	—			8,848			—
Partner contributions	—			19,724			—
Partner distributions	(199,640		)	(55,251		)	(86,078		)
Disposition of assets between entities under common control in excess of historical cost	66			—			(16,973		)
Distributions to noncontrolling interest	—			—			(1,135		)
Proceeds from issuance of common units under LTIP, net of tax withholding	655			145			(4,874		)
Proceeds from common unit issuances, net of issuance costs	203,917			399,872			(89		)
Distributions to Series A Preferred Units	(5,836		)	(1,945		)	(1,945		)
Net cash flows provided by financing activities	649,207			127,594			72,186
Net change in cash and cash equivalents	(4,169		)	(18,949		)	13,157
Cash and cash equivalents at beginning of period	9,400			22,984			9,827
Cash and cash equivalents at end of period	$	5,231		$	4,035		$	22,984
Supplemental cash flow information:
Non-cash capital expenditures	$	25,504		$	28,821		$	18,051
Issuance of common units for an acquisition	—			584,436			—
Deemed contribution from acquisition of assets between entities under common control	177			17,152			—
Release of escrow payable from restricted cash	—			1,011			500
Interest paid, net of amounts capitalized	47,303			32,425			5,410
Income taxes paid	—			634			378

See accompanying notes to condensed consolidated financial statements

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Regency Energy Partners LP

Condensed Consolidated Statement of Partners' Capital and Noncontrolling Interest

(in thousands except unit data)

(unaudited)



	Regency Energy Partners LP
	Units
	Common	Common Unitholders			General Partner Interest			Accumulated Other Comprehensive Loss			Noncontrolling Interest		Total
Balance - December 31, 2010	137,281,336	$	2,940,732		$	333,077		$	(11,099	)	$	31,692	$	3,294,402
Private common unit offering, net of costs	8,500,001	203,917			—			—			—		203,917
Issuance of common units under LTIP, net of forfeitures and tax withholding	62,605	655			—			—			—		655
Unit-based compensation expenses	—	2,444			—			—			—		2,444
Transfer of assets between entities under common control	—	—			243			—			—		243
Partner distributions	—	(192,313		)	(7,327		)	—			—		(199,640		)
Accrued distributions to phantom units	—	(238		)	—			—			—		(238		)
Net income	—	54,016			4,902			—			1,073		59,991
Distributions to Series A Preferred Units	—	(5,724		)	(112		)	—			—		(5,836		)
Accretion of Series A Preferred Units	—	(148		)	—			—			—		(148		)
Net cash flow hedge amounts reclassified to earnings	—	—			—			14,276			—		14,276
Change in fair value of cash flow hedges	—	—			—			(5,179		)	—		(5,179		)
Balance - September 30, 2011	145,843,942	$	3,003,341		$	330,783		$	(2,002	)	$	32,765	$	3,364,887

See accompanying notes to condensed consolidated financial statements

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Regency Energy Partners LP

Notes to Condensed Consolidated Financial Statements

(Tabular dollar amounts, except per unit data, are in thousands)

(unaudited)

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 and its subsidiaries. The Partnership and its subsidiaries are engaged in the business of gathering and processing, contract compression, treating, transportation, fractionation and storage of natural gas and NGLs. 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.

Basis of Presentation. In May 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 of the outstanding limited partner interests in the General Partner and, as a result of that position, controlled the Partnership. As a result of this transaction, the outstanding voting interests of the General Partner and control of the Partnership were transferred from GE EFS to ETE.

In connection with this change in control, the Partnership’s assets and liabilities were adjusted to fair value on the closing date (May 26, 2010) by application of “push-down” accounting (the “Push-down Adjustments”). 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, 2010. In the opinion 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. Certain prior year numbers have been reclassified to conform to the current year presentation.

Use of Estimates. The unaudited condensed consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made 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 condensed consolidated 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.

