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~~March 3031, ~~2014~~2015



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

Commission file number 1-35262

REGENCY ENERGY PARTNERS LP

(Exact name of registrant as specified in its charter)

DELAWARE		16-1731691
(State or other jurisdiction ofincorporation or organization)		(I.R.S. EmployerIdentification No.)
2001 BRYAN STREET, SUITE 3700DALLAS, TX		75201
3738 OAK LAWN AVENUEDALLAS, TX		75219
(Address of principal executive offices)		(Zip Code)

(214) ~~750~~981-~~1771~~0700

(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 (§232.405 of this chapter) 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

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FORM 10-Q

TABLE OF CONTENTS

REGENCY ENERGY PARTNERS LP

PART I – FINANCIAL INFORMATION
ITEM 1.	FINANCIAL STATEMENTS (Unaudited)
	Condensed Consolidated Balance Sheets	1
	Condensed Consolidated Statements of Operations	2
	Condensed Consolidated Statements of Comprehensive Income	3
	Condensed Consolidated Statements of Comprehensive (Loss) Income	3
	Condensed Consolidated Statements of Cash Flows	4
	Condensed Consolidated Statement of Partners’ Capital and Noncontrolling Interest	5
	Notes to Condensed Consolidated Financial Statements	6
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	3122
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	4631
ITEM 4.	CONTROLS AND PROCEDURES	4732
PART II – OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	4832
ITEM 1A.	RISK FACTORS	4832
ITEM 4.	MINE SAFETY DISCLOSURES	4832
ITEM 6.	EXHIBITS	4933
SIGNATURE		5033

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Introductory Statement

References in this report to the “Partnership,” “we,” “our,” “us” and similar terms refer to Regency Energy Partners LP and its subsidiaries. We use the following definitions in this quarterly report on Form 10-Q:

Name		Definition or Description
/d		Per day
2018 Notes		$600 million of 6.875% senior notes that mature on December 1, 2018
AOCI		Accumulated Other Comprehensive Income (Loss)
Aqua - PVR		Aqua - PVR Water Services, LLC
ARO		Asset Retirement Obligation
Barclays		Barclays Capital Inc.
Bbls		Barrels
bps		Basis points
Citi		Citigroup Global Markets Inc.
Coal Handling		Coal Handling Solutions LLC, Kingsport Handling LLC, and Kingsport Services LLC
Eagle Rock		Eagle Rock Energy Partners, L.P.
ELG		Edwards Lime Gathering LLC and its wholly-owned subsidiaries, ELG Oil LLC and ELG Utility LLC
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 Common Holdings		ETE Common Holdings, LLC, a wholly-owned subsidiary of ETE
ETP		Energy Transfer Partners, L.P.
ETP GP		Energy Transfer Partners GP, L.P.
Exchange Act		Securities Exchange Act of 1934, as amended
Finance Corp.		Regency Energy Finance Corp., a wholly-owned subsidiary of the Partnership
GAAP		Accounting principles generally accepted in the United States of America
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 Partnership through its board of directors and Regency Employees Management LLC
Grey Ranch		Grey Ranch Plant LP, a former joint venture ~~between~~of the Partnership ~~and a subsidiary of SandRidge Energy, Inc.~~
Gulf States		Gulf States Transmission LLC, a wholly-owned subsidiary of the Partnership
Holdco		ETP Holdco Corporation
Hoover		Hoover Energy Partners, LP
HPC		RIGS Haynesville Partnership Co. and its wholly-owned subsidiary, Regency Intrastate Gas LP
IDRs		Incentive Distribution Rights
Lone Star		Lone Star NGL LLC
LTIP		Long-Term Incentive Plan
MBbls		One thousand barrels
MEP		Midcontinent Express Pipeline LLC
Mi Vida JV		Mi Vida JV LLC
MMBtu		One million BTUs. BTU is a unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit
NGLs		Natural gas liquids, including ethane, propane, normal butane, iso butane and natural gasoline
NYMEX		New York Mercantile Exchange
NMED		New Mexico Environmental Department
ORS		Ohio River System LLC
PADEP		Pennsylvania Department of Environmental Protection
Partnership		Regency Energy Partners LP
PEPL		Panhandle Eastern Pipe Line Company, LP
PVR		PVR Partners, L.P.
Ranch JV		Ranch Westex JV LLC
RGS		Regency Gas Services LP, a wholly-owned subsidiary of the Partnership
RIGS		Regency Intrastate Gas System
SEC		Securities and Exchange Commission
Senior Notes		The collective of 2019 Notes, 2020 Notes, 2020 PVR Notes, 2021 Notes, 2021 PVR Notes, 2022 Notes, October 2022 Notes, 2023 4.5% Notes and 2023 5.5% Notes
Series A Preferred Units		Series A convertible redeemable preferred units

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Name		Definition or Description
PEPL Holdings		PEPL Holdings, LLC, a former wholly-owned subsidiary of Southern Union that merged into PEPL
PVR		PVR Partners, L.P.
Ranch JV		Ranch Westex JV LLC
Regency Western		Regency Western G&P LLC, a wholly-owned subsidiary of the Partnership
RGS		Regency Gas Services LP, a wholly-owned subsidiary of the Partnership
RIGS		Regency Intrastate Gas System
SEC		Securities and Exchange Commission
Senior Notes		The collective of 2018 Notes, 2018 PVR Notes, 2020 Notes, 2020 PVR Notes, 2021 Notes, 2021 PVR Notes, 2022 Notes, 2023 5.5% Notes and 2023 4.5% Notes
Series A Preferred Units		Series A convertible redeemable preferred units
Services Co.		ETE Services Company, LLC
Southern Union		Southern Union Company
SUGS		Southern Union Gathering Company LLC
Sweeny JV		Sweeny Gathering, L.P.
TCEQ		Texas Commission on Environmental Quality
WTI		West Texas Intermediate Crude



Name		Definition or Description
Services Co.		ETE Services Company, LLC
Sweeny JV		Sweeny Gathering, L.P.
U.S.		United States
WTI		West Texas Intermediate Crude

iii

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Forward-Looking Statements

Certain matters discussed in this report include “forward-looking” statements. 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, condensate, NGLs and coal;

• ~~unexpected~~ETP’s ~~difficulties~~ability into ~~integrating~~successfully ~~any~~integrate ~~significant acquisitions into~~ our operations, ~~including~~and ~~the~~employees ~~PVR~~and ~~Acquisition,~~to ~~the~~realize ~~Eagle~~synergies ~~Rock Midstream Acquisition~~ and ~~the~~cost ~~Hoover Acquisition~~savings;


•	unexpected difficulties in integrating any significant acquisitions into our operations;


•	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 our contract services business;


•	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 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 or enforcement practices impacting the midstream sector of the natural gas industry, oil industry and the coal mining industry, including those that relate to climate change and environmental protection and safety, including with respect to emissions levels applicable to coal-burning power generators and permissible levels of mining runoff;


•	the adoption of new laws, or the promulgation of new regulations, at the federal, state or local level that promote use and development of renewable energy or limit use or development of fossil fuels;


•	weather and other natural phenomena;


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


•	regulation of transportation rates on our natural gas, NGL, and oil 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;


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


•	the extent to which the amount and quality of actual production of our coal differs from estimated recoverable coal reserves;


•	the experience and financial condition of our coal lessees, including our lessees’ ability to satisfy their royalty, environmental, reclamation and other obligations to us and others;


•	operating risks, including unanticipated geological problems, incidental to our Gathering and Processing segment and Natural Resources segment;


•	the ability of our lessees to produce sufficient quantities of coal on an economic basis from our reserves and obtain favorable contracts for such production;


•	delays in anticipated start-up dates of new development in our Gathering and Processing segment and our lessees’ mining operations and related coal infrastructure projects, including the timing of receipt of necessary governmental permits by us or our lessees; and


•	uncertainties relating to the effects of regulatory guidance on permitting under the Clean Water Act and the outcome of current and future litigation regarding mine permitting.

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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, ~~2013~~2014 Annual Report on Form 10-K ~~and in Part II — Other Information — Item 1A Risk Factors in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2014~~.

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.

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PART I – FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

REGENCY ENERGY PARTNERS LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)

	September 30, 2014			December 31, 2013
	March 31, 2015			December 31, 2014
ASSETS
Current Assets:
Cash and cash equivalents	$	1559		$	1924
Trade accounts receivable, net	542			292
Trade accounts receivable, net of allowance for doubtful accounts of $9 and $7	384			483
Related party receivables	5276			2845
Inventories	7163			4267
Other current assets	36			19
Derivative assets	65			75
Total current assets	716			400
Other current assets	16			9
Property, plant and equipment	9,915			5,050
Total current assets	663			703
Less accumulated depreciation and depletion	(922		)	(632		)
Property, plant and equipment	10,706			10,260
Property, plant and equipment, net	8,993			4,418
Less accumulated depreciation and depletion	(1,166		)	(1,043		)
Investments in unconsolidated affiliates	2,371			2,097
Property, plant and equipment, net	9,540			9,217
Other, net of accumulated amortization of debt issuance costs of $30 and $24	100			57
Investments in unconsolidated affiliates	2,484			2,418
Intangible assets, net of accumulated amortization of $179 and $107	3,472			682
Other, net of accumulated amortization of debt issuance costs of $30 and $28	101			103
Goodwill	1,528			1,128
Intangible assets, net of accumulated amortization of $244 and $212	3,405			3,439
TOTAL ASSETS	$	17,180		$	8,782
Goodwill	1,223			1,223
TOTAL ASSETS	$	17,416		$	17,103
LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST
Current Liabilities:
Drafts payable	$	23		$	2615
Trade accounts payable	~~559~~407			~~291~~529
Related party payables	4425			6964
Accrued interest	97			38
Accrued expenses	53			43
Other current liabilities	102			51
Accrued interest	105			81
Total current liabilities	825			475
Other current liabilities	30			24
Long-term derivative liabilities	31			19
Total current liabilities	643			756
Other long-term liabilities	74			30
Long-term derivative liabilities	14			16
Long-term debt, net	6,427			3,310
Other long-term liabilities	74			72
Long-term debt, net	7,221			6,641
Commitments and contingencies
Series A Preferred Units, redemption amounts of $38 and $38	3233			3233
Partners’ capital and noncontrolling interest:
Common units	8,~~741~~351			38,~~886~~531
Class F units	~~151~~155			~~146~~153
General partner interest	~~782~~770			~~782~~781
Total partners’ capital	9,~~674~~276			49,~~814~~465
Noncontrolling interest	~~117~~155			~~102~~120
Total partners’ capital and noncontrolling interest	9,~~791~~431			49,~~916~~585
TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST	$	17,~~180~~416		$	817,~~782~~103

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

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REGENCY ENERGY PARTNERS LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in millions, except unit data and per unit data)

(unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	Three Months Ended March 31,
	2014			2013			2014			2013
	2015			2014
REVENUES
Gas sales, including related party amounts of $23, $22, $58 and $56	$	549		$	213		$	1,359		$	600
Gas sales, including related party amounts of $8 and $13	$	374		$	335
NGL sales, including related party amounts of $89, $11, $196 and $23	555			286			1,308			766
NGL sales, including related party amounts of $123 and $50	254			331
Gathering, transportation and other fees, including related party amounts of $13, $6, $26 and $20	283			147			682			405
Gathering, transportation and other fees, including related party amounts of $5 and $6	315			172
Net realized and unrealized gain (loss) from derivatives	1811			(1013		)	—			—
Other	7845			2938			~~175~~			73
Total revenues	~~1,483~~999			~~665~~863			~~3,524~~			~~1,844~~
OPERATING COSTS AND EXPENSES
Cost of sales, including related party amounts of $19, $8, $45 and $35	1,051			477			2,517			1,309
Cost of sales, including related party amounts of $19 and $10	641			638
Operation and maintenance	~~129~~133			78			~~300~~			~~220~~
General and administrative	36			1333			~~123~~			64
Loss (gain) on asset sales, net	1			(1		)	(1		)	1
Gain on asset sales, net	—			(2		)
Depreciation, depletion and amortization	~~122~~158			7494			~~384~~			~~207~~
Total operating costs and expenses	~~1,339~~968			~~641~~841			~~3,323~~			~~1,801~~
OPERATING INCOME	~~144~~31			2422			~~201~~			43
Income from unconsolidated affiliates	5350			3743			~~143~~			~~103~~
Interest expense, net	(8682		)	(4156		)	~~(220~~		)	~~(119~~		)
Gain (loss) on debt refinancing, net	2			—			2			(7		)
Other income and deductions, net	3			2
Other income and deductions, net	(2		)	24			(7		)	3
INCOME BEFORE INCOME TAXES	2			11
INCOME BEFORE INCOME TAXES	111			44			119			23
Income tax expense (benefit)	5			(1		)
Income tax expense (benefit)	4			2			4			(1		)
NET (LOSS) INCOME	$	(3	)	$	12
NET INCOME	$	107		$	42		$	115		$	24
Net income attributable to noncontrolling interest	(4		)	(3		)
Net income attributable to noncontrolling interest	(4		)	(3		)	(11		)	(4		)
NET (LOSS) INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP	$	(7	)	$	9
NET INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP	$	103		$	39		$	104		$	20
Amounts attributable to Series A Preferred Units	1			1
Amounts attributable to Series A Preferred Units	1			1			3			5
General partner’s interest, including IDRs	—			5
General partner’s interest, including IDRs	10			3			22			8
Beneficial conversion feature for Class F units	2			2
Beneficial conversion feature for Class F units	1			2			5			3
Limited partners’ interest in net (loss) income	$	(10	)	$	1
Pre-acquisition loss from SUGS allocated to predecessor equity	—			—			—			(36		)
Basic and diluted net (loss) income per common unit:
Limited partners’ interest in net income	$	91		$	33		$	74		$	40
Amount allocated to common units	$	(10	)	$	1
Basic and diluted net income per common unit:
Weighted average number of common units outstanding	410,670,934			226,046,232
Amount allocated to common units	$	91		$	33		$	74		$	40
Basic (loss) income per common unit	$	(0.02	)	$	0.00
Weighted average number of common units outstanding	397,961,321			209,559,854			328,989,245			191,334,032
Diluted (loss) income per common unit	$	(0.02	)	$	0.00
Basic income per common unit	$	0.23		$	0.16		$	0.22		$	0.21
Distributions per common unit	$	—		$	0.48
Diluted income per common unit	$	0.23		$	0.05		$	0.22		$	0.21
Amount allocated to Class F units due to beneficial conversion feature	$	2		$	2
Distributions per common unit	$	0.5025		$	0.470		$	1.4725		$	1.395
Total number of Class F units outstanding	6,274,483			6,274,483
Amount allocated to Class F units due to beneficial conversion feature	$	1		$	2		$	5		$	3
Income per Class F unit due to beneficial conversion feature	$	0.27		$	0.27
Total number of Class F units outstanding	6,274,483			6,274,483			6,274,483			6,274,483
Income per Class F unit due to beneficial conversion feature	$	0.27		$	0.27		$	0.81		$	0.45

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

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REGENCY ENERGY PARTNERS LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

(Dollars in millions)

(unaudited)

	Three Months Ended September 30,					Nine Months Ended September 30,
	Three Months Ended March 31,
	2014			2013		2014		2013
	2015			2014
Net income	$	107		$	42	$	115	$	24
Net (loss) income	$	(3	)	$	12
Other comprehensive income	—			—		—		—
Total other comprehensive income	—			—		—		—
Comprehensive income	107			42		115		24
Comprehensive (loss) income	(3		)	12
Comprehensive income attributable to noncontrolling interest	4			3		11		4
Comprehensive income attributable to Regency Energy Partners LP	$	103		$	39	$	104	$	20
Comprehensive (loss) income attributable to Regency Energy Partners LP	$	(7	)	$	9

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

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REGENCY ENERGY PARTNERS LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

(unaudited)

	Nine Months Ended September 30,
	Three Months Ended March 31,
	2014			2013
	2015			2014
OPERATING ACTIVITIES:
Net income	$	115		$	24
Net (loss) income	$	(3	)	$	12
Reconciliation of net income to net cash flows provided by operating activities:
Reconciliation of net (loss) income to net cash flows provided by operating activities:
Depreciation, depletion and amortization, including debt issuance cost amortization and bond premium write-off and amortization	~~363~~158			~~211~~97
Income from unconsolidated affiliates	(~~143~~50		)	(~~103~~43		)
Derivative valuation changes	(39		)	317
Loss (gain) on asset sales, net	(1		)	1
Gain on asset sales, net	—			(2		)
Unit-based compensation expenses	84			52
Cash flow changes in current assets and liabilities:
Trade accounts receivable and related party receivables	~~(45~~64		)	(7321		)
Other current assets and other current liabilities	5235			~~(26~~35		)
Trade accounts payable and related party payables	73(149		)	~~103~~48
Distributions of earnings received from unconsolidated affiliates	~~147~~52			~~108~~43
Cash flow changes in other assets and liabilities	42			~~128~~(1		)
Net cash flows provided by operating activities	~~570~~122			~~381~~187
INVESTING ACTIVITIES:
Capital expenditures	(~~764~~457		)	(~~762~~215		)
Capital contributions to unconsolidated affiliates	(~~274~~90		)	(~~125~~40		)
Distributions in excess of earnings of unconsolidated affiliates	4721			~~232~~9
Acquisitions, net of cash received	~~(790~~—		)	(~~463~~213		)
Proceeds from asset sales	73			135
Net cash flows used in investing activities	(~~1,774~~523		)	(~~1,105~~454		)
FINANCING ACTIVITIES:
Repayments under revolving credit facility, net	(436		)	(15		)
Borrowings (repayments) under revolving credit facility, net	583			(519		)
Proceeds from issuances of senior notes	~~1,600~~—			~~1,000~~886
Redemptions of senior notes	(403		)	(163		)
Debt issuance costs	(1		)	(16		)
Debt issuance costs	(29		)	(24		)
Drafts payable	8			(8		)
Drafts payable	(3		)	8
Partner distributions and distributions on unvested unit awards	(218		)	(107		)
Partner distributions and distributions on unvested unit awards	(492		)	(282		)
Common units issued under unit offerings, equity distribution program and LTIP, net of issuance costs, forfeitures and tax withholding	34			34
Common unit offering, net of issuance costs	800			—
Distributions to Series A Preferred Units	(1		)	(1		)
Common units issued under equity distribution program, net of costs	162			149
Noncontrolling interest contributions (distributions), net	31			(8		)
Distributions to Series A Preferred Units	(3		)	(5		)
Net cash flows provided by financing activities	436			261
Noncontrolling interest contributions, net of distributions	4			15
Net change in cash and cash equivalents	35			(6		)
Net cash flows provided by financing activities	1,200			683
Cash and cash equivalents at beginning of period	24			19
Net change in cash and cash equivalents	(4		)	(41		)
Cash and cash equivalents at end of period	$	59		$	13
Cash and cash equivalents at beginning of period	19			53
Cash and cash equivalents at end of period	$	15		$	12
Supplemental cash flow information:
Accrued capital expenditures	$	6180		$	7024
Issuance of Class F and common units in connection with SUGS Acquisition	—			961
Interest paid, net of amounts capitalized	64			29
Interest paid, net of amounts capitalized	196			—
Issuance of common units in connection with PVR and Hoover acquisitions	—			4,015
Issuance of common units in connection with PVR, Hoover and Eagle Rock acquisitions	4,281			—
Long-term debt assumed in PVR Acquisition	—			1,887
Long-term debt assumed in PVR Acquisition	1,887			—
Long-term debt exchanged in connection with the Eagle Rock Midstream Acquisition	499			—

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

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REGENCY ENERGY PARTNERS LP

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

AND NONCONTROLLING INTEREST

(Dollars in millions)

(unaudited)

	Regency Energy Partners LP
	CommonUnits			Class F Units		GeneralPartnerInterest			NoncontrollingInterest		Total
Balance - December 31, 2013	$	3,886		$	146	$	782		$	102	$	4,916
Balance - December 31, 2014	$	8,531		$	153	$	781		$	120	$	9,585
Issuance of common units under equity distribution program, net of costs	~~162~~34			—		—			—		~~162~~34
Issuance of common units to ETE Common Holdings	800			—		—			—		800
Unit-based compensation expenses	3			—		—			—		3
Issuance of common units in connection with Hoover Acquisition	109			—		—			—		109
Partner distributions and distributions on unvested unit awards	(207		)	—		(11		)	—		(218		)
Issuance of common units in connection with PVR Acquisition	3,906			—		—			—		3,906
Noncontrolling interest contributions, net of distributions	—			—		—			31		31
Issuance of common units in connection with Eagle Rock Acquisition	266			—		—			—		266
Net (loss) income	(9		)	2		—			4		(3		)
Unit-based compensation expenses	8			—		—			—		8
Distributions to Series A Preferred Units	(1		)	—		—			—		(1		)
Partner distributions and distributions on unvested unit awards	(470		)	—		(22		)	—		(492		)
Balance - March 31, 2015	$	8,351		$	155	$	770		$	155	$	9,431
Noncontrolling interest contributions, net of distributions	—			—		—			4		4
Net income	77			5		22			11		115
Distributions to Series A Preferred Units	(3		)	—		—			—		(3		)
Balance - September 30, 2014	$	8,741		$	151	$	782		$	117	$	9,791

The accompanying notes are an integral part of these 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 millions)

(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”), a Delaware limited partnership. The Partnership and its subsidiaries are engaged in the business of gathering and processing, compression, treating and transportation of natural gas; the transportation, fractionation and storage of NGLs; the gathering, transportation and terminaling of oil (crude and/or condensate, a lighter oil) received from producers; natural gas and NGL marketing and trading, and the management of coal and natural resource properties in the United States. 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.

~~SUGS~~Merger ~~Acquisition~~with ETP. On April 30, ~~2013~~2015, the Partnership ~~and~~merged ~~Regency~~with ~~Western~~a ~~acquired~~wholly-owned ~~SUGS~~subsidiary ~~from~~of ~~Southern Union~~ETP, with the Partnership continuing as the surviving entity and becoming a wholly-owned subsidiary of ~~Holdco,~~ETP ~~for~~(the $1“Merger”).5 ~~billion~~At the effective time of the Merger (the “~~SUGS~~Effective ~~Acquisition~~Time”), each Partnership common unit and Class F unit converted into the right to receive 0.4124 ETP common units. Based on the Partnership units outstanding, ETP issued approximately 172.2 million ETP Common Units to the Partnership’s unitholders, including approximately 15.5 million units issued to ETP subsidiaries. Series A Preferred Units converted into the right to receive a preferred unit representing a limited partner interest in ETP, a new class of units in ETP established at the Effective Time. The merger was a combination of entities under common control; therefore, the carrying amounts of the Partnership's assets and liabilities will not be adjusted.

~~The~~Basis ~~Partnership~~of ~~accounted~~Presentation. ~~for~~The ~~the~~unaudited ~~acquisition~~financial ininformation aincluded ~~manner~~in ~~similar~~this toForm ~~the~~10-Q ~~pooling~~has ofbeen ~~interests~~prepared ~~method~~on ofthe ~~accounting~~same basis as itthe ~~was~~audited aconsolidated ~~transaction~~financial ~~between~~statements ~~commonly~~included ~~controlled~~in ~~entities. The~~the Partnership’s ~~retrospectively~~Annual ~~adjusted~~Report ~~its~~on ~~March~~Form 10-K for the year ended December 31, ~~2013~~2014. In the opinion of the Partnership’s management, such financial ~~statements~~information toreflects ~~include~~all adjustments necessary for a fair presentation of the ~~operations~~financial position and the results of ~~SUGS~~operations for such interim periods ~~prior~~in toaccordance ~~April~~with ~~30,~~GAAP. ~~2013~~All intercompany items and transactions have been eliminated in consolidation. ~~The~~Certain ~~SUGS~~information ~~Acquisition~~and ~~did~~footnote ~~not~~disclosures ~~impact~~normally ~~historical~~included ~~earnings~~in ~~per~~annual ~~unit~~consolidated asfinancial ~~pre-acquisition~~statements ~~earnings~~prepared ~~were~~in ~~allocated~~accordance with GAAP have been omitted pursuant to ~~predecessor~~the ~~equity.~~rules and regulations of the SEC.

The following table presents the revenues and net income for the previously separate entities and the combined amounts presented herein:

	Nine Months Ended September 30, 2013 (1)
Revenues:
Partnership	$	1,576
SUGS	268
Combined	$	1,844
Net income (loss):
Partnership	$	60
SUGS	(36		)
Combined	$	24

(1) The SUGS Acquisition closed on April 30, 2013. Therefore, amounts attributable to SUGS only include four months of activity for the nine months ended September 30, 2013.

Basis of Presentation. 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, 2013. 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.

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.

~~Equity Method Investments~~2. ~~Even~~PARTNERS’ ~~though~~CAPITAL ~~there~~AND is a presumption of a controlling financial interest in Aqua - PVR (because of our 51% ownership), our partner in this joint venture has substantive participating rights and management authority that preclude us from controlling the joint venture. Therefore, it is accounted for as an equity method investment.DISTRIBUTIONS

Beneficial Conversion Feature. The beneficial conversion feature, incurred as a result of the issuance of Class F units, is reflected in income per unit using the effective yield method over the period the Class F units are outstanding, as indicated on the statement of operations in the line item entitled “beneficial conversion feature for Class F units.” In connection with the Merger in April 2015, each Class F unit converted into the right to receive 0.4124 ETP common units.

Equity Distribution Agreement. During the three months ended March 31, 2015, the Partnership received net proceeds of $34 million from common units sold pursuant to an equity distribution agreement which were used for general partnership purposes. The Partnership did not issue any common units under the equity distribution agreement subsequent to March 31, 2015, and the equity distribution agreement terminated as a result of the ETP Merger in April 2015.

Units Activity. The change in common and Class F units during the three months ended March 31, 2015 was as follows:



	Common	Class F
Balance - December 31, 2014	409,406,482	6,274,483
Issuance of common units under LTIP, net of forfeitures and tax withholding	20,098	—
Issuance of common units under the equity distribution agreement	1,516,677	—
Balance - March 31, 2015	410,943,257	6,274,483

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~~Coal Royalties Revenues and Deferred Income~~3. ~~The~~(LOSS) ~~Partnership~~INCOME ~~recognizes~~PER ~~coal~~COMMON royalties revenues on the basis of tons of coal sold by its lessees and the corresponding revenues from those sales. The Partnership does not have access to actual production and revenues information until 30 days following the month of production. Therefore, financial results include estimated revenues and accounts receivable for the month of production. The Partnership records any differences between the actual amounts ultimately received or paid and the original estimates in the period they become finalized. Most lessees must make minimum monthly or annual payments that are generally recoverable over certain time periods. These minimum payments are recorded as deferred income. If the lessee recovers a minimum payment through production, the deferred income attributable to the minimum payment is recognized as coal royalties revenues. If a lessee fails to meet its minimum production for certain pre-determined time periods, the deferred income attributable to the minimum payment is recognized as minimum rental revenues, which is a component of other revenues on our consolidated statements of operations. Other liabilities on the balance sheet also include deferred unearned income from a coal services facility lease, which is recognized as other income as it is earned.UNIT

~~New~~The ~~Accounting~~following ~~Pronouncement.~~tables Inprovide ~~May~~a ~~2014,~~reconciliation of the ~~FASB~~numerator ~~issued~~and ~~Accounting~~denominator ~~Standards~~of ~~Update~~the ~~No.~~basic ~~2014-09,~~and ~~Revenue~~diluted ~~from Contracts with Customers~~ (~~Topic 606~~loss) ~~(“ASU~~earnings ~~2014-09”),~~per ~~which~~common ~~clarifies~~unit ~~the~~computations ~~principles~~ for ~~recognizing revenue based on~~ the ~~core~~three ~~principle~~months ~~that~~ended an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.March ~~ASU 2014-09 is effective for annual reporting periods beginning after December 15~~31, ~~2016,~~2015 ~~including~~and ~~interim periods within that reporting period, with earlier adoption not permitted. ASU~~ 2014-09 can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership is currently evaluating the impact, if any, that adopting this new accounting standard will have on our revenue recognition policies. :

2. PARTNERS’ CAPITAL AND DISTRIBUTIONS



	Three Months Ended March 31,
	2015							2014
	Loss (Numerator)			Units (Denominator)	Per-Unit Amount			Income (Numerator)		Units (Denominator)	Per-Unit Amount
Basic (loss) income per unit
Amount allocated to common units	$	(10	)	410,670,934	$	(0.02	)	$	1	226,046,232	$	0.00
Effect of Dilutive Securities:
Common unit options	—			—				—		22,787
Phantom units	—			—				—		424,332
Series A Preferred Units	—			—				—		2,054,217
Diluted (loss) income per unit	$	(10	)	410,670,934	$	(0.02	)	$	1	228,547,568	$	0.00

~~Beneficial Conversion Feature.~~ The ~~beneficial~~following ~~conversion~~data ~~feature,~~show ~~incurred~~securities asthat acould ~~result~~potentially ofdilute ~~the~~earnings ~~issuance of Class F units, is reflected in income~~ per unit ~~using~~in the ~~effective~~future ~~yield~~that ~~method~~were ~~over~~not ~~the~~included ~~period~~in the ~~Class~~computation ~~F units are outstanding, as indicated on the statement~~ of ~~operations~~diluted inearnings ~~the~~per ~~line~~unit ~~item~~because ~~entitled~~to ~~“beneficial~~do ~~conversion~~so ~~feature~~would ~~for~~have ~~Class~~been Fantidilutive ~~units.” The Class F units will convert to common units on a one-~~for~~-one~~ ~~basis~~the onperiods ~~May 8, 2015.~~ presented:

Equity Distribution Agreement. In June 2012, the Partnership entered into an equity distribution agreement with Citi under which the Partnership may offer and sell common units having an aggregate offering price of up to $200 million, from time to time through Citi, as sales agent for the Partnership. Sales of these units made from time to time under the equity distribution agreement were made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices, in block transactions, or as otherwise agreed upon by the Partnership and Citi. The Partnership used the net proceeds from the sale of these common units for general partnership purposes. During the nine months ended September 30, 2014, the Partnership received net proceeds of $34 million from common units sold pursuant to this equity distribution agreement. No amounts remained available to be issued under this agreement and it is no longer effective.



	Three Months Ended March 31, 2015
Common unit options	1,425
Phantom units	675,700
Series A preferred units	2,068,508

In May 2014, the Partnership entered into an equity distribution agreement with Barclays under which the Partnership may offer and sell common units having an aggregate offering price of up to $400 million, from time to time through Barclays, as sales agent for the Partnership4. ~~Sales~~INVESTMENTS ofIN ~~these~~UNCONSOLIDATED units made from time to time under the equity distribution agreement will be made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices, in block transactions, or as otherwise agreed upon by the Partnership and Barclays. The Partnership may also sell common units to Barclays as principal for its own account at a price agreed upon at the time of sale. Any sale of common units to Barclays as principal would be pursuant to the terms of a separate agreement between the Partnership and Barclays. The Partnership intends to use the net proceeds from the sale of these units for general partnership purposes. During the nine months ended September 30, 2014, the Partnership received net proceeds of $128 million from common units sold pursuant to this equity distribution agreement; $272 million remains available to be issued as of September 30, 2014. AFFILIATES

~~Common~~The ~~Units~~carrying ~~Sold.~~value ~~In June 2014, the Partnership sold 14.4 million common units to ETE Common Holdings for proceeds~~ of ~~$400 million. Proceeds from~~ the ~~issuance were used to pay down borrowings on the~~ Partnership’s ~~revolving~~investment ~~credit~~in ~~facility,~~each toof ~~redeem~~the ~~certain~~unconsolidated ~~senior~~affiliates ~~notes~~as of ~~the~~March 31, ~~Partnership~~2015 and ~~for~~December 31, ~~general partnership purposes. In July~~ 2014, ~~the~~is ~~Partnership~~as sold 16.5 million common units to ETE Common Holdings for proceeds of $400 million. Proceeds from the issuance were used to fund a portion of the cash consideration paid to Eagle Rock in connection with the Eagle Rock Midstream Acquisition. follows:



	Ownership	Type	March 31, 2015		December 31, 2014
HPC	49.99%	General Partner	$	417	$	422
MEP	50.00%	Membership Interest	687		695
Lone Star	30.00%	Membership Interest	1,217		1,162
Ranch JV	33.33%	Membership Interest	36		38
Aqua - PVR	51.00%	Membership Interest	45		46
Mi Vida JV	50.00%	Membership Interest	81		54
Others ⁽¹⁾			1		1
Total			$	2,484	$	2,418

⁽¹⁾ Others includes Coal Handling, Sweeny JV and Grey Ranch

The following tables summarize the Partnership’s investment activities in each of the unconsolidated affiliates for the three months ended March 31, 2015 and 2014:



	Three Months Ended March 31, 2015
	HPC			MEP			Lone Star			Ranch JV			Aqua - PVR			Mi Vida JV
Contributions to unconsolidated affiliates	$	—		$	—		$	63		$	—		$	—		$	27
Distributions from unconsolidated affiliates	(13		)	(20		)	(37		)	(3		)	—			—
Share of earnings of unconsolidated affiliates’ net income (loss)	9			12			29			2			(1		)	—
Amortization of excess fair value of investment	(1		)	—			—			—			—			—

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Units Activity. The change in common and Class F units during the nine months ended September 30, 2014 was as follows:



	Three Months Ended March 31, 2014
	HPC			MEP			Lone Star			Ranch JV		Grey Ranch
Contributions to unconsolidated affiliates	$	—		$	—		$	27		$	—	$	—
Distributions from unconsolidated affiliates	(10		)	(18		)	(25		)	—		—
Share of earnings of unconsolidated affiliates’ net income (loss)	7			11			25			2		(1		)
Amortization of excess fair value of investment	(1		)	—			—			—		—

	Common	Class F
Balance - December 31, 2013	210,850,232	6,274,483
Issuance of common units under LTIP, net of forfeitures and tax withholding	37,191	—
Issuance of common units under the equity distribution agreements	5,442,878	—
Issuance of common units in connection with Hoover Acquisition	4,040,471	—
Issuance of common units in connection with PVR Acquisition	140,388,382	—
Issuance of common units to ETE Common Holdings	30,890,565	—
Issuance of common units in connection with Eagle Rock Midstream Acquisition	8,245,859	—
Balance - September 30, 2014	399,895,578	6,274,483

The following tables present selected income statement data for each of the unconsolidated affiliates, on a 100% basis, for the three months ended March 31, 2015 and 2014:

Quarter Ended		Record Date	Payment Date		Cash Distributions(per common unit)
	Three Months Ended March 31, 2015
December 31, 2013		February 7, 2014	February 14, 2014		$0.475
	HPC			MEP		Lone Star		Ranch JV		Aqua - PVR
March 31, 2014		May 8, 2014	May 15, 2014		$0.480
Total revenues	$	38		$	62	$	803	$	8	$	—
June 30, 2014		August 7, 2014	August 14, 2014		$0.490
Operating income (loss)	22			31		97		5		(2		)
September 30, 2014		November 7, 2014	November 14, 2014		$0.5025
Net income (loss)	19			23		97		5		(2		)

3. INCOME PER COMMON UNIT



	Three Months Ended March 31, 2014
	HPC		MEP		Lone Star		Ranch JV
Total revenues	$	37	$	66	$	813	$	9
Operating income	18		34		84		7
Net income	15		21		83		6

~~The~~5. ~~following~~DERIVATIVE ~~tables provide a reconciliation of the numerator and denominator of the basic and diluted earnings per common unit computations for the three and nine months ended September 30, 2014 and 2013:~~INSTRUMENTS

	Three Months Ended September 30,
	2014					2013
	Income(Numerator)		Units(Denominator)	Per-UnitAmount		Income(Numerator)			Units(Denominator)	Per-UnitAmount
Basic income per unit
Amount allocated to common units	$	91	397,961,321	$	0.23	$	33		209,559,854	$	0.16
Effect of Dilutive Securities:
Common unit options	—		31,777			—			32,489
Phantom units	—		737,205			—			435,606
Series A Preferred Units	—		—			(23		)	2,047,571
Diluted income per unit	$	91	398,730,303	$	0.23	$	10		212,075,520	$	0.05

	Nine Months Ended September 30,
	2014					2013
	Income(Numerator)		Units(Denominator)	Per-UnitAmount		Income(Numerator)		Units(Denominator)	Per-UnitAmount
Basic income per unit
Amount allocated to common units	$	74	328,989,245	$	0.22	$	40	191,334,032	$	0.21
Effect of Dilutive Securities:
Common unit options	—		27,574			—		23,931
Phantom units	—		590,034			—		351,811
Diluted income per unit	$	74	329,606,853	$	0.22	$	40	191,709,774	$	0.21

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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, 2014			Nine Months Ended September 30, 2014			Nine Months Ended September 30, 2013
Series A Preferred Units	2,061,191			2,057,716			2,047,571

4. ACQUISITIONS

2014

Eagle Rock Midstream Acquisition. On July 1, 2014, the Partnership acquired Eagle Rock’s midstream business (the “Eagle Rock Midstream Acquisition”) for $1.3 billion, including the assumption of $499 million of Eagle Rock’s 8.375% Senior Notes due 2019. The remainder of the purchase price was funded by $400 million in common units sold to ETE Common Holdings, 8.2 million common units issued to Eagle Rock, and borrowings under the Partnership’s revolving credit facility. The Partnership is accounting for the Eagle Rock Midstream Acquisition using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. This acquisition is expected to complement the Partnership’s core gathering and processing business and is expected to further diversify the Partnership’s geographic presence in the mid-continent region, east Texas and south Texas. Revenues attributable to Eagle Rock’s operations included in the statement of operations for the three and nine months ended September 30, 2014 was $472 million. Net income attributable to Eagle Rock’s operations included in the statement of operations for the three and nine months ended September 30, 2014 was $18 million.

Management’s evaluation of the assigned fair values is ongoing. The table below represents a preliminary allocation of the total purchase price:

Assets	At July 1, 2014
Current assets	$	115
Property, plant and equipment	1,329
Other long-term assets	4
Total Assets Acquired	$	1,448
Liabilities
Current liabilities	$	109
Long-term debt	499
Long-term liabilities	12
Total Liabilities Assumed	$	620
Net Assets Acquired	$	828

The fair values of the assets acquired and liabilities assumed is being determined using various valuation techniques, including the income and market approaches.

PVR Acquisition. On March 21, 2014, the Partnership acquired PVR for a total purchase price of $5.7 billion (based on the Partnership’s closing price of $27.82 per unit on March 21, 2014), including $1.8 billion principal amount of assumed debt (“PVR Acquisition”). PVR unitholders received (on a per unit basis) 1.02 Partnership common units and a one-time cash payment of $36 million, which was funded through borrowings under the Partnership’s revolving credit facility. The PVR Acquisition enhances the Partnership’s geographic diversity with a strategic presence in the Marcellus and Utica shales in the Appalachian Basin and the Granite Wash in the Mid-Continent region. The Partnership accounted for the acquisition of PVR using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Revenues attributable to PVR’s operations included in the statement of operations for the three and nine months ended September 30, 2014 were $302 million and $653 million, respectively. Net income attributable to PVR’s operations included in the statement of operations for the three and nine months ended September 30, 2014 were $84 million and $119 million, respectively.

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Management completed the evaluation of the assigned fair values to the assets acquired and liabilities assumed. The total purchase price was allocated as follows:

Assets	At March 21, 2014
Current assets	$	149
Gathering and transmission systems	1,396
Compression equipment	342
Gas plants and buildings	110
Natural resources	454
Other property, plant and equipment	229
Construction in process	185
Investments in unconsolidated affiliates	62
Intangible assets	2,717
Goodwill (1)	370
Other long-term assets	18
Total Assets Acquired	$	6,032
Liabilities
Current liabilities	$	168
Long-term debt	1,788
Premium related to senior notes	99
Long-term liabilities	30
Total Liabilities Assumed	$	2,085
Net Assets Acquired	$	3,947

(1) Goodwill is reported in the Gathering and Processing segment.

The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.

Assets. Cash and cash equivalents, accounts receivable, net, other current assets, and construction in process, were valued using a cost basis as this basis approximates fair value due to the current nature of these items. Real property, including gathering and transmission systems, compression equipment, gas plants and buildings, and other property, plant and equipment, were valued based on a combination of the income, market and cost approaches, depending on the type of asset. Coal and timber reserves were valued using the income approach for active coal and timber reserves. The investments in unconsolidated affiliates were valued using the income approach. Intangible assets, other than goodwill, are customer contract related intangibles, which have an average useful life of 30 years, and have been valued using the income approach. The goodwill is the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized.

Liabilities. The Partnership assumed accounts payable, accrued liabilities, deferred income, and other long-term liabilities as part of the PVR Acquisition. The Partnership determined that the historical cost basis of these liabilities approximated fair value as they comprise normal operating liabilities. The Partnership assumed long-term debt as part of the acquisition, consisting of amounts outstanding under PVR’s revolving credit facility and PVR’s outstanding senior notes. The amount related to the revolving credit facility was valued at historical book value while the senior notes were valued using quoted market prices, which are considered Level 1 inputs.

Change in Control. The PVR Acquisition constituted a change of control for certain PVR employment agreements. Pursuant to the terms of those agreements, certain payments and benefits, including severance payments, were triggered by the PVR Acquisition. The Partnership recorded $10 million of severance payments due to the change in control and recorded $2 million in retention bonuses that were paid to various retained PVR employees upon the expiration of their retention period.

Hoover Energy Acquisition. On February 3, 2014, the Partnership acquired certain subsidiaries of Hoover for a total purchase price of $293 million, consisting of (i) 4,040,471 common units issued to Hoover and (ii) $184 million in cash, and (iii) $2 million in asset retirement obligations assumed (the “Hoover Acquisition”). The Hoover Acquisition increases the Partnership’s fee-based

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revenue, expanding its existing footprint in the southern portion of the Delaware Basin in west Texas, and its services to producers into crude and water gathering. A portion of the consideration is being held in escrow as security for certain indemnification claims. The Partnership financed the cash portion of the purchase price through borrowings under its revolving credit facility. The Partnership accounted for the Hoover Acquisition using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Revenues attributable to Hoover’s operations included in the statement of operations for the three and nine months ended September 30, 2014 were $11 million and $26 million, respectively. Net income attributable to Hoover’s operations included in the statement of operations for the three and nine months ended September 30, 2014 were losses of $2 million and income of $2 million, respectively.

Management completed the evaluation of the assigned fair values to the assets acquired and liabilities assumed. The total purchase price was allocated as follows:

Assets	At February 3, 2014
Accounts receivable, net	$	5
Gathering and transmission systems	60
Compression equipment	16
Gas plants and buildings	12
Other property, plant, and equipment	23
Construction in process	6
Intangible assets	148
Goodwill (1)	30
Total Assets Acquired	$	300
Liabilities
Accounts payable and accrued liabilities	$	5
Asset retirement obligation	2
Total Liabilities Assumed	$	7
Net Assets Acquired	$	293

(1) Goodwill is reported in the Gathering and Processing segment.

The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.

Assets. Accounts receivable, net, other current assets, and construction in process were valued using a cost basis as this basis approximates fair value due to the current nature of these items. Real property, including gathering and transmission systems, compression equipment, and other property, plant and equipment, were valued based on a combination of the income, market and cost approaches, depending on the type of asset. Intangible assets, other than goodwill, are customer contract related intangibles, which have an average useful life of 30 years, and have been valued using the income approach. The goodwill is the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized.

Liabilities. The Partnership assumed accounts payable, accrued liabilities, and an asset retirement obligation as part of the Hoover Acquisition. The Partnership determined that the historical cost basis of the accounts payable and the accrued liabilities approximated fair value as they comprise normal operating liabilities. The asset retirement obligation was valued based on estimates prepared by an independent environmental consulting firm.

Pro Forma Results of Operations

The following unaudited pro forma consolidated results of operations for the three and nine months ended September 30, 2014 and 2013 are presented as if the PVR, Hoover and Eagle Rock Midstream acquisitions had been completed on January 1, 2013. The pro forma information includes adjustments to reflect incremental expenses associated with the fair value adjustments recorded as a result of applying the acquisition method of accounting and incremental interest expense related to the financing of a portion of the purchase price. This pro forma information is not necessarily indicative of the results that would have occurred had the

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acquisitions occurred on January 1, 2013, nor is it indicative of future results of operations. Actual results for the three months ended September 30, 2014 include PVR, Hoover and the Eagle Rock midstream business for the entire period.

	Three Months Ended September 30,					Nine Months Ended September 30,
	2014		2013			2014			2013
Revenues	$	1,483	$	1,230		$	4,354		$	3,453
Net income (loss) attributable to the Partnership	103		(6		)	(23		)	(119		)
Basic net income (loss) per Limited Partner unit	$	0.23	$	(0.01	)	$	(0.23	)	$	(0.01	)
Diluted net income (loss) per Limited Partner unit	$	0.23	$	(0.01	)	$	(0.23	)	$	(0.01	)

5. INVESTMENTS IN UNCONSOLIDATED AFFILIATES

As of September 30, 2014, the Partnership has a 49.99% general partner interest in HPC, a 50% membership interest in MEP, a 30% membership interest in Lone Star, a 33.33% membership interest in Ranch JV, a 51% membership interest in Aqua - PVR, a 50% membership interest in Coal Handling, and a 50% partnership interest in Sweeny JV. The Partnership’s interests in the Aqua - PVR and Coal Handling joint ventures were acquired in the PVR Acquisition and its interest in Sweeny JV was acquired in the Eagle Rock Midstream Acquisition. In March 2014, the Partnership entered into an agreement, whereby the Partnership’s 50% interest in Grey Ranch was assigned to SandRidge Midstream, Inc., resulting in a cash settlement of $4 million and a loss of $1 million recorded to income from unconsolidated affiliates.

The carrying value of the Partnership’s investment in each of the unconsolidated affiliates as of September 30, 2014 and December 31, 2013 is as follows:

	September 30, 2014		December 31, 2013
HPC	$	428	$	442
MEP	703		548
Lone Star	1,145		1,070
Ranch JV	35		36
Aqua - PVR	47		—
Coal Handling	12		—
Sweeny JV	1		—
Grey Ranch	—		1
Total	$	2,371	$	2,097

The following tables summarize the Partnership’s investment activities in each of the unconsolidated affiliates for the three and nine months ended September 30, 2014 and 2013:

	Three Months Ended September 30, 2014
	HPC			MEP			Lone Star			Ranch JV			Aqua - PVR			Coal Handling
Contributions to unconsolidated affiliates	$	—		$	—		$	15		$	—		$	—		$	—
Distributions from unconsolidated affiliates	(14		)	(17		)	(37		)	(7		)	(1		)	(2		)
Share of earnings of unconsolidated affiliates’ net income (loss)	9			11			31			3			(1		)	1
Amortization of excess fair value of investment	(1		)	—			—			—			—			—

	Three Months Ended September 30, 2013
	HPC (1)			MEP			Lone Star			Ranch JV
Contributions to unconsolidated affiliates	$	—		$	—		$	51		$	1
Distributions from unconsolidated affiliates	(196		)	(18		)	(16		)	(1		)
Share of earnings of unconsolidated affiliates’ net income	9			11			18			—
Amortization of excess fair value of investment	(1		)	—			—			—

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	Nine Months Ended September 30, 2014
	HPC			MEP (2)			Lone Star			Ranch JV			Aqua - PVR			Coal Handling
Contributions to unconsolidated affiliates	$	—		$	175		$	86		$	—		$	—		$	—
Distributions from unconsolidated affiliates	(35		)	(54		)	(94		)	(8		)	(1		)	(2		)
Share of earnings of unconsolidated affiliates’ net income (loss)	25			33			83			7			(2		)	1
Amortization of excess fair value of investment	(4		)	—			—			—			—			—

	Nine Months Ended September 30, 2013
	HPC (1)			MEP			Lone Star			Ranch JV
Contributions to unconsolidated affiliates	$	—		$	—		$	100		$	2
Distributions from unconsolidated affiliates	(226		)	(56		)	(56		)	(1		)
Share of earnings of unconsolidated affiliates’ net income	28			31			48			—
Amortization of excess fair value of investment	(4		)	—			—			—

(1) The Partnership received a non-recurring return of capital of $185 million from HPC in September 2013.

(2) The Partnership paid $175 million to MEP in September 2014.