Recently Issued Accounting Standards. In September 2011, the FASB issued Accounting Standards Update No. 2011-08, Intangibles - Goodwill and Other (Topic 350): Testing Goodwill for Impairment ("ASU 2011-08"), which simplifies how entities test goodwill for impairment. ASU 2011-08 gives entities the option, under certain circumstances, to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether further impairment testing is necessary. ASU 2011-08 is effective for fiscal years beginning after December 15, 2011, and early adoption is permitted. The Partnership is currently evaluating early adoption of ASU 2011-08; however, the Partnership does not expect adoption of this standard will materially impact its financial position or results of operations.

Quarterly Distributions of Available Cash. Following are distributions declared by the Partnership subsequent to December 31, 2010:



Quarter Ended	Record Date	Payment Date	Cash Distributions (per common unit)
December 31, 2010	February 7, 2011	February 14, 2011	$	0.445
March 31, 2011	May 6, 2011	May 13, 2011	$	0.445
June 30, 2011	August 5, 2011	August 12, 2011	$	0.450
September 30, 2011	November 7, 2011	November 14, 2011	$	0.455

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Common Unit Offering. In October 2011, the Partnership issued 11,500,000 common units representing limited partner interests in a public offering at a price of $20.92 per common unit, resulting in net proceeds of $231.9 million which were used to repay outstanding borrowings under the revolving credit facility.

2. Income (Loss) per Limited Partner Unit

The following tables provide a reconciliation of the numerator and denominator of the basic and diluted earnings per unit computations for the three and nine months ended September 30, 2011. For the Predecessor period from January 1, 2010 to May 25, 2010 and the Successor period from May 26, 2010 to September 30, 2010, diluted earnings per unit equaled basic earnings per unit because all instruments were antidilutive.



	Three Months Ended September 30, 2011						Three Months Ended September 30, 2010
	Income (Numerator)			Units (Denominator)	Per-Unit Amount		Income (Numerator)		Units (Denominator)	Per-Unit Amount
Basic income from continuing operations per unit
Limited Partners’ interest	$	26,243		145,842,735	$	0.18	$	4,314	128,387,929	$	0.03
Effect of Dilutive Securities:
Common unit options	—			13,633			—		34,671
Phantom units *	—			281,320			—		204,960
Series A Preferred Units	(13,233		)	4,626,197			—		—
Diluted income from continuing operations per unit	$	13,010		150,763,885	$	0.09	$	4,314	128,627,560	$	0.03



	Nine Months Ended September 30, 2011
	Income (Numerator)			Units (Denominator)	Per-Unit Amount
Basic income from continuing operations per unit
Limited Partners’ interest	$	48,031		142,058,631	$	0.34
Effect of Dilutive Securities:
Common unit options	—			23,450
Phantom units *	—			237,192
Series A Preferred Units	(14,770		)	4,626,197
Diluted income from continuing operations per unit	$	33,261		146,945,470	$	0.23

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*	Amount assumes maximum conversion rate for market condition awards.

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



	Three Months Ended
	September 30, 2011	September 30, 2010
Common unit options	—	—
Phantom units *	—	—
Series A Preferred Units	—	4,584,192

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	Successor		Predecessor
	Nine Months Ended September 30, 2011	Period from Acquisition (May 26, 2010) to September 30, 2010	Period from January 1, 2010 to May 25, 2010
Restricted (non-vested) common units	—	—	396,918
Common unit options	—	288,500	298,400
Phantom units *	—	322,602	369,346
Series A Preferred Units	—	4,584,192	4,584,192

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*	Amount assumes maximum conversion rate for market condition awards.

3. Investment in Unconsolidated Affiliates

Lone Star. The Partnership contributed $592.7 million in cash to Lone Star in exchange for its 30% interest on May 2, 2011. Lone Star, a newly formed joint venture that is owned 70% by ETP and 30% by the Partnership, completed its acquisition of all of the membership interest in LDH, which previously had been a wholly-owned subsidiary of Louis Dreyfus Highbridge Energy LLC, for $1.98 billion in cash. To fund a portion of this capital contribution, the Partnership issued 8,500,001 common units representing limited partnership interests with net proceeds of $203.9 million.