The following tables present selected income statement data for each of the unconsolidated affiliates, on a 100% basis, for the three and nine months ended September 30, 2014 and 2013:

	Three Months Ended September 30, 2014
	HPC		MEP		Lone Star		Ranch JV		Aqua - PVR			Coal Handling
Total revenues	$	39	$	64	$	1,166	$	10	$	2		$	3
Operating income (loss)	21		33		105		8		(1		)	1
Net income (loss)	19		21		104		8		(1		)	1

	Three Months Ended September 30, 2013
	HPC		MEP		Lone Star		Ranch JV
Total revenues	$	38	$	66	$	537	$	4
Operating income	19		34		61		1
Net income	18		21		61		1

	Nine Months Ended September 30, 2014
	HPC		MEP		Lone Star		Ranch JV		Aqua - PVR			Coal Handling
Total revenues	$	113	$	196	$	2,859	$	30	$	2		$	6
Operating income (loss)	59		102		279		22		(4		)	3
Net income (loss)	50		65		276		21		(4		)	3

	Nine Months Ended September 30, 2013
	HPC		MEP		Lone Star		Ranch JV
Total revenues	$	116	$	194	$	1,320	$	10
Operating income	58		101		162		2
Net income	56		63		160		2

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6. 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 Committee of the General Partner is responsible for overseeing the management of these risks, including monitoring exposure limits. The Audit and Risk 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 supply and demand as well as 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.

~~Commodity~~The ~~Derivative~~Partnership ~~Instruments~~has -swap ~~Marketing~~contracts &settled ~~Trading.~~against ~~The~~certain ~~Partnership~~NGLs, ~~conducts~~condensate and natural gas ~~marketing~~market ~~and~~prices. ~~trading~~In ~~activities~~April ~~intended~~2015, tothe ~~capitalize~~Partnership onterminated ~~favorable~~all ~~price~~outstanding ~~differentials~~swap ~~between~~contracts ~~various~~and ~~receipt~~received ~~and~~net ~~delivery~~proceeds ~~locations~~of $56 million.

AsMarketing ~~part~~& ofTrading. ~~its~~The Partnership conducts natural gas marketing and trading activities, ~~the~~intended to capitalize on favorable price differentials between various receipt and delivery locations. The Partnership enters into both financial derivatives and physical contracts. These financial derivatives, primarily basis swaps, are transacted: (i) to economically hedge subscribed capacity exposed to market rate fluctuations and (ii) to mitigate the price risk related to other ~~purchase~~purchases and sales of natural gas. By entering into a basis swap, one pricing index is exchanged for another, effectively locking in the margin between the natural gas purchase and sale by removing index spread risk on the combined physical and financial transaction. Changes in the fair value of these financial and physical contracts are recorded as adjustments to natural gas sales and realized (unrealized) gain (loss) from derivatives, as appropriate.

The Partnership has credit exposure to additional counterparties. The Partnership monitors its exposure to any single counterparty and the creditworthiness of its counterparties on an ongoing basis. In addition, the Partnership's natural gas purchase and sale contracts, for certain counterparties, are subject to counterparty netting agreements governing settlement under such natural gas purchase and sales contracts, and when possible, the Partnership nets the open positions of each counterparty.

~~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, 2014, the Partnership had $689 million of outstanding borrowings exposed to variable interest rate risk.8

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contracts, for certain counterparties, are subject to counterparty netting agreements governing settlement under such natural gas purchase and sales contracts, and when possible, the Partnership nets the open positions of each counterparty.

Interest Rate Risk. The Partnership is exposed to variable interest rate risk as a result of borrowings under its revolving credit facility. As of March 31, 2015, the Partnership had $2.1 billion of outstanding borrowings exposed to variable interest rate risk.

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 contract 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 failed to perform under existing swap contracts, the Partnership’s maximum loss as of ~~September~~March 3031, ~~2014~~2015 would be $1072 million, which would be reduced by $21 million, due to the netting features. 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.

The 14Partnership’s derivative assets and liabilities, including credit risk adjustments, as of March 31, 2015 and December 31, 2014 are detailed below:



	Assets				Liabilities
	March 31, 2015		December 31, 2014		March 31, 2015		December 31, 2014
Derivatives not designated as cash flow hedges
Current amounts
Commodity contracts	$	65	$	75	$	1	$	—
Long-term amounts
Commodity contracts	9		10		—		—
Embedded derivatives in Series A Preferred Units	—		—		14		16
Total derivatives	$	74	$	85	$	15	$	16

The Partnership’s statements of operations for the three months ended March 31, 2015 and 2014 were impacted by derivative instruments activities as follows:



		Three Months Ended March 31,
		2015		2014
Derivatives not designated in a hedging relationship	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Recognized in Income on Derivatives
Commodity derivatives	Revenues	$	11	$	(13	)
Embedded derivatives in Series A Preferred Units	Other income & deductions, net	2		(1		)
		$	13	$	(14	)

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~~The~~6. ~~Partnership’s~~LONG-TERM ~~derivative assets and liabilities, including credit risk adjustments, as of September 30, 2014 and December 31, 2013 are detailed below:~~DEBT

	Assets				Liabilities
	September 30, 2014		December 31, 2013		September 30, 2014		December 31, 2013
Derivatives not designated as cash flow hedges
Current amounts
Commodity contracts	$	11	$	3	$	3	$	9
Long-term amounts
Commodity contracts	1		1		1		—
Embedded derivatives in Series A Preferred Units	—		—		30		19
Total derivatives	$	12	$	4	$	34	$	28

The Partnership’s statements of operations for the three and nine months ended September 30, 2014 and 2013 were impacted by derivative instruments activities as follows:

		Three Months Ended September 30,
		2014			2013
Derivatives not designated in a hedging relationship	Location of Gain/(Loss)Recognized in Income	Amount of Gain/(Loss) Recognizedin Income on Derivatives
Commodity derivatives	Revenues	$	18		$	(10	)
Embedded derivatives in Series A Preferred Units	Other income & deductions, net	(1		)	24
		$	17		$	14

		Nine Months Ended September 30,
		2014			2013
Derivatives not designated in a hedging relationship	Location of Gain/(Loss)Recognized in Income	Amount of Gain/(Loss) Recognizedin Income on Derivatives
Embedded derivatives in Series A Preferred Units	Other income & deductions, net	(11		)	2
		$	(11	)	$	2

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7. LONG-TERM DEBT

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

	September 30, 2014			December 31, 2013
	March 31, 2015			December 31, 2014
Senior notes	$	5,~~688~~089		$	25,~~800~~089
Revolving loans	~~689~~2,087			~~510~~1,504
Unamortized premium and discounts	5045			—48
Long-term debt	$	67,~~427~~221		$	36,~~310~~641
Availability under revolving credit facility:
Total credit facility limit	$	12,500		$	12,~~200~~000
Revolving loans	(~~689~~2,087		)	(~~510~~1,504		)
Letters of credit	(2516		)	(1423		)
Total available	$	~~786~~397		$	~~676~~473

Long-term debt maturities as of ~~September~~March 3031, ~~2014~~2015 for each of the next five years are as follows:

Years Ending December 31,	Amount
2014 (remainder)	$	—
2015 (remainder)	$	—
2015	—
2016	—
2017	—
2018	~~600~~—
Thereafter	5,777
2019	2,586
Total *	$	6,377
Thereafter	4,590
Total *	$	7,176

* Excludes a $7064 million unamortized premium on the 2020 PVR Notes and the 2021 PVR Notes assumed by the Partnership and a $2019 million unamortized discount on the combined 2022 Notes.

Revolving Credit Facility

InThe ~~February~~weighted ~~2014,~~average ~~RGS~~interest ~~entered~~rate ~~into~~on the ~~First~~amounts ~~Amendment~~outstanding tounder the ~~Sixth~~Partnership’s ~~Amended and Restated~~ Credit Agreement ~~(as~~was ~~amended, the “Credit Agreement”) to, among other things, expressly permit the pending PVR and Eagle Rock Midstream acquisitions, and to increase the commitment to $1~~2.518% ~~billion~~as ~~and increase the uncommitted incremental facility to $500 million. The amendment allowed the Partnership to assume the series~~ of ~~PVR~~March 31, ~~senior notes that mature prior to the Credit Agreement~~2015.

InOn ~~September~~April ~~2014~~30, ~~RGS entered into the Second Amendment to the Credit Agreement to~~2015, ~~among~~in ~~other~~connection ~~things,~~with ~~increase~~ the ~~letter of credit sublimit from $50 million to $100 million~~Merger, ~~with none of~~ the ~~four~~revolving ~~individual issuing banks being required to issue letters of~~ credit infacility ~~excess~~was ofpaid ~~$25~~off ~~million; increase~~ in ~~the~~full ~~general~~and ~~basket~~terminated. ofAs ~~permitted~~a ~~investments~~result, ~~from~~compliance ~~$300~~with ~~million~~material tocovenants ~~$500~~is ~~million;~~no ~~add~~longer ~~provisions~~applicable ~~permitting~~as ~~investments~~of ~~in ORS affording it similar treatment to~~ the ~~Partnership’s~~reporting ~~existing joint ventures; and update various swap agreement provisions to conform to current market standards~~date.

The weighted average interest rate on the amounts outstanding under the Partnership’s Credit Agreement was 2.66% as of September 30, 2014.

Senior Notes

InThe ~~February~~Senior ~~2014,~~Notes issued by the Partnership and Finance Corp. ~~issued~~are ~~$900~~fully ~~million~~and ofunconditionally ~~senior notes that mature on March 1~~guaranteed, ~~2022 (the “2022 Notes”). The 2022 Notes bear interest at 5.875% with interest payable semi-annually in arrears~~ on ~~September~~a 1joint and ~~March~~several ~~1. At any time prior to December 1~~basis, ~~2021,~~by ~~the~~substantially ~~Partnership may redeem some or~~ all of the ~~notes~~Partnership’s ~~at 100% of the principal amount thereof~~existing, plus a “make-whole” redemption price and accrued and unpaid interest, if any, to the redemption date. On or after December 1, 2021, the Partnership may redeem some or all of the notes at a redemption price equal to 100% ~~of the principal amount thereof~~owned, plus accrued and unpaid interest, if any, to the redemption date. If the Partnership undergoes certain change of control transactions, the Partnership may be required to offer to purchase the notes from holders. The 2022 Notes are guaranteed by the Partnership’s existing consolidated subsidiaries, except ~~Finance~~for ~~Corp,~~ ELG and ORS. The 2022 Notes rank equally in right of payment with all of the Partnership’s existing and future senior unsecured debt, including the Partnership’s other outstanding Senior Notes, and contain the same covenants as the Partnership’s other existing Senior Notes.

7. 16COMMITMENTS AND CONTINGENCIES

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In March 2014, in connection with the PVR Acquisition, the Partnership assumed $1.2 billion in aggregate principal amount of PVR’s outstanding senior notes, consisting of $300 million of 8.25% senior notes that mature on April 15, 2018 (the “2018 PVR Notes”), $400 million of 6.5% senior notes that mature on May 15, 2021 (the “2021 PVR Notes”), and $473 million of 8.375% senior notes that mature on June 1, 2020 (the “2020 PVR Notes”). In April 2014, the Partnership redeemed all of the 2018 PVR Notes for $313 million at a price of 104.125% plus accrued and unpaid interest paid to the redemption date. Interest on the 2021 PVR Notes and the 2020 PVR Notes accrue semi-annually on May 15 and November 15 and June 1 and December 1, respectively.

On March 24, 2014, in accordance with our obligations under the indentures governing the 2020 PVR Notes and the 2021 PVR Notes, we commenced change of control offers pursuant to which holders of such notes were entitled to require us to repurchase all or a portion of their notes at a purchase price of 101% of the principal amount thereof, plus accrued and unpaid interest to the repurchase date. The change of control offers for the 2020 PVR Notes and the 2021 PVR Notes expired on April 22, 2014 and, on April 23, 2014, we accepted for purchase less than $1 million in aggregate principal amount of 2021 PVR Notes.

In July 2014, the Partnership exchanged $499 million of 8.375% Senior Notes due 2019 (the “Eagle Rock Notes”) of Eagle Rock and Eagle Rock Energy Finance Corp. for 8.375% Senior Notes due 2019 issued by the Partnership and Finance Corp. (the “New Partnership Notes”). The New Partnership Notes have substantially the same economic terms as the outstanding Eagle Rock Notes, including interest rate, interest payment dates, optional redemption terms and maturity. The New Partnership Notes rank equally with the Partnership’s existing Senior Notes.

In July 2014, the Partnership and Finance Corp. issued $700 million of senior notes that mature on October 1, 2022 (the “October 2022 Notes”). The October 2022 Notes bear interest at 5% with interest payable semi-annual in arrears on October 1 and April 1, beginning April 1, 2015. At any time prior to July 1, 2022, the Partnership may redeem some or all of the notes at 100% of the principal amount thereof, plus a “make-whole” redemption price and accrued and unpaid interest, if any, to the redemption date. On or after, July 1, 2022, the Partnership may redeem some or all of the notes at a redemption price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date. If the Partnership undergoes certain change of control transactions, it may be required to offer to purchase the notes from holders. The October 2022 Notes will be guaranteed by substantially all of the Partnership’s consolidated subsidiaries, except Finance Corp., ELG and ORS. The October 2022 Notes rank equally in right of payment with all of its existing and future senior unsecured debt, including its other outstanding Senior Notes, and contain substantially the same covenants as its other existing Senior Notes.

In July 2014, the Partnership redeemed $83 million of the $473 million outstanding 2020 PVR Notes for $91 million, including $8 million of accrued interest and redemption premium.

On October 28, 2014, the Partnership issued a notice of redemption to the holders of the $600 million 2018 Notes, with a redemption date of December 2, 2014, for a total price of 103.438%.

At September 30, 2014, the Partnership was in compliance with all material covenants under the Credit Agreement and the indentures governing the Senior Notes.

The Senior Notes issued by the Partnership and Finance Corp. will be fully and unconditionally guaranteed, on a joint and several basis, by substantially all of the Partnership’s existing, 100% owned, consolidated subsidiaries, except for ELG, Aqua - PVR and ORS.

8. 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.

~~PVR~~ETP Merger Shareholder Litigation. Following ~~Five putative class action lawsuits challenging~~ the ~~PVR~~January ~~Acquisition are currently pending. All of the cases name PVR~~26, ~~PVR~~2015 GPannouncement ~~and the current directors~~ of ~~PVR GP, as well as~~ the ~~Partnership~~definitive ~~and~~merger ~~the~~agreement ~~General~~with ~~Partner (collectively~~ETP, ~~the “Regency Defendants”), as defendants. Each of the lawsuits has been brought by a~~ purported ~~unitholder~~Partnership ~~of PVR, both individually and on behalf of a putative class consisting of public~~ unitholders offiled ~~PVR. The~~ lawsuits generally allege, among other things, that the directors of PVR GP breached their fiduciary duties to unitholders of PVR, that PVR GP, PVR and the Regency Defendants aided and abetted the directors of PVR GP in ~~the~~state ~~alleged breach of these fiduciary duties,~~ and, ~~as to the actions in~~ federal ~~court,~~courts that some or all of PVR, PVR GP, and the directors of PVR GP violated Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder and Section 20(a) of the Exchange Act. The lawsuits purport to seek, in ~~general~~Dallas, ~~(i)~~Texas ~~injunctive~~asserting ~~relief,~~claims ~~(ii)~~relating disclosure of certain additional information concerning the transaction, (iii) in the event the merger is consummated, rescission or an award of rescissory damages, (iv) an award of plaintiffs’ costs and (v) the accounting for damages allegedly causes by the defendants to ~~these actions, and, (vi) such further relief as~~ the ~~court~~proposed ~~deems just and proper~~transaction. ~~The styles of the pending cases are as~~

On 17February 3, 2015, William Engel and Enno Seago, purported Partnership unitholders, filed a class action petition on behalf of the Partnership’s common unitholders and a derivative suit on behalf of the Partnership in the 162nd Judicial District Court of Dallas County, Texas (the “Engel Lawsuit”). The lawsuit names as defendants the General Partner, the members of the General Partner’s board of directors, ETP, ETP GP, ETE, and, as a nominal party, the Partnership. The Engel Lawsuit alleges that (1) the General Partner’s directors breached duties to the Partnership and the Partnership’s unitholders by employing a conflicted and

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~~follows:~~unfair ~~David~~process ~~Naiditch~~and v.failing ~~PVR~~to ~~Partners,~~maximize ~~L.P.,~~the etmerger ~~al.~~consideration; (~~Case No. 9015-VCL~~2) in the ~~Court~~General ofPartner’s ~~Chancery~~directors ofbreached the ~~State~~implied covenant of ~~Delaware); Charles~~good ~~Monatt~~faith v.and ~~PVR~~fair ~~Partners,~~dealing ~~LP,~~by etengaging ~~al.~~in ~~(Case~~a ~~No.~~flawed ~~2013-10606)~~merger process; and ~~Saul Srour v. PVR Partners, L.P., et al.~~ (~~Case~~3) ~~No.~~the ~~2013~~non-~~011015),~~director ~~each~~defendants ~~pending~~aided ~~in the~~and ~~Court~~abetted ofin ~~Common~~these ~~Pleas~~claimed ~~for~~breaches. ~~Delaware~~The ~~County,~~plaintiffs ~~Pennsylvania;~~seek ~~Stephen~~an ~~Bushansky~~injunction v.preventing ~~PVR~~the ~~Partners,~~defendants ~~L.P.,~~from etclosing ~~al.~~the ~~(C.A.~~proposed ~~No.~~transaction ~~2:13-cv-06829-HB);~~or ~~and~~an ~~Mark~~order ~~Hinnau~~rescinding v.the ~~PVR~~transaction ~~Partners,~~if ~~L.P.,~~it ethas ~~al.~~already ~~(C.A.~~been Nocompleted. ~~2:13-cv-07496-HB),~~The ~~pending~~plaintiffs inalso ~~the~~seek ~~United~~money ~~States~~damages ~~District~~and ~~Court~~court ~~for~~costs, ~~the~~including ~~Eastern~~attorney’s ~~District of Pennsylvania~~fees.

On ~~January~~February 289, ~~2014~~2015, ~~the~~Stuart ~~defendants entered into a Memorandum of Understanding (“MOU”) with Monatt~~Yeager, ~~Srour, Bushansky, Naiditch and Hinnau pursuant to which defendants and the referenced plaintiffs agreed in principle to~~ a ~~settlement~~purported ofPartnership ~~their lawsuits (“Settled Lawsuits”)~~unitholder, ~~which~~filed ~~will be memorialized in~~ a ~~separate~~class ~~settlement~~action ~~agreement,~~petition ~~subject~~on tobehalf ~~customary conditions, including consummation~~ of the ~~PVR~~Partnership’s ~~Acquisition,~~common ~~which~~unitholders ~~occurred~~and ona ~~March~~derivative ~~21,~~suit ~~2014,~~on ~~completion~~behalf of ~~certain~~the ~~confirmatory~~Partnership ~~discovery,~~in ~~class~~the ~~certification~~134th ~~and~~Judicial ~~final~~District ~~approval by the~~ Court of ~~Common~~Dallas ~~Pleas for Delaware~~ County, ~~Pennsylvania.~~Texas If (the ~~Court~~“Yeager ~~approves~~Lawsuit”). ~~the~~The ~~settlement~~allegations, ~~the~~claims, ~~Settled Lawsuits will be dismissed with prejudice~~ and ~~all~~relief ~~defendants~~sought ~~will~~in bethe ~~released~~Yeager ~~from~~Lawsuit ~~any~~are ~~and~~nearly ~~all~~identical ~~claims~~to ~~relating~~those toin the ~~Settled~~Engel ~~Lawsuits~~Lawsuit.

~~The~~On ~~settlement~~February ~~will~~10, ~~not~~2015, ~~affect~~Lucien ~~any~~Coggia ~~provisions~~a ofpurported ~~the~~Partnership ~~merger~~unitholder, ~~agreement~~filed ora ~~the~~class ~~form~~action orpetition ~~amount~~on behalf of ~~consideration~~the ~~received~~Partnership’s bycommon ~~PVR~~ unitholders inand ~~the~~a ~~PVR~~derivative ~~Acquisition. The~~suit ~~defendants~~on ~~have~~behalf ~~denied~~of ~~and~~the ~~continue~~Partnership toin ~~deny~~the ~~any~~192nd ~~wrongdoing~~Judicial orDistrict ~~liability~~Court ~~with~~of ~~respect~~Dallas toCounty, Texas (the ~~plaintiffs’~~“Coggia ~~claims~~Lawsuit”). inThe ~~the~~allegations, ~~aforementioned~~claims, ~~litigation~~ and ~~have~~relief ~~entered~~sought ~~into~~in the ~~settlement~~Coggia toLawsuit ~~eliminate~~are ~~the~~nearly ~~uncertainty,~~identical ~~burden,~~to ~~risk,~~those ~~expense,~~in ~~and~~the ~~distraction~~Engel ~~of further litigation~~Lawsuit.

~~Utility Line Services, Inc. vs. PVR Marcellus Gas Gathering LLC.~~ On ~~May~~February 223, ~~2012~~2015, ~~Plaintiff~~Linda ~~and Counterclaim Defendant~~Blankman, ~~Utility~~a ~~Line~~purported ~~Services~~Partnership unitholder, ~~Inc. (“ULS”)~~ filed ~~suit~~a ~~against~~class ~~PVR~~action ~~Marcellus~~complaint ~~Gas~~on ~~Gathering,~~behalf ~~LLC~~of ~~now~~the ~~known~~Partnership’s ascommon ~~Regency~~unitholders ~~Marcellus~~in ~~Gas~~the ~~Gathering~~United ~~LLC~~States ~~(“Regency~~District ~~Marcellus”)~~Court ~~relating~~for tothe aNorthern ~~dispute~~District ~~involving~~of ~~payment~~Texas ~~under a construction contract~~ (the “~~Construction~~Blankman ~~Contract~~Lawsuit”). The ~~entered~~allegations ~~into~~and claims in ~~October~~the ~~2010~~Blankman ~~for~~Lawsuit ~~Regency~~are ~~Marcellus’~~similar ~~multi-phase~~to ~~pipeline~~those ~~construction project~~ in ~~Lycoming County, PA (~~the ~~“Project”)~~Engel Lawsuit. However, ~~Under~~ the ~~terms~~Blankman ofLawsuit ~~the~~does ~~Construction~~not ~~Contract,~~allege ~~Regency~~any ~~Marcellus~~derivative ~~believed~~claims ~~ULS was obligated to design, permit~~ and ~~build~~includes ~~Phases~~the IPartnership ~~and~~as IIa ofdefendant ~~Regency~~rather ~~Marcellus’~~than ~~30-inch~~a ~~pipeline~~nominal ~~and~~party. toThe ~~design~~lawsuit ~~additional~~also ~~phases~~omits one of the ~~project.~~General ~~Due to ULS~~Partner’s ~~deficiencies and delays throughout the project~~directors, asRichard ~~well as extensive overbilling for its services~~Brannon, ~~Regency~~who ~~Marcellus~~was ~~allowed~~named ~~the Construction Contract to terminate~~ in ~~accordance~~the ~~with~~Engel ~~its~~Lawsuit. The ~~terms~~Blankman inLawsuit ~~December~~alleges ~~2011~~that ~~and refused to pay ULS’ outstanding invoices for~~ the ~~Project.~~General ~~ULS then filed suit alleging: Regency Marcellus~~Partner’s ~~refusal~~directors tobreached ~~pay~~their ~~certain~~fiduciary ~~invoices~~duties ~~totaling approximately $17 million; penalties pursuant~~ to the ~~Pennsylvania~~unitholders ~~Contractor~~by ~~and~~failing ~~Subcontractor~~to ~~Payment~~maximize ~~Act,~~the 73value ~~P.S.~~of §the ~~501~~Partnership, etfailing ~~seq. (“CASPA”), Regency Marcellus’ alleged wrongful withholding of payments owed~~ to ~~ULS;~~properly ~~and~~value ~~breach~~the ~~of contract in connection with Regency Marcellus’ alleged wrongful termination of ULS in December 2011. ULS alleged damages~~Partnership, ~~inclusive~~and ofignoring ~~CASPA~~conflicts ~~penalties, are in excess~~ of ~~$30 million~~interest. The ~~Regency~~plaintiff ~~Marcellus~~also ~~alleged~~asserts ~~counterclaims~~a claim against ~~ULS for breach of~~ the ~~parties’~~non-director ~~contract~~defendants for ~~engineering~~aiding and ~~construction~~abetting ~~services;~~the ~~restitution for Regency Marcellus~~directors’ ~~overpayments~~alleged tobreach ~~ULS because~~ of ~~ULS’~~fiduciary ~~improper~~duty. The ~~billing~~Blankman ~~practices;~~Lawsuit ~~attorneys’~~seeks ~~fees~~the ~~resulting~~same ~~from~~relief ~~ULS’~~that ~~meritless~~the ~~claim~~plaintiffs ~~under~~seek ~~CASPA;~~in ~~and professional malpractice against ULS for negligent performance of various engineering services on~~ the ~~Project.~~Engel ~~Regency Marcellus’ alleged damages exceed $21 million~~Lawsuit.

~~Trial~~On ~~commenced~~February on6, ~~March 24~~2015, ~~2014~~Edwin ~~and~~Bazini, ona ~~April~~purported ~~17,~~Partnership ~~2014~~unitholder, ~~the~~filed ~~jury~~a ~~found~~class inaction ~~favor~~complaint on behalf of ~~ULS~~the ~~and~~Partnership’s ~~assessed~~common ~~damages~~unitholders ~~against~~in ~~Regency~~the ~~Marcellus~~United ofStates ~~approximately~~District ~~$24~~Court ~~million~~for ~~plus~~the ~~interest~~Northern ~~and~~District ~~penalties~~of Texas (the “Bazini Lawsuit”). InThe ~~June~~allegations, ~~2014~~claims, ~~ULS~~ and ~~Regency~~relief ~~Marcellus~~sought ~~reached~~in athe ~~settlement~~Bazini Lawsuit are nearly identical to those in ~~this~~the ~~matter~~Blankman Lawsuit. On March 27, ~~the~~2015, ~~terms~~Plaintiff ofBazini ~~which~~filed ~~are~~an ~~confidential.~~amended ~~The~~complaint ~~settlement~~asserting ~~did~~additional ~~not~~claims ~~have~~under Sections 14(a) ~~material~~and ~~adverse~~20(a) ~~effect~~of on the ~~Partnership’s~~Securities ~~business~~Exchange orAct ~~financial~~of ~~position~~1934.

~~Eagle~~On ~~Rock~~February ~~Shareholder~~11, ~~Litigation.~~2015, ~~Three~~Mark ~~putative~~Hinnau, ~~class~~a ~~action~~purported ~~lawsuits~~Partnership ~~challenging the Eagle Rock Midstream Acquisition are currently pending in federal district court in Houston~~unitholder, ~~Texas.~~filed ~~All~~a ~~cases~~class ~~name~~action ~~Eagle~~complaint ~~Rock~~on ~~and~~behalf ~~its~~of ~~current directors, as well as~~ the Partnership’s ~~and~~common aunitholders ~~subsidiary,~~in ~~as defendants. One of~~ the ~~lawsuits~~United ~~also~~States ~~names~~District ~~additional~~Court ~~Eagle~~for ~~Rock entities as defendants. Each of~~ the ~~lawsuits~~Northern ~~has~~District ~~been brought by a purported unitholder~~ of ~~Eagle~~Texas ~~Rock~~ (~~collectively,~~ the “~~Plaintiffs~~Hinnau Lawsuit”)~~, both individually and on behalf of a putative class consisting of public unitholders of Eagle Rock~~. The ~~Plaintiffs in each case seek to rescind the transaction~~allegations, ~~claiming~~claims, ~~among other things, that it yields inadequate consideration, was tainted by conflict~~ and ~~constitutes~~relief ~~breaches~~sought ofin ~~common law fiduciary duties or contractually imposed duties to~~ the ~~shareholders.~~Hinnau ~~Plaintiffs~~Lawsuit ~~also seek monetary damages and attorneys’ fees. The Partnership and its subsidiary~~ are ~~named~~nearly asidentical ~~“aiders~~to ~~and~~those ~~abettors”~~in of the ~~allegedly~~Blankman ~~wrongful actions of Eagle Rock and its board~~Lawsuit.

~~Environmental.~~On ~~The~~February ~~Partnership~~11, is2015, ~~responsible~~Stephen ~~for~~Weaver, ~~environmental~~a ~~remediation~~purported atPartnership ~~certain~~unitholder, ~~sites~~filed ona ~~its~~class ~~gathering~~action ~~and~~complaint ~~processing~~on ~~systems,~~behalf ~~resulting primarily from releases~~ of ~~hydrocarbons.~~the ~~The~~ Partnership’s ~~remediation~~common ~~program~~unitholders ~~typically~~in ~~involves~~ the ~~management~~United ofStates ~~contaminated~~District ~~soils~~Court ~~and~~for ~~may~~the ~~involve~~Northern ~~remediation~~District of ~~groundwater.~~Texas ~~Activities~~(the ~~vary~~“Weaver ~~with~~Lawsuit”). The ~~site conditions and locations~~allegations, ~~the extent and nature of the contamination~~claims, ~~remedial requirements~~ and ~~complexity. The~~relief ~~ultimate~~sought ~~liability~~in ~~and~~the ~~total~~Weaver ~~costs~~Lawsuit ~~associated~~are ~~with~~nearly ~~these~~identical ~~sites~~to ~~will~~those ~~depend~~in ~~upon~~the ~~many~~Blankman ~~factors~~Lawsuit.

On 18February 11, 2015, Adrian Dieckman, a purported Partnership unitholder, filed a class action complaint on behalf of the Partnership’s common unitholders in the United States District Court for the Northern District of Texas (the “Dieckman Lawsuit”). The allegations, claims, and relief sought in the Dieckman Lawsuit are similar to those in the Blankman Lawsuit, except that the Dieckman Lawsuit does not assert an aiding and abetting claim.

On February 13, 2015, Irwin Berlin, a purported Partnership unitholder, filed a class action complaint on behalf of the Partnership’s common unitholders in the United States District Court for the Northern District of Texas (the “Dieckman Lawsuit”). The allegations, claims, and relief sought in the Berlin Lawsuit are similar to those in the Blankman Lawsuit.

On March 13, 2015, the Court in the 95th Judicial District Court of Dallas County, Texas transferred and consolidated the Yeager and Coggia Lawsuits into the Engel Lawsuit and captioned the consolidated lawsuit as Engel v. Regency GP, LP, et al. (the “Consolidated State Lawsuit”).

On March 30, 2015, Leonard Cooperman, a purported Partnership unitholder, filed a class action complaint on behalf of the Partnership’s common unitholders in the United States District Court for the Northern District of Texas (the “Cooperman Lawsuit”). The allegations, claims, and relief sought in the Cooperman Lawsuit are similar to those in the Blankman Lawsuit.

On March 31, 2015, the Court in United States District Court for the Northern District of Texas consolidated the Blankman, Bazini, Hinnau, Weaver, Dieckman, and Berlin Lawsuits into a consolidated lawsuit captioned Bazini v. Bradley, et al. (the “Consolidated

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~~The~~Federal ~~table~~Lawsuit”). ~~below~~On ~~reflects~~April 1, 2015, plaintiffs in the ~~environmental~~Consolidated ~~liabilities~~Federal ~~recorded~~Lawsuit atfiled ~~September 30,~~an ~~2014~~Emergency ~~and~~Motion ~~December 31,~~to ~~2013~~Expedite Discovery. ~~Except~~On asApril ~~described~~9, ~~above~~2015, by order of the ~~Partnership~~Court, ~~does~~the ~~not~~parties ~~have~~submitted ~~any~~a ~~material~~joint ~~environmental~~submission ~~remediation~~wherein ~~matters~~defendants ~~assessed~~opposed asplaintiffs ~~reasonably~~request ~~possible~~to ~~that~~expedite ~~would~~discovery. ~~require~~On ~~disclosure~~April in17, 2015, the ~~financial~~Court ~~statements~~denied plaintiffs’ motion to expedite discovery.

	September 30, 2014		December 31, 2013
Current	$	2	$	2
Noncurrent	8		6
Total environmental liabilities	$	10	$	8

Each of these lawsuits is at a preliminary stage. The Partnership cannot predict the outcome of these or any other lawsuits that might be filed, nor can we predict the amount of time and expense that will be required to resolve these lawsuits. The Partnership and the other defendants named in the lawsuits intend to defend vigorously against these and any other actions.

~~The~~NMED ~~Partnership~~Settlement. ~~recorded~~In ~~less~~April ~~than~~2015, $1our ~~million~~subsidiary, inRegency ~~expenditures~~Field Services LLC (“RFS”) entered into a Settlement Agreement (“Agreement”) with the New Mexico Environment Department (“NMED”), settling and resolving the penalty assessment issued by the NMED concerning alleged violations New Mexico air regulations related to ~~environmental~~the ~~remediation~~Jal ~~for~~#3 ~~the~~and ~~nine~~Jal ~~months~~#4 ~~ended~~facilities. ~~September 30~~Pursuant to the Agreement, ~~2014~~RFS agreed to pay a $1.2 million civil penalty to settle the alleged violations.

~~Endangered~~Environmental. ~~Species~~The ~~Act.~~Partnership Inis ~~March~~responsible ~~2014,~~for ~~the~~environmental ~~U.S.~~remediation ~~Fish~~at &certain ~~Wildlife~~sites ~~Service~~on ~~listed~~its ~~the~~gathering ~~lesser~~and ~~prairie~~processing ~~chicken~~systems, asresulting aprimarily ~~“threatened”~~from ~~species~~releases ~~under~~of hydrocarbons. The Partnership’s remediation program typically involves the ~~federal~~management ~~Endangered~~of ~~Species~~contaminated ~~Act.~~soils ~~This~~and ~~species~~may isinvolve ~~predominantly~~remediation ~~located~~of ingroundwater. ~~the~~Activities ~~Partnership’s~~vary ~~Permian~~with ~~and~~site ~~Midcontinent~~conditions ~~regions;~~and ~~therefore~~locations, the ~~Partnership~~extent ~~may~~and ~~encounter~~nature ~~additional~~of ~~costs~~the ~~and~~contamination, ~~delays~~remedial inrequirements ~~infrastructure~~and ~~development~~complexity. The ~~Partnership~~ultimate ~~is participating,~~liability ~~along~~and ~~with~~total ~~other~~costs ~~companies~~associated inwith ~~our~~these ~~industry,~~sites inwill adepend ~~conservation~~upon ~~plan~~many ~~for~~factors. ~~this~~In ~~species~~addition, ~~which~~the ~~will~~Partnership ~~allow~~has ~~the~~reclamation ~~Partnership~~and tobonding ~~participate~~requirements inwith ~~managing~~respect ~~the~~to ~~related~~certain ~~conservation~~un-leased ~~efforts~~and inactive coal properties.

~~Air Quality Control.~~ The ~~Partnership~~table isbelow ~~currently~~reflects ~~negotiating~~the ~~settlements~~undiscounted toenvironmental ~~certain~~liabilities ~~enforcement~~recorded ~~actions~~at byMarch 31, ~~the~~2015 ~~NMED~~ and ~~the~~December 31, ~~TCEQ~~2014. ~~The~~Except ~~TCEQ~~as ~~recently~~described ~~initiated~~above, ~~a state-wide emissions inventory for~~ the ~~sulfur~~Partnership ~~dioxide~~does ~~emissions~~not ~~from~~have ~~sites~~any ~~with~~material ~~reported~~environmental ~~emissions~~remediation ofmatters 10assessed ~~tons~~as ~~per~~reasonably ~~year~~possible ~~or more. If this data demonstrates~~ that ~~any~~would ~~source~~require ordisclosure group of sources may cause or contribute to a violation of the National Ambient Air Quality Standards, they must be sufficiently controlled to ensure timely attainment of the standard. This may potentially affect three recovery units in ~~Texas. It is unclear at this time how~~ the ~~NMED~~financial ~~will address the sulfur dioxide standard~~statements.

Compliance Orders from the NMED. The Partnership has been in discussions with the NMED concerning allegations of violations of New Mexico air regulations related to the Jal #3 and Jal #4 facilities. Hearings on the compliance orders were delayed until October 2014 to allow the parties to pursue substantive settlement discussions. The Partnership has meritorious defenses to the NMED claims and can offer significant mitigating factors to the claimed violations. The Partnership has recorded a liability of less than $1 million related to the claims and will continue to assess its potential exposure to the allegations as the matters progress.



	March 31, 2015		December 31, 2014
Current	$	2	$	2
Noncurrent	7		8
Total environmental liabilities	$	9	$	10

~~PADEP~~The ~~Consent Assessment. On October 21, 2013 the PADEP presented the~~ Partnership’s ~~subsidiary,~~recorded ~~Regency~~less ~~Marcellus~~than ~~Gas Gathering LLC (“Regency Marcellus”), with a proposed Consent Assessment of Civil Penalty totaling approximately~~ $~~0.3~~1 million in ~~connection~~expenditures ~~with alleged erosion and sediment control violations incurred during construction of its pipelines and~~ related ~~facilities~~to inenvironmental ~~Lycoming~~remediation ~~and~~for ~~Tioga Counties, Pennsylvania. In September 2014, Regency Marcellus entered into a Consent Assessment of Civil Penalty (“Assessment”) with~~ the ~~PADEP,~~three ~~settling~~months ~~and~~ended ~~resolving the penalty assessment. Pursuant to the Assessment~~March 31, ~~Regency Marcellus agreed to pay a civil penalty of approximately $0~~2015.~~3 million to settle the aforementioned violations alleged by the PADEP. Such penalty was paid in full in September 2014.~~

CDM Sales Tax Audit. CDM Resource Management LLC (“CDM”), a subsidiary of the Partnership, has historically claimed the manufacturing exemption from sales tax in Texas, as is common in the industry. The exemption is based on the fact that CDM’s natural gas compression equipment is used in the process of treating natural gas for ultimate use and sale. In a recent audit by the Texas Comptroller’s office, the Comptroller has challenged the applicability of the manufacturing exemption to CDM. The period being audited is from August 2006 to August 2007, and liability for that period is potentially covered by an indemnity obligation from CDM’s prior owners. CDM may also have liability for periods since 2008, and prospectively, if the Comptroller’s challenge is ultimately successful. An audit of the 2008 period has commenced. In April 2013, an independent audit review agreed with the Comptroller’s position. While CDM continues to disagree with this position and intends to seek redetermination and other relief, we are unable to predict the final outcome of this matter.

Mine Health and Safety Laws. There are numerous mine health and safety laws and regulations applicable to the coal mining industry. However, since the Partnership does not operate any mines and does not employ any coal miners, it is not subject to such laws and regulations. Accordingly, the Partnership has not accrued any related liabilities.

In8. ~~addition~~RELATED toPARTY the matters discussed above, the Partnership is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business.TRANSACTIONS

As 19of March 31, 2015 and December 31, 2014, details of the Partnership’s related party receivables and related party payables were as follows:



	March 31, 2015		December 31, 2014
Related party receivables
ETE and its subsidiaries	$	73	$	43
HPC	1		1
Ranch JV	—		1
Other	2		—
Total related party receivables	$	76	$	45

Related party payables
ETE and its subsidiaries	$	22	$	50
HPC	3		3
Mi Vida JV	—		11
Total related party payables	$	25	$	64

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9. RELATED PARTY TRANSACTIONS

As of September 30, 2014 and December 31, 2013, details of the Partnership’s related party receivables and related party payables were as follows:

	September 30, 2014		December 31, 2013
Related party receivables
ETE and its subsidiaries	$	48	$	25
HPC	1		1
Ranch JV	—		2
Other	3		—
Total related party receivables	$	52	$	28
Related party payables
ETE and its subsidiaries	$	43	$	68
HPC	1		1
Total related party payables	$	44	$	69

Transactions with ETE and its subsidiaries. Under the service agreement with Services Co., the Partnership paid Services Co.’s direct expenses for services performed, plus an annual fee of $10 million, and received the benefit of any cost savings recognized for these services. The service agreement has a five year term ending 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. On April 30, 2013, this agreement was amended to provide for a waiver of the $10 million annual fee effective as of May 1, 2013 through and including April 30, 2015 and to clarify the scope and expenses chargeable as direct expenses thereunder.

On April 30, 2013, the Partnership entered into the second amendment (the “Operation and Service Amendment”) to the Operation and Service Agreement (the “Operation and Service Agreement”), by and among the Partnership, ETC, the General Partner and RGS. Under the Operation and Service Agreement, ETC performs certain operations, maintenance and related services reasonably required to operate and maintain certain facilities owned by the Partnership, and the Partnership reimburses 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 Operation and Service Agreement Amendment describes the services that ETC will provide in the future.~~

The Partnership incurred total service fees related to the agreements described above from ETE and its subsidiaries of $12 million and $21 million for the three months ended ~~September~~March 3031, ~~2014~~2015 and ~~2013, respectively, and $4 million and $9 million for the nine months ended September 30,~~ 2014 ~~and 2013, respectively~~.

In conjunction with distributions by the Partnership to the limited and general partner interests, ETE and its subsidiaries received cash distributions of $5355 million and $3132 million for the three months ended ~~September~~March 3031, ~~2014~~2015 and ~~2013, respectively, and $119 million and $62 million for the nine months ended September 30,~~ 2014 ~~and 2013~~, respectively.

The Partnership’s Contract Services segment provides contract compression and treating services to subsidiaries of ETE and records revenue in gathering, transportation and other fees. The Partnership’s Contract Services segment purchased compression equipment from a subsidiary of ETE for $2736 million and $399 million during the three months ended ~~September~~March 3031, ~~2014~~2015 and ~~2013, respectively, and $58 million and $76 million for the nine months ended September 30,~~ 2014 ~~and 2013~~, respectively.

Transactions with Lone Star. ~~Subsidiaries~~The ~~of the~~ Partnership ~~have~~ entered into various agreements to sell NGLs to Lone Star. For the three ~~and nine~~ months ended ~~September~~March 3031, 2015 and 2014, the Partnership had recorded $86121 million and $~~193~~50 million, respectively, in NGL sales under these contracts. ofFor ~~which~~ the ~~unsettled~~three ~~portion~~months ~~are~~ended ~~included~~March 31, in2015 and 2014, the ~~related~~Partnership ~~party~~recorded ~~receivable~~$13 ~~from~~million ~~ETE~~and $7 million, respectively, in gathering and ~~its~~transportation ~~subsidiaries~~fees with Lone Star.

~~Transactions with Southern Union~~9. ~~Prior~~SEGMENT to April 30, 2013, Southern Union provided certain administrative services for SUGS that were either based on SUGS’s pro-rata share of combined net investment, margin and certain expenses or direct costs incurred by Southern Union on the behalf of SUGS. Southern Union also charged a management and royalty fee to SUGS for certain management support services provided by Southern Union on the behalf of SUGS and for the use of certain Southern Union trademarks, trade names and service marks by SUGS. These administrative services are no longer being provided subsequent to the SUGS Acquisition.INFORMATION

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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. The related party general and administrative expenses reimbursed to the Partnership were $3 million and $4 million for the three months ended September 30, 2014 and 2013, respectively, and $11 million and $14 million for the nine months ended September 30, 2014 and 2013, respectively, which are recorded in gathering, transportation and other fees.

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

10. SEGMENT INFORMATION

The Partnership has six reportable segments: Gathering and Processing, Natural Gas Transportation, NGL Services, Contract Services, Natural Resources and Corporate. The reportable segments are as described below:

• Gathering and Processing. The Partnership provides “wellhead-to-market” services to producers of natural gas, which include transporting 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, the gathering of oil (crude and/or condensate, a lighter oil) received from producers, the gathering and disposing of salt water, and natural gas and NGL marketing and trading. This segment also includes the Partnership’s 60% membership interest in ELG, which operates natural gas gathering, oil pipeline, and oil stabilization facilities in south Texas, the Partnership’s 33.33% membership interest in Ranch JV, which processes natural gas delivered from NGL-rich shale formations in west Texas, the Partnership’s 50% interest in Sweeny JV, which operates a natural gas gathering facility in south Texas, the Partnership’s 51% membership interest in Aqua - PVR, which transports and supplies fresh water to natural gas producers in the Marcellus shale in Pennsylvania, ~~and~~ the Partnership’s 75% membership interest in ORS, which will operate a natural gas gathering system in the Utica shale in Ohio., ~~The~~and the Partnership’s ~~completed~~50% ~~the~~interest ~~SUGS~~in ~~Acquisition~~Mi onVida ~~April 30~~JV, ~~2013~~ which ~~was~~will operate a ~~reorganization~~cryogenic ofprocessing ~~entities~~plant ~~under~~and ~~common~~related ~~control~~facilities in west Texas.

•

Natural Gas Transportation. The Partnership owns a 49.99% general partner interest in HPC, which owns RIGS, a 450- mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets, and a 50% membership interest in MEP, which owns a 500-mile interstate natural gas pipeline stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipe Line system in Butler, Alabama. This segment also includes Gulf States, which owns a 10-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.

• NGL Services. The Partnership owns a 30% membership interest in Lone Star, an entity owning a diverse set of midstream energy assets including NGL pipelines, storage, fractionation and processing facilities located in Texas, New Mexico, Mississippi and Louisiana.


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

• Natural Resources. The Partnership is involved in the management of coal and natural resources properties and the related collection of royalties. The Partnership also earns revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. This segment also includes the Partnership’s 50% interest in Coal Handling, which owns and operates end-user coal handling facilities.13

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•	Natural Resources. The Partnership is involved in the management of coal and natural resources properties and the related collection of royalties, and the operation of end-user coal handling facilities. The Partnership also earns revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties.


•	Corporate. The Corporate segment comprises the Partnership’s corporate assets.

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 Natural Gas Transportation segments is defined as total revenues, including service fees, less cost of sales. In the Contract Services segment, segment margin is defined as revenues less direct costs. The Natural Resources segment margin is generally equal to total revenues as there is typically minimal cost of sales associated with the management and leasing of properties.

Management believes segment margin is an important measure because it directly relates to volume, commodity price changes and revenue generating horsepower. Operation and maintenance expenses are a separate measure used by management to evaluate performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of operation and maintenance expenses. These expenses fluctuate depending on the activities performed during a specific period. The Partnership does not deduct operation and maintenance expenses from total revenues in calculating segment margin because management separately evaluates commodity volume and price changes in segment margin. The Partnership does not record segment margin for its investments in unconsolidated affiliates (HPC, MEP, Lone Star, Ranch JV, Aqua - PVR, Mi Vida JV and Sweeny JV) because it records its ownership percentages of their net income as income from unconsolidated affiliates in accordance with the equity method of accounting.

2114

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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 its investments in unconsolidated affiliates (HPC, MEP, Lone Star, Ranch JV, Aqua - PVR, and Coal Handling) because it records its ownership percentages of their net income as income from unconsolidated affiliates in accordance with the equity method of accounting.