Lone Star owns and operates an NGL storage, fractionation and transportation business. Lone Star's storage assets are primarily located in Mont Belvieu, Texas and its West Texas Pipeline transports NGLs through an intrastate pipeline system that originates in the Permian Basin in west Texas, passes through the Barnett Shale production area in north Texas and terminates at the Mont Belvieu storage and fractionation complex. Lone Star also owns and operates fractionation and processing assets located in Louisiana.

Lone Star is managed by a two-person board of directors, with the Partnership and ETP each having the right to appoint one director, and is operated by ETP. As of September 30, 2011, the carrying value of the Partnership’s interest in Lone Star was $615.1 million. Amounts recorded with respect to Lone Star for the period ended September 30, 2011 are summarized in the table below:



	Three Months Ended September 30, 2011
Contributions to Lone Star	$	24,630
Distributions received from Lone Star	18,900
Partnership's share of Lone Star's net income	9,285

	Period from Initial Contribution (May 2, 2011) to September 30, 2011
Contributions to Lone Star	$	616,311
Distributions received from Lone Star	18,900
Partnership's share of Lone Star's net income	17,673

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The summarized income statement information of Lone Star (on a 100% basis) is disclosed below:



	Three Months Ended September 30, 2011
Total revenues	$	146,596
Operating income	30,936
Net income	30,952

	Period from Initial Contribution (May 2, 2011) to September 30, 2011
Total revenues	$	245,416
Operating income	59,079
Net income	58,910

HPC. The Partnership owns a 49.99% general partner interest in HPC. As of September 30, 2011 and December 31, 2010, the carrying value of the Partnership’s general partner interest in HPC was $686.9 million and $698.8 million, respectively. Amounts recorded with respect to HPC for the three and nine months ended September 30, 2011 and 2010, including successor and predecessor periods, are summarized in the tables below:



	Three Months Ended September 30,
	2011		2010
Distributions received from HPC	$	15,022	$	32,966
Return of investment received from HPC	—		19,995
Partnership's share of HPC's net income	12,138		15,180
Amortization of excess fair value of investment in HPC	1,462		1,585



	Successor				Predecessor
	Nine Months Ended September 30, 2011		Period from Acquisition (May 26, 2010) to September 30, 2010		Period from January 1, 2010 to May 25, 2010
Contributions to HPC	$	—	$	—	$	20,210
Purchase of additional HPC Interest	—		—		75,114
Distributions received from HPC	49,863		32,966		12,446
Return of investment received from HPC	—		19,995		—
Partnership's share of HPC's net income	42,343		19,639		15,872
Amortization of excess fair value of investment in HPC	4,385		1,949		—

The summarized income statement information of HPC (on a 100% basis) is disclosed below:



	Three Months Ended September 30,
	2011		2010
Total revenues	$	43,809	$	49,409
Operating income	24,627		30,507
Net income	24,282		30,366

	Nine Months Ended September 30,
	2011		2010
Total revenues	$	141,043	$	128,973
Operating income	85,469		74,923
Net income	84,703		74,640

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MEP. On September 1, 2011, the Partnership purchased an additional 0.1% interest in MEP from ETP for $1.2 million in cash, bringing its total interest in MEP to 50%. Because this transaction occurred between entities under common control, partners' capital was increased by $0.2 million, which represented a deemed contribution of the excess carrying amount of ETP's investment of $1.4 million over the purchase price. As of September 30, 2011 and December 31, 2010, the carrying value of the Partnership’s interest in MEP was $622.2 million and $652.5 million, respectively. Amounts recorded with respect to MEP for the three and nine months ended September 30, 2011 and 2010 are summarized in the tables below:



	Three Months Ended September 30,
	2011		2010
Distributions received from MEP	$	19,238	$	27,176
Partnership's share of MEP's net income	10,985		8,159

	Nine Months Ended September 30, 2011		Period from Acquisition (May 26, 2010) to September 30, 2010
Distributions received from MEP	$	62,897	$	27,176
Partnership's share of MEP's net income	31,290		12,185

The summarized income statement information of MEP (on a 100% basis) is disclosed below:



	Three Months Ended September 30,
	2011		2010
Total revenues	$	65,853	$	56,997
Operating income	34,852		29,100
Net income	21,998		16,351



	Nine Months Ended September 30, 2011		Period from Acquisition (May 26, 2010) to September 30, 2010
Total revenues	$	195,620	$	78,266
Operating income	101,307		40,599
Net income	62,684		24,419

4. Derivative Instruments

Policies. The Partnership established comprehensive risk management policies and procedures to monitor and manage the market risks associated with commodity prices, counterparty credit and interest rates. The General Partner is responsible for delegation of transaction authority levels, and the Audit and Risk Management Committee of the General Partner is responsible for the oversight of these risks, including monitoring exposure limits. The Audit and 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 operations. The prices of these commodities are impacted by changes in the supply and demand as well as other market forces. 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 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.

At September 30, 2011, all of the Partnership’s commodity swaps were accounted for as cash flow hedges.

Interest Rate Risk. The Partnership is exposed to variable interest rate risk as a result of borrowings under its revolving credit facility. As of September 30, 2011, the Partnership had $445 million of outstanding borrowings exposed to variable interest rate risk. In April 2010, the Partnership entered into two-year interest rate swaps related to $250 million of borrowings under its

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revolving credit facility, effectively locking the base rate, exclusive of applicable margins, for these borrowings at 1.325% through April 2012. The Partnership accounts for these interest rate swaps using the mark-to-market method of accounting.

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

The Partnership is exposed to credit risk from its derivative counterparties. The Partnership does not require collateral from these counterparties. The Partnership deals primarily with financial institutions when entering into financial derivatives, and utilizes master netting agreements that allow for netting of swap contract 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 as of September 30, 2011 would be $8.2 million which would be reduced by $4 million due to the netting feature. The Partnership has elected to present assets and liabilities under master netting 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.

Quantitative Disclosures. The Partnership expects to reclassify $5.3 million of net hedging losses to revenues from accumulated other comprehensive loss in the next 12 months.

The Partnership’s derivative assets and liabilities, including credit risk adjustments, as of September 30, 2011 and December 31, 2010 are detailed below:



	Assets				Liabilities
	September 30, 2011		December 31, 2010		September 30, 2011		December 31, 2010
Derivatives designated as cash flow hedges:
Current amounts
Commodity contracts	$	4,504	$	2,650	$	11,357	$	11,421
Long-term amounts
Commodity contracts	3,696		23		365		3,271
Total cash flow hedging instruments	8,200		2,673		11,722		14,692
Derivatives not designated as cash flow hedges:
Current amounts
Interest rate contracts	—		—		1,078		1,751
Long-term amounts
Interest rate contracts	—		—		—		833
Embedded derivatives in Series A Preferred Units	—		—		36,268		57,023
Total derivatives not designated as cash flow hedges	—		—		37,346		59,607
Total derivatives	$	8,200	$	2,673	$	49,068	$	74,299

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The Partnership’s statement of operations for the three months ended September 30, 2011 and 2010 were impacted by derivative instruments activities as follows:



		Three Months Ended September 30, 2011			Three Months Ended September 30, 2010
		Change in Value Recognized in AOCI on Derivatives (Effective Portion)
Derivatives in cash flow hedging relationships:
Commodity derivatives		$	10,287		$	—

	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	$	(5,282	)	$	—

	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Recognized in Income on Ineffective Portion
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	$	21		$	—