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Results for each segment are shown below:

	Three Months Ended September 30,						Nine Months Ended September 30,
	Three Months Ended March 31,
	2014			2013			2014			2013
	2015			2014
External Revenues
Gathering and Processing	$	~~1,387~~887		$	~~603~~793		$	~~3,254~~		$	~~1,671~~
Natural Gas Transportation	—			—			—			—
NGL Services	—			—			—			—
Contract Services	7684			5863			~~217~~			~~159~~
Natural Resources	1825			—2			40			—
Corporate	23			45			13			14
Eliminations	—			—			—			—
Total	$	~~1,483~~999		$	~~665~~863		$	~~3,524~~		$	~~1,844~~
Intersegment Revenues
Gathering and Processing	$	—		$	—		$	—		$	—
Natural Gas Transportation	—			—			—			—
NGL Services	—			—			—			—
Contract Services	31			4			11			11
Natural Resources	—			—			—			—
Corporate	—			—			—			—
Eliminations	(31		)	(4		)	~~(11~~		)	~~(11~~		)
Total	$	—		$	—		$	—		$	—
Segment Margin
Gathering and Processing	$	~~349~~261		$	~~136~~166		$	~~784~~		$	~~383~~
Natural Gas Transportation	—			—			—			—
NGL Services	—			—			—			—
Contract Services	6670			5256			~~185~~			~~149~~
Natural Resources	1825			—2			40			—
Corporate	23			45			9			14
Eliminations	(31		)	(4		)	~~(11~~		)	~~(11~~		)
Total	$	~~432~~358		$	~~188~~225		$	~~1,007~~		$	~~535~~
Operation and Maintenance
Gathering and Processing	$	~~104~~107		$	6360		$	~~237~~		$	~~177~~
Natural Gas Transportation	—			—			—			—
NGL Services	—			—			—			—
Contract Services	2122			1920			62			53
Natural Resources	4			—			9			—
Corporate	1			—2			2			1
Eliminations	(1		)	(4		)	~~(10~~		)	~~(11~~		)
Total	$	~~129~~133		$	78		$	~~300~~		$	~~220~~

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The table below provides a reconciliation of total segment margin to income before income taxes:

	Three Months Ended September 30,						Nine Months Ended September 30,
	Three Months Ended March 31,
	2014			2013			2014			2013
	2015			2014
Total segment margin	$	~~432~~358		$	~~188~~225		$	~~1,007~~		$	~~535~~
Operation and maintenance	(~~129~~133		)	(78		)	~~(300~~		)	~~(220~~		)
General and administrative	(36		)	(1333		)	~~(123~~		)	~~(64~~		)
(Loss) gain on asset sales, net	(1		)	1			1			(1		)
Gain on asset sales, net	—			2
Depreciation, depletion and amortization	(~~122~~158		)	(7494		)	~~(384~~		)	~~(207~~		)
Income from unconsolidated affiliates	5350			3743			~~143~~			~~103~~
Interest expense, net	(8682		)	(4156		)	~~(220~~		)	~~(119~~		)
Gain (loss) on debt refinancing, net	2			—			2			(7		)
Other income and deductions, net	3			2
Other income and deductions, net	(2		)	24			(7		)	3
Income before income taxes	$	2		$	11
Income before income taxes	$	111		$	44		$	119		$	23

The tables below provide amounts reflected in the condensed consolidated balance sheets for each segment:

Total Assets	~~September~~March 3031, ~~2014~~2015		December 31, ~~2013~~2014
Gathering and Processing	$	12,~~310~~290	$	412,~~748~~069
Natural Gas Transportation	1,~~132~~105		~~991~~1,119
NGL Services	1,~~145~~217		1,~~070~~162
Contract Services	12,~~977~~089		12,~~897~~035
Natural Resources	~~515~~525		—529
Corporate and Others	~~101~~190		76189
Total	$	17,~~180~~416	$	817,~~782~~103

Investments in Unconsolidated Affiliates	~~September~~March 3031, ~~2014~~2015		December 31, ~~2013~~2014
Gathering and Processing	$	83163	$	36139
Natural Gas Transportation	1,~~131~~104		~~991~~1,117
NGL Services	1,~~145~~217		1,~~070~~162
Natural Resources	12		—
Total	$	2,484	$	2,418
Total	$	2,371	$	2,097

1110. EQUITY-BASED COMPENSATION

The Partnership’s LTIP for its employees, directors and consultants authorizes grants up to 5,865,584 common units. LTIP compensation expense of $34 million and $2 million was recorded in general and administrative expense for the three months ended ~~September~~March 3031, ~~2014~~2015 and ~~2013, respectively, and $8 million and $5 million for the nine months ended September 30,~~ 2014 ~~and 2013~~, respectively.

Phantom Units. Phantom units granted during the period were service condition grants that (1) have graded vesting over five years or (2) vest over the next five years on a cliff basis; by vesting 60% at the end of the third year of service and vesting the remaining 40% at the end of the fifth year of service. Distributions related to the unvested phantom units are paid concurrent with the Partnership’s distribution for common units.

2416

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The following table presents phantom units activity for the ~~nine~~three months ended ~~September~~March 3031, ~~2014~~2015:

Phantom Units	~~Units~~	Units		~~Weighted Average GrantDate Fair Value~~	Weighted Average GrantDate Fair Value
Outstanding at beginning of period	~~982,242~~	2,167,720		$	~~23.16~~$	24.31
Service condition grants	~~810,682~~	14,911		~~26.55~~	24.28
Vested service condition	~~(6,610~~	)(1,126	)	~~25.88~~	24.19
Forfeited service condition	~~(91,234~~	)(9,329	)	~~24.81~~	25.03
Outstanding at end of period	~~1,695,080~~	2,172,176		$	~~24.68~~$	24.37

The Partnership expects to recognize $3039 million of compensation expense related to non-vested phantom units over a weighted-average period of 3.27 years.

12Cash Restricted Units. ~~FAIR~~Cash ~~VALUE~~restricted ~~MEASURES~~units awards are service condition (time-based) grants of notional units that vest 100% after the third year of continued employment. A cash restricted unit entitles the award recipient to receive cash equal to the market price of one Regency common unit as of the vesting date.

The following table presents cash restricted unit activity for the three months ended March 31, 2015:



Cash Restricted Units	Units
Outstanding at beginning of period	379,328
Service condition grants	—
Vested service condition	—
Forfeited service condition	(7,410	)
Outstanding at end of period	371,918

The Partnership expects to recognize $6 million of unit-based compensation expense related to non-vested cash restricted units over a period of 2.4 years.

11. FAIR VALUE MEASURES

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 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. Embedded derivatives related to Series A Preferred Units are valued using a binomial lattice model. The 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.

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

	Fair Value Measurements at September 30, 2014						Fair Value Measurements at December 31, 2013
	Fair Value Measurements at March 31, 2015						Fair Value Measurements at December 31, 2014
	Fair Value Total		SignificantObservableInputs(Level 2)		UnobservableInputs(Level 3)		Fair Value Total		SignificantObservableInputs(Level 2)		UnobservableInputs(Level 3)
Assets
Commodity Derivatives:
Natural Gas	$	522	$	522	$	—	$	226	$	226	$	—
NGLs	317		317		—		223		223		—
Condensate	435		435		—		—36		—36		—
Total Assets	$	1274	$	1274	$	—	$	485	$	485	$	—
Liabilities
Commodity Derivatives:
Natural Gas	$	2—	$	2—	$	—	$	4—	$	4—	$	—
NGLs	1—		1—		—		4—		4—		—
Condensate	1		1		—		1—		1—		—
Embedded derivatives in Series A Preferred Units	3014		—		3014		1916		—		1916
Total Liabilities	$	3415	$	41	$	3014	$	2816	$	9—	$	1916

The following table presents the material unobservable inputs used to estimate the fair value of the embedded derivatives in the Series A Preferred Units:

Unobservable Input		~~September~~March 3031, ~~2014~~2015
Credit Spread		43.0651	%

Changes in the Partnership’s cost of equity and U.S. Treasury yields would cause a change in the credit spread used to value the embedded derivatives.

The 25following table presents the changes in Level 3 derivatives measured on a recurring basis for the three months ended March 31, 2015. There were no transfers between the fair value hierarchy levels for the three months ended March 31, 2015.

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	Embedded Derivatives in Series A Preferred Units
Net liability balance at December 31, 2014	$	16
Change in fair value recorded in other income and deductions	(2		)
Net liability balance at March 31, 2015	$	14

The following table presents the changes in Level 3 derivatives measured on a recurring basis for the nine months ended September 30, 2014. There were no transfers between the fair value hierarchy levels for the nine months ended September 30, 2014.

	Embedded Derivatives in Series A Preferred Units
Net liability balance at December 31, 2013	$	19
Change in fair value recorded in other income and deductions	11
Net liability balance at September 30, 2014	$	30

The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to their short-term maturities. Long-term debt, other than the Senior Notes, is comprised of borrowings under which interest accrues under a floating interest rate structure. Accordingly, the carrying value approximates fair value.

The aggregate fair value and carrying amount of the Senior Notes at ~~September~~March 3031, ~~2014~~2015 were $5.94 billion and $5.691 billion, respectively. As of December 31, ~~2013~~2014, the aggregate fair value and carrying amount of the Senior Notes were $25.831 billion ~~and $2~~.80 ~~billion, respectively.~~ The fair value of the Senior Notes is a Level 1 valuation based on third party market value quotations.

1312. CONSOLIDATING GUARANTOR FINANCIAL INFORMATION

ELG, Aqua - PVR, and ORS do not fully and unconditionally guarantee, on a joint and several basis, the Senior Notes issued and outstanding as of ~~September~~March 3031, ~~2014~~2015, by the Partnership and Finance Corp. Included in the Parent financial statements are the Partnership’s intercompany investments in all consolidated subsidiaries and the Partnership’s investments in unconsolidated affiliates. ELG, Aqua - PVR, and ORS are included in the non-guarantor subsidiaries.

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The consolidating financial information for the Parent, Guarantor Subsidiaries, and Non Guarantor Subsidiaries are as follows:

	September 30, 2014
	March 31, 2015
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
ASSETS
Cash	$	—	$	—	$	2266	$	(7	)	$	1559
All other current assets	—		~~671~~596		319		(1		)	~~701~~604
Property, plant, and equipment, net	—		89,~~759~~186		~~321~~437		(8783		)	89,~~993~~540
Investments in subsidiaries	2119,~~257~~633		—		—		(2119,~~257~~633		)	—
Investments in unconsolidated affiliates	—		2,~~207~~283		—		~~164~~201			2,~~371~~484
All other assets	—		54,~~100~~729		—		—			54,~~100~~729
TOTAL ASSETS	$	2119,~~257~~633	$	16,~~737~~794	$	~~374~~512	$	(2119,~~188~~523	)	$	17,~~180~~416
LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST
All other current liabilities	—		~~810~~627		1621		(15		)	~~825~~643
Long-term liabilities	5,~~801~~181		~~763~~2,160		31		(3—		)	67,~~564~~342
Noncontrolling interest	—		—		—		~~117~~155			~~117~~155
Total partners’ capital	1514,~~456~~452		1514,~~164~~007		~~355~~490		(2119,~~301~~673		)	9,~~674~~276
TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST	$	2119,~~257~~633	$	16,~~737~~794	$	~~374~~512	$	(2119,~~188~~523	)	$	17,~~180~~416



	December 31, 2014
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
ASSETS
Cash	$	—	$	—	$	32	$	(8	)	$	24
All other current assets	—		667		13		(1		)	679
Property, plant, and equipment, net	—		8,948		353		(84		)	9,217
Investments in subsidiaries	19,829		—		—		(19,829		)	—
Investments in unconsolidated affiliates	—		2,252		—		166			2,418
All other assets	—		4,765		—		—			4,765
TOTAL ASSETS	$	19,829	$	16,632	$	398	$	(19,756	)	$	17,103

LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST
All other current liabilities	—		723		34		(1		)	756
Long-term liabilities	5,185		1,575		6		(4		)	6,762
Noncontrolling interest	—		—		—		120			120
Total partners’ capital	14,644		14,334		358		(19,871		)	9,465
TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST	$	19,829	$	16,632	$	398	$	(19,756	)	$	17,103

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	December 31, 2013
	Three Months Ended March 31, 2015
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
ASSETS
Revenues	$	—		$	982		$	17	$	—		$	999
Cash	$	—		$	—		$	19	$	—		$	19
Operating costs, expenses, and other	—			961			9		(2		)	968
All other current assets	—			366			15		—			381
Operating income	—			21			8		2			31
Property, plant, and equipment, net	—			4,244			174		—			4,418
Income from unconsolidated affiliates	—			50			—		—			50
Investments in subsidiaries	10,446			—			—		(10,446		)	—
Interest expense, net	(76		)	(6		)	—		—			(82		)
Investments in unconsolidated affiliates	—			1,995			—		102			2,097
Equity in consolidated subsidiaries	74			—			—		(74		)	—
All other assets	—			1,867			—		—			1,867
Other income and deductions, net	2			1			—		—			3
TOTAL ASSETS	$	10,446		$	8,472		$	208	$	(10,344	)	$	8,782
Income before income taxes	—			66			8		(72		)	2
LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST
Income tax expense	5			—			—		—			5
All other current liabilities	—			466			9		—			475
Net (loss) income	(5		)	66			8		(72		)	(3		)
Long-term liabilities	2,832			559			—		—			3,391
Net income attributable to noncontrolling interest	—			—			—		(4		)	(4		)
Noncontrolling interest	—			—			—		102			102
Net (loss) income attributable to Regency Energy Partners LP	$	(5	)	$	66		$	8	$	(76	)	$	(7	)
Total partners’ capital	7,614			7,447			199		(10,446		)	4,814
Total other comprehensive income	$	—		$	—		$	—	$	—		$	—
TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST	$	10,446		$	8,472		$	208	$	(10,344	)	$	8,782
Comprehensive (loss) income	(5		)	66			8		(72		)	(3		)
Comprehensive income attributable to noncontrolling interest	—			—			—		4			4
Comprehensive (loss) income attributable to Regency Energy Partners LP	$	(5	)	$	66		$	8	$	(76	)	$	(7	)

	Three Months Ended September 30, 2014
	Three Months Ended March 31, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Revenues	$	—		$	~~1,466~~848		$	1815	$	(1—	)	$	~~1,483~~863
Operating costs, expenses, and other	—			~~1,334~~834			97		(4—		)	~~1,339~~841
Operating income	—			~~132~~14			98		3—			~~144~~22
Income from unconsolidated affiliates	—			5243			—		1—			5343
Interest expense, net	(8549		)	(17		)	—		—			(8656		)
Gain (loss) on debt refinancing, net	2			—			—		—			2
Equity in consolidated subsidiaries	51			—			—		(51		)	—
Equity in consolidated subsidiaries	190			—			—		(190		)	—
Other income and deductions, net	(1		)	3			—		—			2
Other income and deductions, net	(2		)	—			—		—			(2		)
Income before income taxes	1			53			8		(51		)	11
Income before income taxes	105			183			9		(186		)	111
Income tax (benefit) expense	—			(2		)	1		—			(1		)
Income tax expense	2			2			—		—			4
Net income	1			55			7		(51		)	12
Net income	103			181			9		(186		)	107
Net income attributable to noncontrolling interest	—			(3		)	—		—			(3		)
Net income attributable to noncontrolling interest	—			—			—		(4		)	(4		)
Net income attributable to Regency Energy Partners LP	$	1		$	52		$	7	$	(51	)	$	9
Net income attributable to Regency Energy Partners LP	$	103		$	181		$	9	$	(190	)	$	103
Total other comprehensive income	$	—		$	—		$	—	$	—		$	—
Comprehensive income	~~103~~1			~~181~~55			97		(~~186~~51		)	~~107~~12
Comprehensive income attributable to noncontrolling interest	—			—3			—		4—			43
Comprehensive income attributable to Regency Energy Partners LP	$	~~103~~1		$	~~181~~52		$	97	$	(~~190~~51	)	$	~~103~~9

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	Three Months Ended September 30, 2013
	Three Months Ended March 31, 2015
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—		$	654		$	11		$	—		$	665
Cash flows from operating activities	$	—		$	108		$	8		$	6		$	122
Operating costs, expenses, and other	—			637			4			—			641
Cash flows from investing activities	—			(449		)	(100		)	26			(523		)
Operating income	—			17			7			—			24
Cash flows from financing activities	—			341			126			(31		)	436
Income from unconsolidated affiliates	—			37			—			—			37
Change in cash	—			—			34			1			35
Interest expense, net	(37		)	(4		)	—			—			(41		)
Cash at beginning of period	—			—			32			(8		)	24
Equity in consolidated subsidiaries	52			—			—			(52		)	—
Cash at end of period	$	—		$	—		$	66		$	(7	)	$	59
Other income and deductions, net	25			(1		)	—			—			24
Income before income taxes	40			49			7			(52		)	44
Income tax benefit	—			2			—			—			2
Net income	40			47			7			(52		)	42
Net income attributable to noncontrolling interest	—			(4		)	—			1			(3		)
Net income attributable to Regency Energy Partners LP	$	40		$	43		$	7		$	(51	)	$	39
Total other comprehensive income	$	—		$	—		$	—		$	—		$	—
Comprehensive income	40			47			7			(52		)	42
Comprehensive income attributable to noncontrolling interest	—			4			—			(1		)	3
Comprehensive income attributable to Regency Energy Partners LP	$	40		$	43		$	7		$	(51	)	$	39



	Three Months Ended March 31, 2014
	Parent		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Cash flows from operating activities	$	—	$	168		$	18		$	1		$	187
Cash flows from investing activities	—		(451		)	(3		)	—			(454		)
Cash flows from financing activities	—		283			(21		)	(1		)	261
Change in cash	—		—			(6		)	—			(6		)
Cash at beginning of period	—		—			19			—			19
Cash at end of period	$	—	$	—		$	13		$	—		$	13

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	Nine Months Ended September 30, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Revenues	$	—		$	3,477		$	49	$	(2	)	$	3,524
Operating costs, expenses, and other	—			3,306			24		(7		)	3,323
Operating income	—			171			25		5			201
Income from unconsolidated affiliates	—			143			—		—			143
Interest expense, net	(206		)	(14		)	—		—			(220		)
Gain (loss) on debt refinancing, net	3			(1		)	—		—			2
Equity in consolidated subsidiaries	327			—			—		(327		)	—
Other income and deductions, net	(11		)	4			—		—			(7		)
Income before income taxes	113			303			25		(322		)	119
Income tax expense	3			—			1		—			4
Net income	110			303			24		(322		)	115
Net income attributable to noncontrolling interest	—			—			—		(11		)	(11		)
Net income attributable to Regency Energy Partners LP	$	110		$	303		$	24	$	(333	)	$	104
Total other comprehensive income	$	—		$	—		$	—	$	—		$	—
Comprehensive income	110			303			24		(322		)	115
Comprehensive income attributable to noncontrolling interest	—			—			—		11			11
Comprehensive income attributable to Regency Energy Partners LP	$	110		$	303		$	24	$	(333	)	$	104

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	Nine Months Ended September 30, 2013
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Revenues	$	—		$	1,825		$	19	$	—		$	1,844
Operating costs, expenses, and other	3			1,789			9		—			1,801
Operating (loss) income	(3		)	36			10		—			43
Income from unconsolidated affiliates	—			103			—		—			103
Interest expense, net	(106		)	(13		)	—		—			(119		)
Loss on debt refinancing, net	(7		)	—			—		—			(7		)
Equity in consolidated subsidiaries	135			—			—		(135		)	—
Other income and deductions, net	3			—			—		—			3
Income before income taxes	22			126			10		(135		)	23
Income tax benefit	—			(1		)	—		—			(1		)
Net income	22			127			10		(135		)	24
Net income attributable to noncontrolling interest	—			(4		)	—		—			(4		)
Net income attributable to Regency Energy Partners LP	$	22		$	123		$	10	$	(135	)	$	20
Total other comprehensive income	$	—		$	—		$	—	$	—		$	—
Comprehensive income	22			127			10		(135		)	24
Comprehensive income attributable to noncontrolling interest	—			4			—		—			4
Comprehensive attributable to Regency Energy Partners LP	$	22		$	123		$	10	$	(135	)	$	20

	Nine Months Ended September 30, 2014
	Parent		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Cash flows from operating activities	$	—	$	525		$	46		$	(1	)	$	570
Cash flows from investing activities	—		(1,747		)	(19		)	(8		)	(1,774		)
Cash flows from financing activities	—		1,222			(24		)	2			1,200
Change in cash	—		—			3			(7		)	(4		)
Cash at beginning of period	—		—			19			—			19
Cash at end of period	$	—	$	—		$	22		$	(7	)	$	15

	Nine Months Ended September 30, 2013
	Parent		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated Partnership
Cash flows from operating activities	$	—	$	374		$	7		$	—	$	381
Cash flows from investing activities	—		(1,019		)	(86		)	—		(1,105		)
Cash flows from financing activities	—		645			38			—		683
Change in cash	—		—			(41		)	—		(41		)
Cash at beginning of period	—		—			53			—		53
Cash at end of period	$	—	$	—		$	12		$	—	$	12

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Item 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

(Tabular dollar amounts are in millions)

The following discussion analyzes our financial condition and results of operations. You should read the following discussion of our financial condition and results of operations in conjunction with (i) our historical condensed consolidated financial statements and the notes included elsewhere in this Quarterly Report on Form 10-Q and (ii) our Annual Report on Form 10-K for the year ended December 31, ~~2013~~2014.

OVERVIEW. We are a growth-oriented publicly-traded Delaware limited partnership engaged in the gathering and processing, compression, treating and transportation of natural gas; the transportation, fractionation and storage of NGLs; the gathering, transportation and terminaling of oil (crude, and/or condensate, a lighter oil) received from producers; the gathering and disposing of salt water; natural gas and NGL marketing and trading; and the management of coal and natural resource properties in the United States. We focus on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring, Avalon and Granite Wash shales. Our assets are primarily located in Texas, Louisiana, Arkansas, West Virginia, Pennsylvania, Ohio, California, Mississippi, Alabama, New Mexico and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma. On February 3, 2014, we completed our acquisition of subsidiaries of Hoover that are engaged in crude oil gathering, transportation and terminaling, condensate handling, natural gas gathering, treating, and processing and water gathering and disposal services in the Southern Delaware Basin in west Texas. On March 21, 2014, we completed our previously announced acquisition of PVR. The PVR Acquisition enhances our geographic diversity with a strategic presence in the Marcellus and Utica shales in the Appalachian Basin and the Granite Wash in the Mid-Continent region. On July 1, 2014, we completed our previously announced acquisition of Eagle Rock’s midstream business. The Eagle Rock Midstream Acquisition complements our gathering and processing business and is expected to further diversify our basin exposure in the Texas Panhandle, east Texas and south Texas.

RECENT DEVELOPMENTS.

~~Hoover~~Merger ~~Energy~~with ~~Acquisition~~ETP. On ~~February~~April 330, ~~2014~~2015, we ~~acquired~~merged ~~certain~~with ~~subsidiaries~~a wholly-owned subsidiary of ~~Hoover~~ETP, ~~for~~with athe ~~total~~Partnership ~~purchase~~continuing ~~price~~as ofthe ~~$293~~surviving ~~million,~~entity ~~consisting~~and becoming a wholly-owned subsidiary of ETP (ithe “Merger”). ~~4,040,471~~At ~~common~~the ~~units~~effective ~~issued~~time toof ~~Hoover,~~the Merger (iithe “Effective Time”), ~~$184~~each ~~million~~Partnership incommon ~~cash,~~unit and ~~(iii)~~Class $2F ~~million~~unit inconverted ~~asset~~into ~~retirement~~the ~~obligations~~right ~~assumed~~to receive 0.4124 ~~The~~ETP ~~Hoover~~common ~~Acquisition~~units. ~~increases~~Based ~~our~~on ~~fee-based~~the ~~revenue~~Partnership ~~and~~units ~~expands~~outstanding, ~~our~~ETP ~~existing~~issued ~~footprint~~approximately in172.2 ~~the~~million ~~southern~~ETP ~~portion~~Common ofUnits to the ~~Delaware~~Partnership’s ~~Basin~~unitholders, inincluding ~~west~~approximately ~~Texas~~15.5 ~~and~~million ~~our~~units ~~services~~issued to ~~producers~~ETP subsidiaries. Series A Preferred Units converted into ~~crude~~the ~~and~~right ~~water~~to ~~gathering.~~receive Aa ~~portion~~preferred ofunit ~~the~~representing ~~consideration~~a islimited ~~being~~partner ~~held~~interest in ~~escrow~~ETP, asa ~~security~~new ~~for~~class ~~certain~~of ~~indemnification~~units ~~claims.~~in WeETP ~~financed~~established at the ~~cash~~Effective ~~portion~~Time. The merger was a combination of entities under common control; therefore, the ~~purchase~~carrying ~~price~~amounts ~~through~~of ~~borrowings~~the ~~under~~Partnership's ~~our~~assets ~~revolving~~and ~~credit~~liabilities ~~facility~~will not be adjusted.

PVR Acquisition. On March 21, 2014, we acquired PVR for a total purchase price of $5.7 billion (based on our closing price of $27.82 per unit on March 21, 2014), including $1.8 billion of assumed debt. PVR unitholders received (on a per unit basis) 1.02 common units and a one-time cash payment of $36 million, which was funded through borrowings under our revolving credit facility. The PVR Acquisition enhances our geographic diversity with a strategic presence in the Marcellus and Utica shales in the Appalachian Basin and the Granite Wash in the Mid-Continent region.