	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Recognized in Income on Derivatives
Derivatives not designated in a hedging relationship:
Commodity derivatives (credit risk adjustment)	Revenues	$	(119	)	$	(6,218	)
Interest rate swap derivatives	Interest expense, net	99			(1,795		)
Embedded derivatives	Other income & deductions, net	15,230			7,321
		$	15,210		$	(692	)

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The Partnership’s statement of operations for the nine months ended September 30, 2011 and 2010 were impacted by derivative instruments activities as follows:



		Successor						Predecessor
		Nine Months Ended September 30, 2011			Period from Acquisition (May 26, 2010) to September 30, 2010			Period from January 1, 2010 to May 25, 2010
		Change in Value Recognized in AOCI on Derivatives (Effective Portion)
Derivatives in cash flow hedging relationships:
Commodity derivatives		$	(5,179	)	$	—		$	14,371

	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	$	(14,276	)	$	—		$	(5,200	)
Interest rate swap derivatives	Interest expense, net	—			—			(1,060		)
		$	(14,276	)	$	—		$	(6,260	)

	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Recognized in Income on Ineffective Portion
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	$	(253	)	$	—		$	(799	)

	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) from Designation Amortized from AOCI into Income
Derivatives not designated in a hedging relationship:
Commodity derivatives	Revenues	$	—		$	—		$	4,115

	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Recognized in Income on Derivatives
Derivatives not designated in a hedging relationship:
Commodity derivatives (credit risk adjustment)	Revenues	$	(107	)	$	(6,348	)	$	1,168
Interest rate swap derivatives	Interest expense, net	(388		)	(3,510		)	(824		)
Embedded derivatives	Other income & deductions, net	20,755			3,715			(4,039		)
		$	20,260		$	(6,143	)	$	(3,695	)

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5. Long-term Debt

Obligations in the form of senior notes and borrowings under the revolving credit facility are as follows:



	September 30, 2011			December 31, 2010
Senior notes	$	1,355,380		$	856,061
Revolving loans	445,000			285,000
Total	1,800,380			1,141,061
Less: current portion	—			—
Long-term debt	$	1,800,380		$	1,141,061
Availability under revolving credit facility:
Total credit facility limit	$	900,000		$	900,000
Revolving loans	(445,000		)	(285,000		)
Letters of credit	(20,000		)	(16,015		)
Total available	$	435,000		$	598,985

Scheduled maturities of long-term debt at September 30, 2011 are as follows:



Years Ending December 31,	Amount
2011 (remainder)	$	—
2012	—
2013	—
2014	445,000
2015	—
Thereafter	1,350,000		*
Total	$	1,795,000

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*	Excludes unamortized premiums of $5.4 million as of September 30, 2011.

Revolving Credit Facility. The Partnership’s $900 million revolving credit facility expires on June 15, 2014. The revolving credit facility and guarantees are senior to the Partnership’s and each guarantor’s unsecured obligations, to the extent of the value of the assets securing such obligations. The revolving credit facility contains financial covenants requiring RGS and its subsidiaries to maintain debt to consolidated EBITDA, as defined in the credit agreement, ratio less than 5.25. At September 30, 2011, RGS and its subsidiaries were in compliance with these covenants.

The outstanding balance 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 weighted average interest rate on the total amount outstanding under the Partnership's revolving credit facility as of September 30, 2011 was 3.03%.

On May 2, 2011, the Partnership amended its Fifth Amended and Restated Credit Agreement to permit the acquisition of equity interests in Lone Star and to allow for additional investments in Lone Star of up to $150 million.

Senior Notes. In May 2011, the Partnership and Finance Corp. issued $500 million in senior notes that mature on July 15, 2021 (the “2021 Notes”). The 2021 Notes bear interest at 6.5% payable semi-annually in arrears on January 15 and July 15, commencing January 15, 2012. The proceeds were used to repay borrowings outstanding under the Partnership’s revolving credit facility.

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At any time prior to July 15, 2014, the Partnership may redeem up to 35% of the senior notes at a price equal to 106.5% plus accrued interest. Beginning on July 15 of the years indicated below, the Partnership may redeem all or part of the 2021 Notes at the redemption prices, expressed as percentages of the principal amount, set forth below:



July 15 of year ending:		Percentage of Redemption
2016		103.250%
2017		102.167%
2018		101.083%
2019 and thereafter at 100%		100.000%

Upon a change of control, as defined in the indenture, followed by a rating decline within 90 days, each holder of the 2021 Notes will be entitled to require the Partnership to purchase all or a portion of its notes at a purchase price of 101% plus accrued interest and liquidated damages, if any. The Partnership's ability to purchase the notes upon a change of control will be limited by the terms of our debt agreements, including the Partnership's revolving credit facility.

The 2021 Notes contain various covenants that limit, among other things, the Partnership's ability, and the ability of certain of its subsidiaries, to:


•	incur additional indebtedness;


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


•	make certain investments;


•	incur liens;


•	enter into certain types of transactions with affiliates; and


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

If the 2021 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 subsidiaries guarantors will no longer be subject to many of the foregoing covenants. At September 30, 2011, the Partnership and its subsidiaries guarantors were in compliance with these covenants.

Finance Corp., co-issuer for all of the Partnership’s senior notes, has no operations and will not have revenues other than as may be incidental. Since the Partnership has no independent operations, the guarantees are fully unconditional and joint and several of its existing unconsolidated subsidiaries, except for one minor subsidiary, and the Partnership has not included condensed consolidated financial information of guarantors of the senior notes.

6. Commitments and Contingencies

Legal. The Partnership is involved in various claims, lawsuits and audits by taxing authorities 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.

Keyes Litigation. In August 2008, Keyes Helium Company, LLC (“Keyes”) filed suit against RGS, 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 the Partnership. No damages were awarded to the Plaintiffs. Plaintiffs have appealed the verdict. The hearing on appeal will likely take place in the first quarter of 2012.

7. Series A Preferred Units

On September 2, 2009, the Partnership issued 4,371,586 Series A Preferred Units. As of September 30, 2011, the Series A Preferred Units were convertible to 4,626,197 common units, and if outstanding, are mandatorily redeemable on September 2, 2029 for $80 million 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 ended March 31, 2010, if outstanding on the record dates of the Partnership’s common unit 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.

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The following table provides a reconciliation of the beginning and ending balances of the Series A Preferred Units for the nine months ended September 30, 2011:



	Units	Amount
Outstanding at beginning of period	4,371,586	$	70,943
Accretion to redemption value	—	148
Outstanding at end of period	4,371,586	$	71,091	*

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*	This amount will be accreted to $80 million plus any accrued and unpaid distributions by deducting amounts from partners’ capital over the remaining period until the mandatory redemption date of September 2, 2029.

8. Related Party Transactions

As of September 30, 2011 and December 31, 2010, details of the Partnership’s related party receivables and related party payables were as follows:



	September 30, 2011		December 31, 2010
Related party receivables
EPD and its subsidiaries	$	31,285	$	25,539
HPC	1,162		5,823
ETE and its subsidiaries	2,281		970
Other	22		10
Total related party receivables	$	34,750	$	32,342
Related party payables
EPD and its subsidiaries	$	1,199	$	1,323
HPC	355		760
ETE and its subsidiaries	10,066		1,245
Other	13		10
Total related party payables	$	11,633	$	3,338

Transactions with ETE and its subsidiaries. Under a May 26, 2010 service agreement with Services Co., Services Co. performs certain services for the Partnership. The Partnership pays Services Co.’s direct expenses for these services, plus an annual fee of $10 million, and receives the benefit of any cost savings recognized for these services. The services agreement has a five year term from May 26, 2010 to May 26, 2015, 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. Also, the Partnership, together with Regency GP LP and RGS entered into an operation and service agreement (the “Operations Agreement”) with ETC. Under the Operations Agreement, ETC will perform certain operations, maintenance and related services reasonably required to operate and maintain certain facilities owned by the Partnership. Pursuant to the Operations Agreement, the Partnership will reimburse ETC for actual costs and expenses incurred in connection with the provision of these services based on an annual budget agreed-upon by both parties. The Operations Agreement has an initial term of one year and automatically renews on a year-to-year basis upon expiration of the initial term.