Dubberly Expansion. In May 2014, we announced that we will construct a new processing plant and NGL pipeline at our Dubberly facility in North Louisiana and will include the addition of a new 200 MMcf/d cryogenic processing plant at the existing Dubberly facility, which will accept gas directly from our recently completed Dubberly gathering trunkline. The residue outlet for this facility will be RIGS. In addition, we will construct a new, 160-mile, 8 and 10 inch NGL pipeline from Dubberly for delivery to fractionation facilities in Louisiana and Texas. The pipeline will have an initial capacity of 25,000 Bbls/d, and will be expandable via additional pump stations. Combined project costs are expected to be $260 million and both the new processing facility and the NGL pipeline are backed by fee-based contracts. The projects are expected to be completed in mid-2015.

Eagle Rock Midstream Acquisition. On July 1, 2014, we acquired Eagle Rock’s midstream business for $1.3 billion, including the issuance of 8.2 million Regency common units to Eagle Rock and the assumption of $499 million of Eagle Rock’s 8.375% Senior Notes due 2019. The remainder of the purchase price was funded by $400 million in common units issued to ETE and borrowings under our revolving credit facility. This acquisition is expected to complement our core gathering and processing business, and when combined with the PVR Acquisition, is expected to further diversify our basin exposure in the Texas Panhandle, east Texas and south Texas.

Ohio River System. In August 2014, we entered into a joint venture with American Energy - Midstream, LLC (“AEM”) to form ORS. On behalf of ORS, we will construct and operate our Ohio Utica River System, (the “system”) which consists of a 52-mile, 36-inch gathering trunkline that will be capable of delivering up to 2.1 bcf/d to Rockies Express Pipeline (“REX”) and Texas Eastern Transmission, and potentially others and the construction of 25,000 horsepower of compression at the REX interconnect.

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The system is expected to be completed in the third quarter of 2015. Total costs for the system are expected to be approximately $500 million, 75% contributed from us and 25% contributed from AEM, which will be reflected on our consolidated balance sheet as a noncontrolling interest. Additionally, we and American Energy - Utica, LLC (“AEU”) entered into a gathering agreement for gas produced from the Utica Shale in eastern Ohio by AEU.

Mi Vida JV. In October 2014, our wholly owned subsidiary, Regency Mi Vida LLC ("Regency Mi Vida"), entered into a joint venture with Anadarko Mi Vida LLC ("Anadarko"). Anadarko and Regency Mi Vida each own a 50% membership interest in the new joint venture, Mi Vida JV LLC (“Mi Vida JV”), a Delaware limited liability company. We will construct and operate a 200 MMcf/d cryogenic processing plant and related facilities, in west Texas, on behalf of Mi Vida JV.

Lone Star Frac III. On November 5, 2014, we and ETP announced that Lone Star will construct a third natural gas liquids fractionator at its facility in Mont Belvieu, Texas, which will bring Lone Star’s total fractionation capacity at Mont Belvieu to 300,000 Bbls/d. Lone Star’s third fractionator is scheduled to be operational by December 2015.

OUR OPERATIONS. We divide our operations into the following six business segments:

• Gathering and Processing. We provide “wellhead-to-market” services to producers of natural gas, which include transporting 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, the gathering, ~~transportation and terminaling~~ of oil (crude and/or condensate, a lighter oil) received from producers, the gathering and disposing of salt water, and natural gas and NGL marketing and trading. This segment also includes our 60% membership interest in ELG, which operates natural gas gathering, oil pipeline, and oil stabilization facilities in south Texas, our 33.33% membership interest in Ranch JV, which processes natural gas delivered from NGL-rich shale formations in west Texas, our 50% ~~membership~~ interest in Sweeny JV, which operates a natural gas gathering facility in south Texas, our 51% membership interest in Aqua - PVR, which transports and supplies fresh water to natural gas producers in the Marcellus shale in Pennsylvania, ~~and~~ our 75% membership interest in ORS, which will operate a natural gas gathering system in the Utica shale in Ohio., Weand ~~completed~~our ~~the~~50% ~~SUGS~~interest ~~Acquisition~~in onMi ~~April~~Vida 30JV, ~~2013~~ which ~~was~~will operate a ~~reorganization~~cryogenic ofprocessing ~~entities~~plant ~~under~~and ~~common~~related ~~control~~facilities in west Texas.

• Natural Gas Transportation. We own a 49.99% general partner interest in HPC, which owns RIGS, a 450- mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets, and a 50% membership interest in MEP, which owns a 500-mile interstate natural gas pipeline stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipe Line system in Butler, Alabama. This segment also includes Gulf States, which owns a 10-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.

• NGL Services. We own a 30% membership interest in Lone Star, an entity owning a diverse set of midstream energy assets including NGL pipelines, storage, fractionation and processing facilities located in Texas, New Mexico, Mississippi and Louisiana.

• Contract Services. We own and operate a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems. We also own and operate a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and ~~dehydration~~BTU management.

• Natural Resources. We are involved in the management and leasing of coal properties and the related collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. This segment also includes our 50% interest in Coal Handling, which owns and operates end-user coal handling facilities.22

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•	Natural Resources. We are involved in the management of coal and natural resources properties and the related collection of royalties, and the operation of end-user coal handling facilities. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties.


•	Corporate. The Corporate segment comprises our corporate assets.

HOW WE EVALUATE OUR OPERATIONS. Management uses a variety of financial and operational measurements to analyze our performance. We view these measures as important tools for evaluating the success of our operations and review these measurements on a monthly basis for consistency and trend analysis. These measures include volumes, segment margin, total segment margin, adjusted segment margin, adjusted total segment margin, revenue generating horsepower and operation and maintenance expense on a segment and company-wide basis and EBITDA and adjusted EBITDA on a company-wide basis.

Volumes. We must continually obtain new supplies of natural gas to maintain or increase throughput volumes on our gathering and processing systems. Our ability to maintain existing supplies of natural gas and obtain new supplies is affected by (i) the level of workovers or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to our gathering and processing systems, (ii) our ability to compete for volumes from successful new wells in other areas and (iii) our ability to obtain natural gas that has been released from other commitments. We routinely monitor producer activity in the areas served by our gathering and processing systems to pursue new supply opportunities.

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Segment Margin and Total Segment Margin. We define segment margin, generally, as revenues minus cost of sales. We calculate our Gathering and Processing segment margin and Natural Gas Transportation segment margin as our revenues generated from operations less the cost of natural gas and NGLs purchased and other cost of sales, including third-party transportation and processing fees.

We do not record segment margin for our investments in unconsolidated affiliates (HPC, MEP, Lone Star, Ranch JV, Aqua - PVR, ~~Coal~~Mi ~~Handling~~Vida JV and Sweeny JV) because we record our ownership percentage of their net income as income from unconsolidated affiliates in accordance with the equity method of accounting.

We calculate our Contract Services segment margin as our revenues generated from our contract compression and treating operations minus direct costs, primarily repairs, associated with those revenues.

Our Natural Resources segment margin is generally equal to total revenues as there is typically minimal cost of sales associated with the management and leasing of these properties.

We calculate total segment margin as the total of segment margin of our six segments, less intersegment eliminations.

Adjusted Segment Margin and Adjusted Total Segment Margin. We define adjusted segment margin as segment margin adjusted for non-cash (gains) losses from commodity derivatives, the 40% of ELG margin attributable to the holder of the noncontrolling interest, the 25% ORS margin attributable to the holder of the noncontrolling interest, and our 33.33% portion of Ranch JV margin. Our adjusted total segment margin equals the sum of our operating segments’ adjusted segment margins or segment margins, including intersegment eliminations. Adjusted segment margin and adjusted total segment margin are included as supplemental disclosures because they are primary performance measures used by management as they represent the results of product purchases and sales, a key component of our operations.

Revenue Generating Horsepower. Revenue generating horsepower is the primary driver for revenue growth in our Contract Services segment, and it is also the primary measure for evaluating our operational efficiency. Revenue generating horsepower is the total horsepower that our Contract Services segment owns and operates for external customers. It does not include horsepower under contract that is not generating revenue or idle horsepower.

Coal Royalty Tonnage. Coal royalty tonnage is the primary driver of the value of our coal royalty revenues in our Natural Resources segment. We earn most of our coal royalty revenues under long-term leases that generally require our lessees to make royalty payments to us based on the higher of a percentage of the gross sales price or a fixed price per ton of coal they sell. The balance of our coal ~~royalties~~royalty ~~revenues~~revenue is earned under long-term leases that require the lessees to make royalty payments to us based on fixed royalty rates that escalate annually.

Operation and Maintenance Expense. Operation and maintenance expense is a separate measure that we use to evaluate operating performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of our operating and maintenance expense. These expenses are largely independent of the volumes through our systems but fluctuate depending on the activities performed during a specific period. We do not deduct operation and maintenance expense from total revenues in calculating segment margin because we use segment margin to separately evaluate commodity volume and price changes.

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EBITDA and Adjusted EBITDA. We define EBITDA as net income (loss) plus interest expense, provision for income taxes and depreciation, depletion and amortization expense. We define adjusted EBITDA as EBITDA plus or minus the following:


•	non-cash loss (gain) from commodity and embedded derivatives;


•	non-cash unit-based compensation;


•	loss (gain) on asset sales, net;


•	(gain) loss on debt refinancing;


•	other non-cash (income) expense, net;


•	our interest in ELG and ORS adjusted EBITDA less adjusted EBITDA attributable to ELG and ORS; and


•	our interest in adjusted EBITDA from unconsolidated affiliates less income from unconsolidated affiliates.

These measures are used as supplemental measures by our management and by external users of our financial statements such as investors, banks, research analysts and others, to assess:


•	financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

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•	the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our unitholders and General Partner;


•	our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and


•	the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

Neither EBITDA nor adjusted EBITDA should be considered an alternative to, or more meaningful than net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. EBITDA and adjusted EBITDA may not be comparable to a similarly titled measure of another company because other entities may not calculate EBITDA or adjusted EBITDA in the same manner. Adjusted EBITDA is the starting point in determining distributable cash flow, which is an important non-GAAP financial measure for a publicly traded partnership.

EBITDA and adjusted EBITDA do not include interest expense, income tax expense or depreciation, depletion and amortization expense. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate cash available for distribution. Because we use capital assets, depreciation, depletion and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net earnings determined under GAAP, as well as EBITDA and adjusted EBITDA, to evaluate our performance.

~~The~~ ~~following table presents a reconciliation of EBITDA and adjusted EBITDA to net cash flows provided by operating activities and to net income for the Partnership:~~24

	Nine Months Ended September 30,
Reconciliation of “Adjusted EBITDA” to net cash flows provided by operating activities and net income	2014			2013
Net cash flows provided by operating activities	$	570		$	381
Add (deduct):
Depreciation, depletion and amortization, including debt issuance cost amortization and bond premium write-off and amortization	(363		)	(211		)
Income from unconsolidated affiliates	143			103
Derivative valuation change	3			(3		)
Gain (loss) on asset sales, net	1			(1		)
Unit-based compensation expenses	(8		)	(5		)
Trade accounts receivable and related party receivables	45			73
Other current assets and other current liabilities	(52		)	26
Trade accounts payable and related party payables	(73		)	(103		)
Distributions of earnings received from unconsolidated affiliates	(147		)	(108		)
Cash flow changes in other assets and liabilities	(4		)	(128		)
Net income	115			24
Add (deduct):
Interest expense, net	220			119
Depreciation, depletion and amortization expense	384			207
Income tax expense (benefit)	4			(1		)
EBITDA	723			349
Add (deduct):
Partnership’s interest in unconsolidated affiliates’ adjusted EBITDA	240			188
Income from unconsolidated affiliates	(143		)	(103		)
Non-cash gain from commodity and embedded derivatives	(3		)	—
(Gain) loss on debt extinguishment	(2		)	7
Other expense, net	41			5
Adjusted EBITDA	$	856		$	446

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The following ~~tables~~table ~~present~~presents ~~reconciliations of net income to adjusted EBITDA for our unconsolidated affiliates, on~~ a ~~100%~~reconciliation ~~basis,~~of ~~and the Partnership’s interest in adjusted~~ EBITDA ~~for the nine months ended September 30, 2014~~ and ~~2013 (The~~ adjusted EBITDA ~~for~~to ~~our~~net ~~investments~~cash inflows ~~Aqua~~provided -by ~~PVR~~operating activities and ~~Coal~~to ~~Handling~~net ~~is from March 21, 2014~~ (~~the acquisition date~~loss) toincome ~~September~~for ~~30, 2014,~~ the ~~adjusted EBITDA for our investments in Sweeny JV from July 1, 2014 (its acquisition date) to September 30, 2014 was not material)~~Partnership:

	Nine Months Ended September 30, 2014
	Three Months Ended March 31,
	HPC			MEP			Lone Star			Ranch JV			Aqua - PVR			Coal Handling			Total
Reconciliation of “Adjusted EBITDA” to net cash flows provided by operating activities and net (loss) income	2015			2014
Net income (loss)	$	50		$	65		$	276		$	21		$	(4	)	$	3
Net cash flows provided by operating activities	$	122		$	187
Add:
Add (deduct):
Depreciation and amortization	27			52			78			4			7			1
Depreciation, depletion and amortization, including debt issuance cost amortization and bond premium write-off and amortization	(158		)	(97		)
Income tax expense	—			—			3			1			—			—
Income from unconsolidated affiliates	50			43
Interest expense, net	10			37			—			—			—			—
Derivative valuation change	(9		)	(17		)
Adjusted EBITDA	87			154			357			26			3			4
Gain (loss) on asset sales, net	—			2
Ownership interest	49.99		%	50		%	30		%	33.33		%	51		%	50		%
Unit-based compensation expenses	(4		)	(2		)
Partnership’s interest in adjusted EBITDA	$	43		$	77		$	107		$	9		$	2		$	2		$	240
Trade accounts receivable and related party receivables	(64		)	21
Other current assets and other current liabilities	(35		)	(35		)
Trade accounts payable and related party payables	149			(48		)
Distributions of earnings received from unconsolidated affiliates	(52		)	(43		)
Cash flow changes in other assets and liabilities	(2		)	1
Net (loss) income	(3		)	12
Add (deduct):
Interest expense, net	82			56
Depreciation, depletion and amortization expense	158			94
Income tax expense (benefit)	5			(1		)
EBITDA	242			161
Add (deduct):
Partnership’s interest in unconsolidated affiliates’ adjusted EBITDA	78			75
Income from unconsolidated affiliates	(50		)	(43		)
Non-cash gain from commodity and embedded derivatives	9			4
Other expense, net	3			8
Adjusted EBITDA	$	282		$	205

	Nine Months Ended September 30, 2013
	HPC			MEP			Lone Star			Ranch JV			Total
Net income	$	56		$	63		$	160		$	2
Add:
Depreciation and amortization	27			52			61			4
Interest expense, net	2			38			—			—
Other expenses, net	—			—			2			—
Adjusted EBITDA	85			153			223			6
Ownership interest	49.99		%	50		%	30		%	33.33		%
Partnership’s interest in adjusted EBITDA	$	42		$	77		$	67		$	2		$	188

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The following ~~table~~tables ~~presents~~present areconciliations ~~reconciliation~~ of ~~total~~net ~~segment~~income ~~margin~~to ~~and~~ adjusted ~~total~~EBITDA ~~segment~~for ~~margin~~our tounconsolidated ~~net~~affiliates, ~~income~~on ~~for~~a ~~the~~100% ~~three~~basis, and ~~nine~~the Partnership’s interest in adjusted EBITDA for the three months ended ~~September~~March 3031, ~~2014~~2015 and ~~2013~~2014 (The adjusted EBITDA for our investments in Aqua - PVR and Coal Handling is from March 21, 2014 (the ~~Partnership~~acquisition date) to March 31, 2014 was not material):

	Three Months Ended September 30,						Nine Months Ended September 30,
	Three Months Ended March 31, 2015
	2014			2013			2014			2013
	HPC			MEP			Lone Star			Ranch JV			Aqua - PVR			Total
Net income	$	107		$	42		$	115		$	24
Net income (loss)	$	19		$	23		$	97		$	5		$	(2	)
Add (deduct):
Add:
Operation and maintenance	129			78			300			220
Depreciation and amortization	9			17			29			1			1
General and administrative	36			13			123			64
Interest expense, net	3			8			(1		)	—			—
Loss (gain) on asset sales, net	1			(1		)	(1		)	1
Adjusted EBITDA	31			48			125			6			(1		)
Depreciation, depletion and amortization	122			74			384			207
Ownership interest	49.99		%	50		%	30		%	33.33		%	51		%
Income from unconsolidated affiliates	(53		)	(37		)	(143		)	(103		)
Partnership’s interest in adjusted EBITDA	$	15		$	24		$	38		$	2		$	(1	)	$	78
Interest expense, net	86			41			220			119
Loss on debt refinancing, net	(2		)	—			(2		)	7
Other income and deductions, net	2			(24		)	7			(3		)
Income tax expense (benefit)	4			2			4			(1		)
Total segment margin	432			188			1,007			535
Add (deduct):
Non-cash (gain) loss from commodity derivatives	(17		)	9			(13		)	2
Segment margin related to noncontrolling interests of ELG	(7		)	(4		)	(19		)	(8		)
Segment margin related to ownership percentage in Ranch JV	4			1			10			3
Adjusted total segment margin	$	412		$	194		$	985		$	532



	Three Months Ended March 31, 2014
	HPC			MEP			Lone Star			Ranch JV			Total
Net income	$	15		$	21		$	83		$	6
Add:
Depreciation and amortization	10			17			25			1
Interest expense, net	3			13			—			—
Other expenses, net	—			—			1			—
Adjusted EBITDA	28			51			109			7
Ownership interest	49.99		%	50		%	30		%	33.33		%
Partnership’s interest in adjusted EBITDA	$	14		$	26		$	33		$	2		$	75

The following table presents a reconciliation of total segment margin and adjusted total segment margin to net (loss) income for the three months ended March 31, 2015 and 2014 for the Partnership:



	Three Months Ended March 31,
	2015			2014
Net (loss) income	$	(3	)	$	12
Add (deduct):
Operation and maintenance	133			78
General and administrative	36			33
Gain on asset sales, net	—			(2		)
Depreciation, depletion and amortization	158			94
Income from unconsolidated affiliates	(50		)	(43		)
Interest expense, net	82			56
Other income and deductions, net	(3		)	(2		)
Income tax expense (benefit)	5			(1		)
Total segment margin	358			225
Add (deduct):
Non-cash loss from commodity derivatives	11			3
Segment margin related to noncontrolling interests of ELG	(7		)	(6		)
Segment margin related to ownership percentage in Ranch JV	3			3
Adjusted total segment margin	$	365		$	225

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RESULTS OF OPERATIONS

Three Months Ended ~~September~~March 3031, ~~2014~~2015 vs. Three Months Ended ~~September~~March 3031, ~~2013~~2014

	Three Months Ended September 30,
	Three Months Ended March 31,
	2014			2013			Change			Percent
	2015			2014			Change			Percent
Total revenues	$	~~1,483~~999		$	~~665~~863		$	~~818~~136		~~123~~16	%
Cost of sales	~~1,051~~641			~~477~~638			(~~574~~3		)	~~120~~—
Total segment margin (1)	~~432~~358			~~188~~225			~~244~~133			~~130~~59
Operation and maintenance	~~129~~133			78			(5155		)	6571
General and administrative	36			1333			(233		)	~~177~~9
Loss (gain) on asset sales, net	1			(1		)	(2		)	200
Gain on asset sales, net	—			(2		)	(2		)	100
Depreciation, depletion and amortization	~~122~~158			7494			(4864		)	6568
Operating income	~~144~~31			2422			~~120~~9			~~500~~41
Income from unconsolidated affiliates	5350			3743			167			4316
Interest expense, net	(8682		)	(4156		)	(4526		)	~~110~~46
Gain on debt refinancing	2			—			2			100
Other income and deductions, net	3			2			1			50
Other income and deductions, net	(2		)	24			(26		)	108
Income before income taxes	2			11			(9		)	82
Income before income taxes	111			44			67			152
Income tax expense (benefit)	5			(1		)	(6		)	600
Income tax expense	4			2			(2		)	100
Net (loss) income	(3		)	12			(15		)	125
Net income	107			42			65			155
Net income attributable to noncontrolling interest	(4		)	(3		)	(1		)	33
Net income attributable to Regency Energy Partners LP	$	103		$	39		$	64		164
Net (loss) income attributable to Regency Energy Partners LP	$	(7	)	$	9		$	(16	)	178
Gathering and processing segment margin	$	~~349~~261		$	~~136~~166		$	~~213~~95		~~157~~57
Non-cash (gain) loss from commodity derivatives	(17		)	9			(26		)	289
Non-cash loss from commodity derivatives	11			3			8			267
Segment margin related to noncontrolling interests of ELG	(7		)	(46		)	(31		)	7517
Segment margin related to ownership percentage in Ranch JV	43			13			3—			~~300~~—
Adjusted gathering and processing segment margin	~~329~~268			~~142~~166			~~187~~102			~~132~~61
Contract services segment margin (2)	6670			5256			14			2725
Natural resources segment margin	1825			—2			1823			~~100~~1,150
Corporate segment margin	23			45			(2		)	5040
Intersegment eliminations (2)	(31		)	(4		)	13			2575
Adjusted total segment margin	$	~~412~~365		$	~~194~~225		$	~~218~~140		~~112~~62	%

__________________


(1)	For a reconciliation of total segment margin to the most directly comparable financial measure calculated and presented in accordance with GAAP, see the reconciliation of total segment margin and adjusted total segment margin.

(2) Contract Services segment margin includes intersegment revenues of $31 million and $4 million for the three months ended ~~September~~March 3031, ~~2014~~2015 and ~~2013~~2014, respectively. These intersegment revenues were eliminated upon consolidation.