The total fees related to these service contracts were $4.2 million and $12.4 million for the three and nine months ended September 30, 2011, respectively, $2.5 million for the three months ended September 30, 2010, and $3.3 million for the period from the acquisition, May 26, 2010 to September 30, 2010.

In conjunction with distributions by the Partnership to the limited and general partner interests, ETE received cash distributions of $14.4 million and $42.5 million during the three and nine months ended September 30, 2011, respectively, and $13.7 million for the period from May 26, 2010 to September 30, 2010.

The Partnership’s Contract Compression segment provides contract compression services to subsidiaries of ETP and records revenue in gathering, transportation and other fees on the statement of operations. The Partnership’s Contract Compression segment sold compression equipment to a subsidiary of ETP for $1.6 million and $7.9 million for the three and nine months ended September 30, 2011, respectively. As these transactions are between entities under common control, partners’ capital was increased by $66 thousand, which represented a deemed contribution of the excess sales price over the carrying amounts. The Partnership’s

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Contract Compression segment purchased compression equipment from a subsidiary of ETP for $6.2 million and $24.3 million for the three and nine months ended September 30, 2011, respectively.

On September 1, 2011, the Partnership purchased an additional 0.1% interest in MEP from ETP for $1.2 million in cash, bringing its total interest in MEP to 50%. Because this transaction occurred between entities under common control, partners' capital was increased by $0.2 million, which represented a deemed contribution of the excess carrying amount of ETP's investment of $1.4 million over the purchase price.

Prior to December 31, 2010, the employees operating the assets of the Partnership and its subsidiaries and all those providing staff or support services were 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. Effective January 1, 2011, certain employees of the Partnership became employees of ETP, and the Partnership reimburses ETP for all direct and indirect expenses incurred on behalf of the Partnership related to those employees. Reimbursements of $12.6 million, $47 million, $18 million, $23.6 million and $31.1 million were recorded to the General Partner during the three and nine months ended September 30, 2011, the three months ended September 30, 2010, from May 26, 2010 to September 30, 2010, and from January 1, 2010 to May 25, 2010, respectively, in the Partnership’s financial statements as operating expenses or general and administrative expenses. For the three and nine months ended September 30, 2011, reimbursements of $6.2 million and $14.8 million to ETP were recorded in the Partnership’s financial statements as operating expenses or general and administrative expenses.

Transactions with HPC. Under a master services agreement with HPC, the Partnership operates and provides all employees and services for the operation and management of HPC. During the three and nine months ended September 30, 2011, the three months ended September 30, 2010, from May 26, 2010 to September 30, 2010, and from January 1, 2010 to May 25, 2010, the related party general and administrative expenses reimbursed to the Partnership were $4.2 million, $12.6 million, $4.2 million, $5.6 million and $6.9 million, respectively, which is recorded in gathering, transportation and other fees on the statement of operations.

The Partnership’s Contract Compression segment provides contract compression services to HPC and records revenues in gathering, transportation and other fees in the statement of operations. The Partnership also receives transportation services from HPC and records it as cost of sales.

Transactions with EDP and its subsidiaries. EPD owns a portion of ETE’s outstanding common units; therefore, it 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 subsidiaries of EPD and records the revenues in gas sales and NGL sales. The Partnership also incurs NGL processing fees and transportation fees with subsidiaries of EPD and records these fees as cost of sales.