Net (Loss) Income Attributable to Regency Energy Partners LP. We recorded net ~~income~~loss of $~~103~~7 million for the three months ended ~~September~~March 3031, ~~2014~~2015 compared to net income of $399 million for the three months ended ~~September~~March 3031, ~~2013~~2014. The major components of this change were as follows:

• $~~244~~133 million increase in total segment margin primarily due to a $~~179~~127 million contribution in segment margin from the PVR, and Eagle Rock ~~and~~acquisitions, ~~Hoover~~including ~~acquisitions~~a $23 million contribution from the Natural Resources segment, and ~~increased~~a ~~volumes~~$14 million increase in ~~south~~the ~~and~~Contract ~~west~~Services ~~Texas~~segment ~~and~~related ~~north~~to ~~Louisiana~~an increase in ~~our~~revenue ~~Gathering~~generating ~~and~~horsepower, ~~Processing~~offset by a decrease in segment margin from the Permian region related to the decline in commodity prices;

• $167 million increase in income from unconsolidated subsidiaries primarily related to an increase in volumes fractionated at Lone Star Fractionator II ~~which was commissioned in late 2013~~ and an increase in volumes transported from west Texas; offset by

• $5164 million increase in ~~operation~~depreciation, depletion and ~~maintenance~~amortization ~~expense~~ primarily due to ~~our~~the ~~2014~~increase ~~acquisitions~~in property, plant, and ~~organic~~equipment ~~growth~~and inintangible ~~south~~assets associated with the PVR and ~~west~~Eagle ~~Texas~~Rock acquisitions;

• 37$55 million increase in operation and maintenance expense primarily due to the PVR and Eagle Rock acquisitions and organic growth in south and west Texas;

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• $4826 million increase in ~~depreciation~~interest expense, ~~depletion~~net ~~and amortization~~ primarily due to ~~the~~$15 ~~completion~~million ofin ~~various~~interest ~~organic~~expense ~~growth~~related ~~projects~~to ~~and~~the ansenior ~~increase~~notes ~~associated~~assumed ~~with~~in the PVR, ~~Hoover~~acquisition, and $18 million in interest expense related to the senior notes assumed in the Eagle Rock ~~acquisitions~~acquisition; and

• $453 million increase in ~~interest~~general ~~expense,~~and ~~net~~administrative expenses primarily due to ~~the~~higher ~~issuance~~employee ~~of $900 million 5~~expenses.~~875% senior notes issued in February 2014 and $25 million in interest expense related to the senior notes assumed in the PVR and Eagle Rock acquisitions; and~~

•Adjusted Total Segment Margin. Adjusted total segment margin increased to $23365 million ~~increase~~ in ~~general~~the ~~and~~three ~~administrative~~months ~~expenses~~ended ~~primarily~~March 31, ~~due~~2015 tofrom ~~higher~~$225 ~~acquisitions~~million ~~costs~~in ~~and~~the ~~employee~~three ~~expenses~~months ended March 31, 2014. The major components of this change were as follows:

• Adjusted ~~Total~~Gathering ~~Segment~~and ~~Margin.~~Processing ~~Adjusted total~~ segment margin increased to $~~412~~268 million induring the three months ended ~~September 30~~March 31, 2015 from $166 million for the three months ended March 31, 2014 primarily due to $104 million contribution from the PVR and Eagle Rock acquisitions, including $~~194~~29 million contribution from Eagle Rock, offset by a decrease in segment margin from the Permian region related to the decline in commodity prices. Total Gathering and Processing throughput increased to 5,756,000 MMBtu/d during the three months ended ~~September 30~~March 31, ~~2013~~2015, including 3,005,000 MMBtu/d from the PVR and Eagle Rock acquisitions, from 2,662,000 MMBtu/d during the three months ended March 31, 2014. ~~The~~Total ~~major~~NGL ~~components~~gross ofproduction ~~this~~increased ~~change~~to ~~were~~168,000 asBbls/d ~~follows:~~during the three months ended March 31, 2015 from 101,000 Bbls/d during the three months ended March 31, 2014;

• ~~Adjusted~~Natural ~~Gathering~~Resources ~~and Processing~~ segment margin ~~increased~~was to $~~329~~25 million during the three months ended ~~September~~March 3031, ~~2014~~2015. ~~from~~Coal ~~$142~~royalty ~~million~~tonnage for the ~~three~~same ~~months~~period ~~ended~~was September 30, 2013 primarily due to volume growth in south and west Texas and north Louisiana, and a $161 million contribution from the PVR, Eagle Rock and Hoover acquisitions. Total Gathering and Processing throughput increased to 5,680,000 MMBtu/d during the three months ended September 30, 2014, including 3,~~102~~240,000 ~~MMBtu/d from the PVR~~, ~~Eagle~~for ~~Rock~~an ~~and~~average ~~Hoover~~royalty ~~acquisitions,~~per ~~from~~ton ~~2,178,000~~of ~~MMBtu/d during the three months ended September 30, 2013~~$4. ~~Total NGL gross production increased to 178,000 Bbls/d during the three months ended September 30, 2014 from 96,700 Bbls/d during the three months ended September 30, 2013~~25; and

• ~~Natural~~Contract ~~Resources~~Services segment margin ~~was~~increased to $1870 million during the three months ended ~~September~~March 3031, ~~2014.~~2015 ~~Coal~~from ~~royalty~~$56 ~~tonnage~~million for the ~~same~~three ~~period~~months ended March 31, 2014. As of March 31, 2015 and 2014, total revenue generating horsepower was 31,~~544~~338,000 and 1,120,000, ~~for~~inclusive anof ~~average~~2,000 ~~royalty~~and ~~per~~47,000, ~~ton~~respectively, of ~~$4.04;~~revenue generating horsepower utilized by our Gathering and Processing segment.

•Operation ~~Contract~~and ~~Services~~Maintenance. ~~segment~~Operation ~~margin~~and maintenance expense increased to $66133 million ~~during~~in the three months ended ~~September 30~~March 31, ~~2014~~2015 from $5278 million ~~for~~during the three months ended ~~September 30~~March 31, ~~2013~~2014. AsThe ofchange ~~September 30, 2014 and 2013, total revenue generating horsepower~~ was ~~1,251,000~~primarily ~~and~~due ~~1,014,000,~~to ~~inclusive~~the ~~of 35,000 and 40,000, respectively, of revenue generating horsepower utilized by our Gathering and Processing segment.~~following:

~~Operation~~• ~~and Maintenance. Operation and maintenance expense increased to~~ $~~129~~26 million increase in ~~the~~pipeline ~~three~~and ~~months~~plant ~~ended~~maintenance ~~September 30,~~and ~~2014~~materials ~~from~~expenses ~~$78~~primarily ~~million~~due ~~during~~to ~~the~~organic ~~three~~growth ~~months~~in ~~ended~~south ~~September 30,~~and ~~2013.~~west ~~The~~Texas ~~change~~as ~~was~~well ~~primarily~~as ~~due~~the toPVR ~~the~~and ~~following:~~Eagle Rock acquisitions;

• $2921 million increase in ~~pipeline~~employee ~~and plant maintenance and materials~~ expenses ~~primarily~~related ~~due~~ to ~~organic~~an ~~growth~~increase in ~~south~~headcount ~~and~~from ~~west Texas as well as~~ the PVR, and Eagle Rock ~~and Hoover~~ acquisitions;

• $104 million increase in ~~employee~~ad ~~expenses~~valorem ~~related~~taxes due to ~~an increase in headcount from~~ the PVR, and Eagle Rock, ~~and Hoover~~ acquisitions;

• $32 million increase in utilities expenses primarily due to organic growth in south and west Texas as well as the additional facilities related to the PVR, ~~Hoover,~~ and Eagle Rock Eagle Rock acquisitions; and

• $32 million ~~increase~~ in ~~operating~~royalty ~~and~~expenses ~~maintenance~~ expenses related to the Natural Resources segment.

General and Administrative. General and administrative expense increased to $36 million in the three months ended ~~September~~March 3031, ~~2014~~2015 from $1333 million in the three months ended ~~September~~March 3031, ~~2013~~2014 primarily due to a $139 million increase in employee costs and a $102 million increase ~~due~~in tobad ~~additional~~debt ~~employees~~expense ~~and~~offset ~~costs~~by ~~from~~an ~~the~~$8 ~~PVR,~~million ~~Eagle~~decrease ~~Rock~~due ~~and~~to ~~Hoover~~lower acquisitions costs.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased to $~~122~~158 million in the three months ended ~~September~~March 3031, ~~2014~~2015 from $7494 million in the three months ended ~~September~~March 3031, ~~2013~~2014, primarily due to the completion of various organic growth projects since ~~July~~April ~~2013~~2014 and assets acquired from PVR, and Eagle Rock ~~and Hoover~~.

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Income from Unconsolidated Affiliates. Income from unconsolidated affiliates increased to $5350 million for the three months ended ~~September~~March 3031, ~~2014~~2015 from $3743 million for the three months ended ~~September~~March 3031, ~~2013~~2014. The schedule below summarizes the components of income from unconsolidated affiliates and our ownership interest for the three months ended ~~September~~March 3031, ~~2014~~2015 and ~~2013~~2014, respectively:

	Three Months Ended September 30, 2014
	Three Months Ended March 31, 2015
	HPC			MEP			Lone Star			Ranch JV			Aqua - PVR			~~Coal Handling~~Total			~~Total~~
Net income (loss)	$	19		$	2123		$	~~104~~97		$	85		$	(12	)	$	1
Ownership interest	49.99		%	50		%	30		%	33.33		%	51		%	50		%
Share of unconsolidated affiliates’ net income (loss)	9			1112			3129			32			(1		)	1
Less: Amortization of excess fair value of unconsolidated affiliates	(1		)	—			—			—			—			—
Income from unconsolidated affiliates	$	8		$	11		$	31		$	3		$	(1	)	$	1		$	53
Income (loss) from unconsolidated affiliates	$	8		$	12		$	29		$	2		$	(1	)	$	50

	Three Months Ended September 30, 2013
	Three Months Ended March 31, 2014
	HPC			MEP			Lone Star			Ranch JV			~~Total~~Grey Ranch			Total
Net income	$	1815		$	21		$	6183		$	16		$	—
Ownership interest	49.99		%	50		%	30		%	33.33		%	50		%
Share of unconsolidated affiliates’ net income	9			11			18			—
Share of unconsolidated affiliates’ net income (loss)	7			11			25			2			(1		)
Less: Amortization of excess fair value of unconsolidated affiliates	(1		)	—			—			—			—
Income from unconsolidated affiliates	$	8		$	11		$	18		$	—		$	37
Income (loss) from unconsolidated affiliates	$	6		$	11		$	25		$	2		$	(1	)	$	43

HPC’s net income increased to $19 million for the three months ended March 31, 2015 from $15 million for the three months ended March 31, 2014, primarily due to lower general and administrative expenses and higher revenues. MEP’s net income increased to $23 million for the three months ended March 31, 2015 from $21 million for the three months ended March 31, 2014. Lone Star’s net income increased to $~~104~~97 million for the three months ended ~~September~~March 3031, ~~2014~~2015 from $6183 million for the three months ended ~~September~~March 3031, ~~2013~~2014, primarily due to an increase in fractionated volumes ~~fractionated~~of at66,000 ~~Lone~~BPD ~~Star~~period ~~Fractionator~~over IIperiod ~~which~~as ~~was~~we commissioned Fractionator II in ~~late~~October 2013, anand ~~increase~~ramped inup volumes ~~transported~~to ~~from~~capacity. ~~west Texas~~Additionally, ~~and~~a an33,000 BPD increase in ~~marketing~~transported ~~net~~volumes ~~income. These~~on ~~increases~~our ~~were~~pipeline ~~offset~~system byincreased anet ~~decrease~~income infor ~~earnings~~the ~~attributable~~current toperiod ~~our~~as ~~refinery~~compared ~~off-gas~~to ~~fractionator~~the inprior ~~Geismar,~~year LAperiod.

The following table presents operational data for each of our unconsolidated affiliates for the three months ended ~~September~~March 3031, ~~2014~~2015 and ~~2013~~2014 that we owned as of both dates:

		Three Months Ended September 30,
		Three Months Ended March 31,
	Operational data	~~2014~~2015	~~2013~~2014
HPC	Throughput (MMBtu/d)	~~696~~773,000	~~697~~613,000
MEP	Throughput (MMBtu/d)	1,~~165~~302,000	1,~~279~~268,000
Lone Star	NGL Transportation — Total Volumes (Bbls/d)	~~232~~225,000	~~172~~184,000
	Refinery — Geismar Throughput (Bbls/d)	1614,000	1211,000
	Fractionation — Throughput Volume (Bbls/d)	~~209~~203,000	72135,000
Ranch JV	Throughput (MMBtu/d)	~~143~~144,000	76120,000

Interest Expense, Net. Interest expense, net increased to $8682 million for the three months ended ~~September~~March 3031, ~~2014~~2015 from $4156 million for the three months ended ~~September~~March 3031, ~~2013~~2014, primarily due to ~~the interest related to our~~ $~~900 million 5.875% senior notes issued in February 2014, the $700 million 5% senior notes issued in July 2014, $~~15 million in interest expense related to the senior notes assumed in the PVR Acquisition, and $1018 million in interest expense related to the senior notes assumed in the Eagle Rock acquisition.

Other Income and Deductions, Net. Other income and deductions ~~decreased~~increased to a $23 million ~~loss~~gain from a $242 million gain for the three months ended ~~September~~March 3031, ~~2014~~2015 and ~~2013~~2014, respectively, primarily due to a ~~$26 million~~ non-cash gain ofon the embedded derivative related to the Series A Preferred Units ~~in September 2013 resulting from the conversion of a portion of the outstanding Series A Preferred Units in September 2013~~.

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RESULTS OF OPERATIONS

Nine Months Ended September 30, 2014 vs. Nine Months Ended September 30, 2013

	Nine Months Ended September 30,
	2014			2013			Change			Percent
Total revenues	$	3,524		$	1,844		$	1,680		91	%
Cost of sales	2,517			1,309			(1,208		)	92
Total segment margin (1)	1,007			535			472			88
Operation and maintenance	300			220			(80		)	36
General and administrative	123			64			(59		)	92
(Gain) loss on asset sales, net	(1		)	1			2			200
Depreciation, depletion and amortization	384			207			(177		)	86
Operating income	201			43			158			367
Income from unconsolidated affiliates	143			103			40			39
Interest expense, net	(220		)	(119		)	(101		)	85
Gain (loss) on debt refinancing, net	2			(7		)	9			129
Other income and deductions, net	(7		)	3			(10		)	333
Income before income taxes	119			23			96			417
Income tax expense (benefit)	4			(1		)	5			500
Net income	115			24			91			379
Net income attributable to noncontrolling interest	(11		)	(4		)	(7		)	175
Net income attributable to Regency Energy Partners LP	$	104		$	20		$	84		420
Gathering and processing segment margin	$	784		$	383		$	401		105
Non-cash (gain) loss from commodity derivatives	(13		)	2			(15		)	750
Segment margin related to noncontrolling interests of ELG	(19		)	(8		)	(11		)	138
Segment margin related to ownership percentage in Ranch JV	10			3			7			233
Adjusted gathering and processing segment margin	762			380			382			101
Contract services segment margin (2)	185			149			36			24
Natural resources segment margin	40			—			40			100
Corporate segment margin	9			14			(5		)	36
Intersegment eliminations (2)	(11		)	(11		)	—			—
Adjusted total segment margin	$	985		$	532		$	453		85	%

__________________

(1) For a reconciliation of total segment margin to the most directly comparable financial measure calculated and presented in accordance with GAAP, see the reconciliation of total segment margin and adjusted total segment margin.

(2) Contract Services segment margin includes intersegment revenues of $11 million for the nine months ended September 30, 2014 and 2013. These intersegment revenues were eliminated upon consolidation.

Net Income Attributable to Regency Energy Partners LP. We recorded net income of $104 million for the nine months ended September 30, 2014 compared to net income of $20 million for the nine months ended September 30, 2013. The major components of this change were as follows:

• $472 million increase in total segment margin primarily due to a $318 million contribution in segment margin from the PVR, Eagle Rock and Hoover acquisitions and increased volumes in south and west Texas and north Louisiana in our Gathering and Processing segment;

• $40 million increase in income from unconsolidated subsidiaries primarily related to an increase in volumes fractionated at Lone Star Fractionator II which was commissioned in late 2013 and an increase in volumes transported from west Texas; offset by

• $177 million increase in depreciation, depletion and amortization primarily due to the completion of various organic growth projects and an increase associated with the PVR, Eagle Rock and Hoover acquisitions;

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• $101 million increase in interest expense, net primarily due to the issuance of $600 million 4.5% senior notes issued in April 2013, $400 million 5.75% senior notes issued in September 2013, $900 million 5.875% senior notes issued in February 2014, $700 million 5% senior notes issued in July 2014, $30 million in interest expense related to the senior notes assumed in the PVR Acquisition, and $10 million in interest expense related to the senior notes assumed in the Eagle Rock acquisition;

• $80 million increase in operation and maintenance expense primarily due to organic growth in south and west Texas, including $53 million related to the PVR, Eagle Rock and Hoover acquisitions;

• $59 million increase in general and administrative expense primarily due to higher acquisitions and employee costs; and

• $10 million decrease in other income and deductions primarily due to an increase in the non-cash mark-to-market loss on the embedded derivative related to the Series A Preferred Units for the nine months ended September 30, 2014 compared to a gain for the nine months ended September 30, 2013.

Adjusted Total Segment Margin. Adjusted total segment margin increased to $985 million in the nine months ended September 30, 2014 from $532 million in the nine months ended September 30, 2013. The major components of this change were as follows:

• Adjusted Gathering and Processing segment margin increased to $762 million during the nine months ended September 30, 2014 from $380 million for the nine months ended September 30, 2013 primarily due to volume growth in south and west Texas and north Louisiana, and a $278 million contribution from the PVR, Eagle Rock and Hoover acquisitions. Total Gathering and Processing throughput increased to 4,423,000 MMBtu/d during the nine months ended September 30, 2014, including 1,948,000 MMBtu/d from the PVR, Eagle Rock and Hoover acquisitions, from 2,116,000 MMBtu/d during the nine months ended September 30, 2013. Total NGL gross production increased to 138,000 Bbls/d during the nine months ended September 30, 2014 from 89,500 Bbls/d during the nine months ended September 30, 2013;

• Natural Resources segment margin was $40 million from March 21, 2014 (the date of acquisition) to September 30, 2014. Coal royalty tonnage for the same period was 8,027,000, for an average royalty per ton of $3.91; and

• Contract Services segment margin increased to $185 million during the nine months ended September 30, 2014 from $149 million for the nine months ended September 30, 2013. As of September 30, 2014 and 2013, total revenue generating horsepower was 1,251,000 and 1,014,000, inclusive of 35,000 and 40,000, respectively, of revenue generating horsepower utilized by our Gathering and Processing segment.

Operation and Maintenance. Operation and maintenance expense increased to $300 million in the nine months ended September 30, 2014 from $220 million during the nine months ended September 30, 2013. The change was primarily due to the following:

• $58 million increase in pipeline and plant maintenance and materials expenses primarily due to organic growth in south and west Texas as well as the PVR, Eagle Rock and Hoover acquisitions;

• $24 million increase in employee expenses related to an increase in headcount related to the PVR, Eagle Rock and Hoover acquisitions;

• $11 million increase in ad valorem taxes due to higher taxable values of assets related to assets acquired from PVR, Hoover, and Eagle Rock; and

• $8 million increase in utilities expenses due to additional facilities from the PVR, Eagle Rock and Hoover acquisitions.

General and Administrative. General and administrative expense increased to $123 million in the nine months ended September 30, 2014 from $64 million in the nine months ended September 30, 2013 primarily due to a $36 million increase in acquisition costs and $23 million increase in employee expenses related to the PVR, Eagle Rock and Hoover acquisitions.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased to $384 million in the nine months ended September 30, 2014 from $207 million in the nine months ended September 30, 2013, primarily due to the completion of various organic growth projects since July 2013 and assets acquired from PVR, Eagle Rock and Hoover.

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Income from Unconsolidated Affiliates. Income from unconsolidated affiliates increased to $143 million for the nine months ended September 30, 2014 from $103 million for the nine months ended September 30, 2013. The schedule below summarizes the components of income from unconsolidated affiliates and our ownership interest for the nine months ended September 30, 2014 and 2013, respectively:

	Nine Months Ended September 30, 2014
	HPC			MEP			Lone Star			Ranch JV			Aqua - PVR			Coal Handling			Total
Net income (loss)	$	50		$	65		$	276		$	21		$	(4	)	$	3
Ownership interest	49.99		%	50		%	30		%	33.33		%	51		%	50		%
Share of unconsolidated affiliates’ net income (loss)	25			33			83			7			(2		)	1
Less: Amortization of excess fair value of unconsolidated affiliates	(4		)	—			—			—			—			—
Income (loss) from unconsolidated affiliates	$	21		$	33		$	83		$	7		$	(2	)	$	1		$	143

	Nine Months Ended September 30, 2013
	HPC			MEP			Lone Star			Ranch JV			Total
Net income	$	56		$	63		$	160		$	2
Ownership interest	49.99		%	50		%	30		%	33.33		%
Share of unconsolidated affiliates’ net income	28			31			48			—
Less: Amortization of excess fair value of unconsolidated affiliates	(4		)	—			—			—
Income from unconsolidated affiliates	$	24		$	31		$	48		$	—		$	103

HPC’s net income decreased to $50 million for the nine months ended September 30, 2014 from $56 million for the nine months ended September 30, 2013, primarily due to the expiration of certain contracts that were not renewed, as well as a customer declaring bankruptcy on April 1, 2013. Lone Star’s net income increased to $276 million for the nine months ended September 30, 2014 from $160 million for the nine months ended September 30, 2013, primarily due to an increase in volumes fractionated at Lone Star Fractionator II which was commissioned in late 2013, and increase in volumes transported west Texas, and an increase in marketing net income due to a more favorable price environment in early 2014. These increases were offset by a decrease in earnings attributable to our refinery off-gas fractionator in Geismar, LA due to the expiration of a major refinery contract in June 2013.

The following table presents operational data for each of our unconsolidated affiliates for the nine months ended September 30, 2014 and 2013 that we owned as of both dates:

		Nine Months Ended September 30,
	Operational data	2014	2013
HPC	Throughput (MMBtu/d)	658,000	689,000
MEP	Throughput (MMBtu/d)	1,214,000	1,335,000
Lone Star	NGL Transportation — Total Volumes (Bbls/d)	210,000	163,000
	Refinery — Geismar Throughput (Bbls/d)	13,000	15,000
	Fractionation — Throughput Volume (Bbls/d)	174,000	70,000
Ranch JV	Throughput (MMBtu/d)	134,000	66,000

Interest Expense, Net. Interest expense, net increased to $220 million for the nine months ended September 30, 2014 from $119 million for the nine months ended September 30, 2013, primarily due to the interest related to our $600 million 4.5% senior notes issued April 30, 2013, our $400 million 5.75% senior notes issued in September 2013, our $900 million 5.875% senior notes issued in February 2014, our $700 million 5% senior notes issued in July 2014, $30 million in interest expense related to the senior notes assumed in the PVR Acquisition, and $10 million in interest expense related to the senior notes assumed in the Eagle Rock acquisition.

Other Income and Deductions, Net. Other income and deductions, net decreased to a loss of $7 million in the nine months ended September 30, 2014 from a gain of $3 million in the nine months ended September 30, 2013, primarily due to an increase in the non-

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cash mark-to-market loss on the embedded derivative related to the Series A Preferred Units in the nine months ended September 30, 2014 compared to a gain in the nine months ended September 30, 2013.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

In addition to the information set forth in this report, further information regarding our critical accounting policies and estimates is included in Item 7 of our Annual Report on Form 10-K for the year ended December 31, ~~2013~~2014.

OTHER MATTERS

Information regarding our commitments and contingencies is included in Note 87 – Commitments and Contingencies to the condensed consolidated financial statements included in Item 1 of this report.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

We expect our sources of liquidity to include:

• cash generated from operations and occasional asset sales;

• borrowings under our revolving credit facility;

• distributions of earnings received from unconsolidated affiliates;

• debt offerings; and

• issuance of additional partnership units.

We expect our 2014 capital expenditures, including expenditures related to the recently acquired PVR and Eagle Rock assets, to be as follows:

	2014
Growth Capital Expenditures
Gathering and Processing	$	650
NGL Services	100
Contract Services	350
Total	$	1,100
Maintenance Capital Expenditures; including our proportionate share related to our unconsolidated affiliates	$	80

We may revise the timing of these expenditures as necessary to adapt to economic or business conditions. We expect to fund our growth capital expenditures with borrowings under our revolving credit facility and a combination of debt and equity issuances.

Working Capital. Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our obligations as they become due. When we incur growth capital expenditures, we may experience working capital deficits as we fund construction expenditures out of working capital until we permanently finance them. Our working capital is also influenced by the fair value changes of current derivative assets and liabilities. These derivative assets and liabilities represent our expectations for the settlement of derivative rights and obligations over the next 12 months, and should be viewed differently from trade accounts receivable and accounts payable, which settle over a shorter span of time. When our derivative positions are settled, we expect an offsetting physical transaction, and, as a result, we do not expect derivative assets and liabilities to affect our ability to pay expenditures and obligations as they come due. Our Contract Services segment records deferred revenues as a current liability. The deferred revenue represents billings in advance of services performed. As the revenues associated with the deferred revenues are earned, the liability is reduced.

We had a working capital ~~deficit~~surplus of $~~109~~20 million at ~~September~~March 3031, ~~2014~~2015 compared to a working capital deficit of $7553 million at December 31, ~~2013~~2014. The increase in the working capital ~~deficit~~ was primarily due to a $5927 million increase in ~~accrued~~cash ~~interest primarily due to additional senior notes issued since September 2013, as well as the addition of interest related to the senior notes from the PVR~~ and ~~Eagle~~cash ~~Rock acquisitions~~equivalents, ~~a $34 million increase in other current liabilities,~~ net of ~~other~~drafts ~~current~~payable. ~~assets, and an~~

Cash 43Flows from Operating Activities. Net cash flows provided by operating activities decreased to $122 million in the three months ended March 31, 2015 from $187 million in the three months ended March 31, 2014, primarily as a result of changes in current assets and liabilities.

~~Table~~Cash Flows used in Investing Activities. Net cash flows used in investing activities was $523 million in the three months ended March 31, 2015 compared to cash used in investing activities of ~~Contents~~$454 million in the three months ended March 31, 2014 primarily due to an increase in capital expenditures related to organic growth projects and capital contributions to unconsolidated affiliates, offset by no cash spent on acquisitions in the quarter ended March 31, 2015.