9. Segment Information

During the nine months ended September 30, 2011, the Partnership changed the name of the Transportation segment to Joint Ventures, which represents the Partnership’s equity method investments in its three unconsolidated affiliates: HPC, MEP and Lone Star. In addition, the disposition of the east Texas assets in July 2010 impacts the Gathering and Processing segment, as the results of those operations are now presented within discontinued operations and excluded from the segment information table. Also, operations within the Partnership's Contract Treating segment for the current year were presented in the Partnership's Contract Compression segment in the prior year. Accordingly, the Partnership has recast the segment information for the corresponding periods in 2010.

Gathering and Processing. The Partnership provides “wellhead-to-market” services to producers of natural gas, which include gathering raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate NGLs from the raw natural gas and selling or delivering pipeline-quality natural gas and NGLs to various markets and pipeline systems.

Joint Ventures. The Partnership owns a 49.99% general partner interest in HPC, which delivers natural gas from northwest Louisiana to downstream pipelines and markets through the 450 mile Regency Intrastate Gas pipeline system. The Partnership owns a 50% membership interest in MEP, which owns approximately 500 miles of natural gas pipeline stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi into Alabama. The Partnership owns a 30% membership interest in Lone Star, an entity owning a diverse set of midstream energy assets including pipelines, storage and processing facilities located in the states of Texas, Mississippi and Louisiana.

Contract Compression. The Partnership owns and operates a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems.

Contract Treating. The Partnership owns and operates a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management, to natural gas producers and midstream pipeline companies.

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Corporate and Others. The Corporate and Others segment comprises a 10-mile interstate pipeline and the Partnership’s corporate offices.

The Partnership accounts for intersegment revenues as if the revenues were to third parties, exclusive of certain cost of capital charges.

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 the Corporate and Others segments is defined as total revenues, including service fees, less cost of sales. In the Contract Compression segment and Contract Treating segment, segment margin is defined as revenues less direct costs.

Management believes segment margin is an important measure because it directly relates to volume, commodity price changes, revenue generating horsepower and revenue generating gallons per minute. 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. The Partnership does not record segment margin for the Joint Ventures segment because it records its ownership percentages of the net income in HPC, MEP and Lone Star as income from unconsolidated affiliates in accordance with the equity method of accounting.

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



	Three Months Ended
	September 30, 2011			September 30, 2010
External Revenues
Gathering and Processing	$	339,273		$	253,054
Joint Ventures	—			—
Contract Compression	36,024			36,172
Contract Treating	10,573			3,299
Corporate and Others	4,397			4,363
Eliminations	—			—
Total	$	390,267		$	296,888
Intersegment Revenues
Gathering and Processing	$	—		$	—
Joint Ventures	—			—
Contract Compression	3,339			5,869
Contract Treating	20			—
Corporate and Others	60			93
Eliminations	(3,419		)	(5,962		)
Total	$	—		$	—
Segment Margin
Gathering and Processing	$	64,716		$	42,723
Joint Ventures	—			—
Contract Compression	37,957			38,509
Contract Treating	6,642			2,730
Corporate and Others	4,767			5,763
Eliminations	(3,341		)	(5,869		)
Total	$	110,741		$	83,856
Operation and Maintenance
Gathering and Processing	$	24,426		$	23,978
Joint Ventures	—			—
Contract Compression	15,916			15,768
Contract Treating	902			322
Corporate and Others	41			107
Eliminations	(3,335		)	(5,869		)
Total	$	37,950		$	34,306

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	Successor				Predecessor
	Nine Months Ended September 30, 2011		Period from Acquisition (May 26, 2010) to September 30, 2010		Period from January 1, 2010 to May 25, 2010
External Revenues
Gathering and Processing	$	908,448	$	336,832	$	438,804
Joint Ventures	—		—		—
Contract Compression	112,532		48,226		58,971
Contract Treating	29,848		3,299		—
Corporate and Others	13,189		5,511		7,275