~~$18~~Growth ~~million~~Capital ~~increase~~Expenditures. inGrowth ~~trade~~capital ~~accounts~~expenditures ~~payable~~are capital expenditures made to acquire additional assets to increase our business, ~~net~~to ofexpand ~~trade~~and ~~accounts~~upgrade ~~receivable~~existing systems and facilities or to construct or acquire systems or facilities. In the three months ended March 31, ~~offset~~2015, bywe aincurred $49531 million ~~increase~~of ingrowth ~~related~~capital ~~party receivables~~expenditures, ~~net~~inclusive of contributions to unconsolidated affiliates. Growth capital expenditures for the ~~decrease~~three inmonths ended March 31, 2015 were primarily related ~~party~~to ~~payables~~$325 million for our Gathering and Processing segment, $93 million for our NGL Services segment, and $113 million for our Contract Services segment.

~~Cash~~Maintenance ~~Flows~~Capital ~~from Operating Activities~~Expenditures. ~~Net~~Maintenance ~~cash~~capital ~~flows~~expenditures ~~provided~~are bycapital ~~operating~~expenditures ~~activities~~made ~~increased~~ to ~~$570~~replace ~~million~~partially inor ~~the~~fully ~~nine~~depreciated ~~months~~assets ~~ended~~or ~~September 30,~~to ~~2014~~maintain ~~from $381 million in~~ the ~~nine~~existing ~~months~~operating ~~ended~~capacity ~~September 30, 2013, primarily as a result~~ of anour ~~increase~~assets inand ~~segment~~extend ~~margin~~their ofuseful ~~$453~~lives. ~~million~~In ~~due~~the tothree ~~volume~~months ~~growth~~ended inMarch 31, ~~south and west Texas and north Louisiana~~2015, ~~and~~we ~~the~~incurred ~~PVR,~~$22 ~~Hoover~~million ~~and~~of ~~Eagle~~maintenance ~~Rock~~capital ~~acquisitions~~expenditures.

Cash Flows ~~used~~from inFinancing ~~Investing~~ Activities. Net cash flows ~~used~~provided inby ~~investing~~financing activities ~~was~~increased to $~~1.8~~436 ~~billion~~million in the ~~nine~~three months ended ~~September~~March 3031, ~~2014~~2015 ~~compared~~from to cash ~~used~~flow inprovided ~~investing~~by financing activities of $~~1.1~~261 ~~billion~~million induring the ~~nine~~same ~~months~~period ~~ended~~in ~~September 30,~~2014 ~~2013~~ primarily due to anhigher ~~increase~~borrowings inunder ~~cash~~the ~~spent~~revolving oncredit ~~acquisitions related to the PVR~~facility, ~~Hoover~~offset ~~and~~by ~~Eagle~~higher ~~Rock~~Partner ~~acquisitions~~distributions.

Growth Capital Expenditures. Growth capital expenditures are capital expenditures made to acquire additional assets to increase our business, to expand and upgrade existing systems and facilities or to construct or acquire systems or facilities. In the nine months ended September 30, 2014, we incurred $770 million of growth capital expenditures, inclusive of contributions to unconsolidated affiliates. Growth capital expenditures for the nine months ended September 30, 2014 were primarily related to $442 million for our Gathering and Processing segment, $68 million for our NGL Services segment, $4 million for our Transportation segment, and $256 million for our Contract Services segment.

Maintenance Capital Expenditures. Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets or to maintain the existing operating capacity of our assets and extend their useful lives. In the nine months ended September 30, 2014, we incurred $61 million of maintenance capital expenditures.

Cash Flows from Financing Activities. Net cash flows provided by financing activities increased to $1.2 billion in the nine months ended September 30, 2014 from cash flow provided by financing activities of $683 million during the same period in 2013 primarily due to higher repayments under the revolving credit facility, an increase in the redemption of senior notes, and an increase in partner distributions, offset by higher proceeds from the issuance of senior notes and common unit offerings.

Capital Resources

Equity Distribution Agreement. InDuring ~~June~~the ~~2012,~~three wemonths ~~entered~~ended ~~into~~March 31, an2015, ~~equity distribution agreement with Citi under which~~ we ~~may~~received ~~offer~~net ~~and~~proceeds ~~sell common units having an aggregate offering price~~ of ~~up to~~ $~~200~~34 million, from ~~time~~common ~~to time through Citi, as sales agent for the Partnership. Sales of these~~ units ~~made~~sold ~~from~~pursuant ~~time~~ to ~~time~~an ~~under the~~ equity distribution agreement which were ~~made~~used byfor ~~means~~general ofpartnership ~~ordinary brokers’ transactions on the New York Stock Exchange at market prices, in block transactions, or as otherwise agreed upon by us and Citi~~purposes. We ~~used~~did ~~the~~not ~~net~~issue ~~proceeds~~any ~~from the sale of these~~ common units ~~for~~under ~~general~~the ~~partnership~~equity ~~purposes.~~distribution ~~During~~agreement ~~the~~subsequent ~~nine~~to ~~months~~March ~~ended September 30~~31, ~~2014~~2015, weand ~~received~~the ~~net proceeds of $34 million from common units sold pursuant to this~~ equity distribution agreement. Noterminated ~~amounts~~as ~~remained~~a ~~available~~result toof bethe ~~issued~~ETP ~~under~~Merger ~~this~~in ~~agreement~~April ~~and it is no longer effective~~2015.

In May 2014, we entered into an equity distribution agreement with Barclays under which we may offer and sell common units having an aggregate offering price of up to $400 million, from time to time through Barclays, as sales agent for the Partnership. Sales of these units made from time to time under the equity distribution agreement will be made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices, in block transactions, or as otherwise agreed upon by us and Barclays. We may also sell common units to Barclays as principal for its own account at a price agreed upon at the time of sale. Any sale of common units to Barclays as principal would be pursuant to the terms of a separate agreement between us and Barclays. We intend to use the net proceeds from the sale of these units for general partnership purposes. During the nine months ended September 30~~, 2014, we received net proceeds of $128 million from common units sold pursuant to this equity distribution agreement; $272 million remains available to be issued as of September 30, 2014.~~

Common Units Sold. In June 2014, we sold 14.4 million common units to ETE Common Holdings for proceeds of $400 million. Proceeds from the issuance were used to pay down borrowings on our revolving credit facility, to redeem certain senior notes of the Partnership and for general partnership purposes. In July 2014, we sold 16.5 million common units to ETE Common Holdings for proceeds of $400 million the proceeds of which were used to fund a portion of the cash consideration paid to Eagle Rock in connection with the Eagle Rock Midstream Acquisition.

Revolver Amendment. In February 2014, RGS entered into the First Amendment to the Credit Agreement to, among other things, expressly permit the pending PVR and Eagle Rock Midstream acquisitions, and to increase the commitment to $1.5 billion and increase the uncommitted incremental facility to $500 million. The amendment allowed us to assume the series of PVR senior notes that mature prior to our Credit Agreement.

In September 2014, RGS entered into the Second Amendment to the Credit Agreement to, among other things, increase the letter of credit sublimit from $50 million to $100 million, with none of the four individual issuing banks being required to issue letters

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ofRevolving ~~credit~~Credit inFacility. ~~excess~~On ofApril ~~$25~~30, ~~million;~~2015, ~~increase~~ in ~~the~~connection ~~general~~with ~~basket~~the ofMerger, ~~permitted~~the ~~investments~~revolving ~~from~~credit ~~$300~~facility ~~million~~was topaid ~~$500~~off ~~million; add provisions permitting investments~~ in ~~ORS~~full ~~affording~~and itterminated. ~~similar~~As ~~treatment~~a toresult, ~~the~~compliance ~~Partnership’s~~with ~~existing~~material ~~joint~~covenants ~~ventures;~~is ~~and~~no ~~update~~longer ~~various~~applicable ~~swap~~as ~~agreement~~of ~~provisions~~the toreporting ~~conform to current market standards~~date.

~~Senior~~Cash ~~Notes.~~Distributions Infrom ~~February~~Unconsolidated ~~2014, we and Finance Corp~~Affiliates. ~~issued $900 million of senior notes that mature on March 1, 2022 (the “2022 Notes”).~~ The ~~2022~~following ~~Notes~~table ~~bear~~summarizes ~~interest at 5.875% with interest payable semi-annual in arrears on September 1 and March 1. At any time prior to December 1, 2021, we may redeem some or all of~~ the ~~notes~~cash atdistributions ~~100%~~from ofunconsolidated ~~the~~affiliates ~~principal~~for ~~amount thereof, plus a “make-whole” redemption price and accrued and unpaid interest, if any, to~~ the ~~redemption~~three ~~date.~~months Onended ~~or after~~March 31, ~~December~~2015 ~~1, 2021, we may redeem some or all of the notes at a redemption price equal to 100% of the principal amount thereof, plus accrued~~ and unpaid interest, if any, to the redemption date. If we undergo certain change of control transactions, we may be required to offer to purchase the notes from holders. The 2022 Notes are guaranteed by our existing consolidated subsidiaries except Finance Corp, ELG and ORS. The 2022 Notes will rank equally in right of payment with all of our existing and future senior unsecured debt, including our other outstanding Senior Notes, and contain substantially the same covenants as our other existing Senior Notes.2014:

In March 2014, in connection with the PVR Acquisition, we assumed $1.2 billion in aggregate principal amount of PVR’s outstanding senior notes, consisting of $300 million of 8.25% senior notes that mature on April 15, 2018, $400 million of 6.5% senior notes that mature on May 15, 2021, and $473 million of 8.375% senior notes that mature on June 1, 2020. In April 2014, we redeemed all of the 2018 PVR Notes for $313 million at a price of 104.125% plus accrued and unpaid interest paid to the redemption date. Interest on the 2021 PVR Notes and the 2020 PVR Notes accrue semi-annually on May 15 and November 15 and June 1 and December 1, respectively.



	Three Months Ended March 31,
	2015		2014
HPC	$	13	$	10
MEP	20		18
Lone Star	37		25
Ranch JV	3		—
	$	73	$	53

In July 2014, we exchanged $499 million of 8.375% Senior Notes due 2019 (the “Eagle Rock Notes”) of Eagle Rock and Eagle Rock Energy Finance Corp. for 8.375% Senior Notes due 2019 issued by us and Finance Corp. (the “New Partnership Notes”). The New Partnership Notes have substantially the same economic terms as the outstanding Eagle Rock Notes, including interest rate, interest payment dates, optional redemption terms and maturity. The New Partnership Notes rank equally with the Partnership’s existing Senior Notes.

In July 2014, we and Finance Corp. issued $700 million of senior notes that mature on October 1, 2022 (the “October 2022 Notes”). The October 2022 Notes bear interest at 5% with interest payable semi-annual in arrears on October 1 and April 1, beginning April 1, 2015. At any time prior to July 1, 2022, we may redeem some or all of the notes at 100% of the principal amount thereof, plus a “make-whole” redemption price and accrued and unpaid interest, if any, to the redemption date. On or after, July 1, 2022, we may redeem some or all of the notes at a redemption price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date. If we undergo certain change of control transactions, we may be required to offer to purchase the notes from holders. The October 2022 Notes will be guaranteed by substantially all of our subsidiaries. The October 2022 Notes rank equally in right of payment with all of our existing and future senior unsecured debt, including our other outstanding Senior Notes, and contain substantially the same covenants as our other existing Senior Notes.

In July 2014, we redeemed $83 million of the $473 million outstanding 2020 PVR Notes for $91 million, including $8 million of accrued interest and redemption premium.

On October 28, 2014, we issued a notice of redemption to the holders of the $600 million 2018 Notes, with a redemption date of December 2, 2014, for a total price of 103.438%.

Compliance with Loan Covenants. At September 30, 2014, we were in compliance with all covenants under the Credit Agreement and the indentures governing the Senior Notes.

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Cash Distributions from Unconsolidated Affiliates. The following table summarizes the cash distributions from unconsolidated affiliates for the nine months ended September 30, 2014 and 2013:

	Nine Months Ended September 30,
	2014		2013
HPC	$	35	$	226
MEP	54		56
Lone Star	94		56
Ranch JV	8		1
Aqua - PVR	1		—
Coal Handling	2		—
	$	194	$	339

Contractual Obligations. The following table summarizes our contractual cash obligations as of September 30, 2014:

	Payments Due By Period
Contractual Obligations	Total		Less than1 year		1-3 years		3-5 years		More than5 years
Long-term debt (including interest) (1)	$	8,884	$	357	$	748	$	1,983	$	5,796
Operating leases (5)	57		3		14		8		32
Purchase obligations (2)	322		322		—		—		—
Natural gas and midstream activities (4)	3		3		—		—		—
Distributions and redemption of Series A Preferred Units (3)	97		3		7		7		80
Related party cash obligations	87		5		11		11		60
Contingency payments (6)	3		—		2		1		—
Asset retirement obligations	14		—		—		—		14
Total (7)	$	9,467	$	693	$	782	$	2,010	$	5,982

_______________________

(1) Assumes a constant LIBOR interest rate of .578% plus applicable margin (2.50% as of September 30, 2014) for our revolving credit facility. The principal of our outstanding senior notes ($5.69 billion) bears a weighted average interest rate of 6.16%.

(2) Excludes physical and financial purchases of natural gas, NGLs, and other commodities due to the nature of both the price and volume components of such purchases, which vary on a daily and monthly basis. Additionally, we do not have contractual commitments for fixed price and/or fixed quantities of any material amount.

(3) Assumes that the Series A Preferred Units are redeemed for cash on September 2, 2029, and an annual distribution of $3 million.

(4) Commitments for natural gas midstream activities related to firm transportation agreements.

(5) Primarily relates to equipment, building leases, and leases of coal reserve-based properties which we sublease, or intend to sublease, to third parties.

(6) Represent the accreted contingency payments related to the purchase price for coal reserves in Northern Appalachia. The undiscounted contingency payments are $3 million.

(7) Excludes deferred tax liabilities of $23 million as the amount payable by period cannot be readily estimated in light of net operating loss carryforwards and future business plans for the entity that generated the deferred tax liability.


Item 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Risk and Accounting Policies. We are exposed to market risks associated with commodity prices, counterparty credit and interest rates. Our management and the board of directors of our General Partner have established comprehensive risk management policies and procedures to monitor and manage these market risks. Our General Partner is responsible for delegation of transaction authority levels, and the Audit and Risk Committee of our General Partner is responsible for the oversight of credit risk and commodity price risk, including monitoring exposure limits. The Audit and Risk Committee receives regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities.

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

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management of our contract portfolio, matching sales prices of commodities with purchases, optimization of our portfolio by monitoring basis and other price differentials in operating areas, and the use of derivative contracts. In some cases, we may not be able to match pricing terms or to cover our risk to price exposure with financial hedges, and we may be exposed to commodity price risk.

Through our natural gas marketing activity, we will have credit exposure to additional counterparties. We minimize the credit risk associated with natural gas marketing by limiting our exposure to any single counterparty and monitoring the creditworthiness of our counterparties on an ongoing basis. In addition, the our natural gas purchase and sale contracts, for certain counterparties, are subject to counterparty netting agreements governing settlement under such natural gas purchase and sales contracts, and when possible, we net the open positions of each counterparty.

We have swap contracts that settle against certain NGLs, condensate and natural gas market prices.

~~The~~ following table sets forth certain information regarding our hedges outstanding at September 30, 2014. The relevant index price that we pay for NGLs is the monthly average of the daily closing price for deliveries of commodities into Mont Belvieu, Texas, as reported by the Oil Price Information Service. The relevant index price for natural gas is NYMEX on the pricing dates as defined by the swap contracts. The relevant index for WTI is the monthly average of the daily price of WTI as reported by the NYMEX.31

September 30, 2014
Period	Underlying	Notional Volume/Amount			We Pay	We Receive Weighted Average Price			FairValueAsset/(Liability)		Effect ofHypotheticalChange inIndex*
									(in millions)
October 2014 –December 2015	Propane	(1,061	)	MBbls	Index	$	1.05	/gallon	$	1	$	4
October 2014 –December 2015	Normal Butane	(439	)	MBbls	Index	$	1.24	/gallon	1		2
October 2014 –December 2016	West Texas Intermediate Crude	(1,715	)	MBbls	Index	$	89.84	/Bbl	3		16
October 2014 –December 2015	Natural Gas	(13,289,000	)	MMBtu	Index	$	4.17	/MMBtu	3		5
						Total Fair Value			$	8

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The following table sets forth certain information regarding our hedges outstanding at March 31, 2015. The relevant index price that we pay for NGLs is the monthly average of the daily closing price for deliveries of commodities into Mont Belvieu, Texas, as reported by the Oil Price Information Service. The relevant index price for natural gas is NYMEX on the pricing dates as defined by the swap contracts. The relevant index for WTI is the monthly average of the daily price of WTI as reported by the NYMEX.



March 31, 2015
Period	Underlying	Notional Volume/ Amount			We Pay	We Receive Weighted Average Price			Fair Value Asset/ (Liability)		Effect of Hypothetical Change in Index*
									(in millions)
April 2015 – December 2015	Propane	(523	)	MBbls	Index	$	1.05	/gallon	$	12	$	1
April 2015 – December 2015	Normal Butane	(220	)	MBbls	Index	$	1.19	/gallon	5		1
April 2015 – December 2016	West Texas Intermediate Crude	(1,060	)	MBbls	Index	$	87.56	/Bbl	34		6
April 2015 – December 2015	Natural Gas	(17,875,000	)	MMBtu	Index	$	3.86	/MMBtu	22		5
						Total Fair Value			$	73

__________________


*	Price risk sensitivities were calculated by assuming a theoretical 10% change, increase or decrease, in prices regardless of the term or the historical relationships between the contractual price of the instrument and the underlying commodity price. These price sensitivity results are presented in absolute terms.


Item 4.	CONTROLS AND PROCEDURES

Disclosure controls. At the end of the period covered by this report, an evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rule 13a–15(e) and 15d–15(e) of the Exchange Act). Based on management’s evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective in achieving that level of reasonable assurance as of ~~September~~March 3031, ~~2014~~2015.

~~Internal~~There ~~control~~have ~~over~~been ~~financial~~no ~~reporting. We~~changes ~~closed~~in ~~the~~our ~~Hoover Acquisition on February 3, 2014, the PVR Acquisition on March 21, 2014 and the Eagle Rock Midstream Acquisition on July 1, 2014. As part of the post-closing integration, we are refining the~~ internal controls and processes of the acquired businesses with those of the Partnership. Management intends to exclude the internal controls related to Eagle Rock midstream operations from its annual assessment of the effectiveness of internal controls over financial reporting ~~pursuant~~(as todefined ~~Section~~in ~~404~~Rule of13(a)–15(f) ~~the~~or ~~Sarbanes-Oxely~~Rule ~~Act~~15d–15(f) of ~~2002 for 2014. This exclusion is in accordance with~~ the ~~general guidance issued by the Securities and~~ Exchange ~~Commission~~Act) ~~that~~during ~~an assessment of a recent business combination may be omitted from management’s report on internal control over financial reporting in~~ the ~~year~~three ofmonths ~~acquisition.~~ended WeMarch 31, ~~also~~2015 ~~made~~that ~~certain~~have ~~changes~~materially toaffected, ~~the~~or ~~internal~~are ~~controls~~reasonably ~~over~~likely ~~financial reporting related~~ to ~~Hoover,~~materially ~~PVR~~affect, ~~and Eagle Rock; none of which were in response to any identified significant deficiency or weakness in~~ our internal ~~control~~controls over financial reporting.

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There have been no changes, other than those resulting from the Hoover, PVR and Eagle Rock Midstream acquisitions, in our internal controls over financial reporting (as defined in Rule 13(a)–15(f) or Rule 15d–15(f) of the Exchange Act) during the three months ended September 30, 2014 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II – OTHER INFORMATION


Item 1.	LEGAL PROCEEDINGS

The information required for this item is provided in Note 87, Commitments and Contingencies, included in the notes to the unaudited condensed consolidated financial statements included under Part I, Item 1, which information is incorporated by reference into this item.


Item 1A.	RISK FACTORS

For information regarding risk, uncertainties and assumptions, see Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, ~~2013 and our Quarterly Report on Form 10-Q for the quarter ended March 31,~~ 2014. There are no material changes from the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, ~~2013 and our Quarterly Report on Form 10-Q for the quarter ended March 31,~~ 2014.


Item 4.	MINE SAFETY DISCLOSURES

Not applicable.

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Item 6.	EXHIBITS

Exhibit Number	Description	Incorporatedby Referencefrom Form	Date Filed and File No
1.1	~~Underwriting~~Equity ~~Agreement~~distribution ~~dated~~agreement aswith ofWells ~~July~~Fargo 22Securities, ~~2014~~LLC, byBarclays ~~and~~Capital ~~among~~Inc., ~~Regency~~BNP ~~Energy~~Paribas ~~Partners~~Securities LPCorp., ~~Regency~~Citigroup ~~Energy~~Global ~~Finance~~Markets ~~Corp~~Inc., ~~certain~~Credit ~~subsidiaries~~Suisse ofSecurities ~~Regency~~(USA) ~~Energy~~LLC, ~~Partners~~Deutsche LPBank ~~party~~Securities ~~thereto~~Inc., ~~and~~Goldman, ~~Barclays~~Sachs & Co., J.P. Morgan Securities LLC, Jefferies LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Mitsubishi UFJ Securities (USA) Inc., Morgan Stanley & Co. LLC, RBC Capital Markets, LLC, Scotia Capital (USA), Inc., asSunTrust ~~representative~~Robinson ofHumphrey, ~~the~~Inc., ~~several~~UBS ~~underwriters~~Securities ~~named~~LLC ~~therein~~and USCA Securities LLC.	8-K	~~July~~January 258, ~~2014001-35262~~2015
4.1	Indenture dated as of July 1, 2014 by and among Regency Energy Partners LP, Regency Energy Finance Corp., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee.	8-K	July 8, 2014001-35262
2.1	Agreement and Plan of Merger, dated as of January 25, 2015, by and among Regency Energy Partners LP, Regency GP LP, Energy Transfer Partners, L.P., Energy Transfer Partners, GP, L.P., Energy Transfer Equity, L.P.	8-K	January 26, 2015
4.2	Sixth Supplemental Indenture dated as of July 25, 2014 among Regency Energy Partners LP, Regency Energy Finance Corp., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (including the form of the notes).	8-K	July 2, 2014001-35262
2.2	Amendment No. 1 to Agreement and Plan of Merger, dated as of February 18, 2015, by and among Regency Energy Partners LP, Regency GP LP, Energy Transfer Partners, L.P., Energy Transfer Partners, GP, L.P., Energy Transfer Equity, L.P.	8-K	February 19, 2015
4.3	Seventh Supplemental Indenture dated as of July 25, 2014 among Regency Energy Partners LP, Regency Energy Finance Corp., the guarantors party thereto, and Wells Fargo Bank, National Association, as trustee.	8-K	July 2, 2014001-35262
10.1	First Amendment to Seventh Amended and Restated Credit Agreement, dated as of February 24, 2015.	*
10.1	Registration Rights Agreement dated as of July 1, 2014 by and among Regency Energy Partners LP, Regency Energy Finance Corp., the guarantors party thereto and Barclays Capital Inc., as dealer-manager.	8-K	July 8, 2014001-35262
10.2	Registration Rights Agreement dated as of July 1, 2014 by and between Regency Energy Partners LP and Eagle Rock Energy Partners, L.P.	8-K	July 8, 2014001-35262
10.3	Common Unit Purchase Agreement dated as of July 1, 2014 by and between Regency Energy Partners LP and ETE Common Holdings, LLC.	8-K	July 8, 2014001-35262
10.4	Registration Rights Agreement dated as of July 1, 2014 by and between Regency Energy Partners LP and ETE Common Holdings, LLC.	8-K	July 8, 2014001-35262
10.5	Second Amendment to Sixth Amended and Restated Credit Agreement, dated September 15, 2014.	8-K	September 19, 2014001-35262
10.6	Bonus Plan	*
31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	*
31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	*
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.	**
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.	**
101.INS	XBRL Instance Document.	*
101.SCH	XBRL Taxonomy Extension Schema Document.	*
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.	*
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.	*
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.	*
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.	*

* Filed herewith. ** Furnished herewith.

** Furnished ~~herewith~~33

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		REGENCY ENERGY PARTNERS LPBy: Regency GP LP, its general partnerBy: Regency GP LLC, its general partner
Date:	~~November~~May 68, ~~2014~~2015	/S/ A. TROY STURROCK
		A. Troy SturrockVice President, Controller and Principal Accounting Officer(Duly Authorized Officer)
		A. Troy SturrockVice President and Controller(Duly Authorized Officer)

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