PANHANDLE EASTERN PIPE LINE COMPANY, LP - FORM 10-K - EX-99.1 - EXHIBIT 99.1 REGENCY FINANCIALS

Attached files

file	filename
EX-31.2 - EXHIBIT 31.2 - PANHANDLE EASTERN PIPE LINE COMPANY, LP	pepl_12312014xex312.htm
EX-31.1 - EXHIBIT 31.1 - PANHANDLE EASTERN PIPE LINE COMPANY, LP	pepl_12312014xex311.htm
EX-32.2 - EXHIBIT 32.2 - PANHANDLE EASTERN PIPE LINE COMPANY, LP	pepl_12312014xex322.htm
EX-32.1 - EXHIBIT 32.1 - PANHANDLE EASTERN PIPE LINE COMPANY, LP	pepl_12312014xex321.htm
EXCEL - IDEA: XBRL DOCUMENT - PANHANDLE EASTERN PIPE LINE COMPANY, LP	Financial_Report.xls
10-K - 10-K - PANHANDLE EASTERN PIPE LINE COMPANY, LP	pepl_2014x10-k.htm
EX-12.1 - EXHIBIT 12.1 RATIO OF EARNINGS TO FIXED CHARGES - PANHANDLE EASTERN PIPE LINE COMPANY, LP	pepl_12312014xex121.htm

Table of Contents

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



	Page

Report of Independent Registered Public Accounting Firm	1

Consolidated Balance Sheets as of December 31, 2014 and 2013	2

Consolidated Statements of Operations for the three years ended December 31, 2014	4

Consolidated Statements of Comprehensive (Loss) Income for the three years ended December 31, 2014	5

Consolidated Statements of Cash Flows for the three years ended December 31, 2014	6

Consolidated Statements of Partners’ Capital and Noncontrolling Interest for the three years ended December 31, 2014	8

Notes to Consolidated Financial Statements	10

F- 1

Table of Contents

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 these consolidated financial statements and footnotes:



Name		Definition or Description
2018 Notes		$600 million of 6.875% senior notes with original maturity on December 1, 2018
AOCI		Accumulated Other Comprehensive Income (Loss)
Aqua - PVR		Aqua - PVR Water Services, LLC
ARO		Asset Retirement Obligation
APM		Anadarko Pecos Midstream LLC
Barclays		Barclays Capital Inc.
bps		Basis points
Citi		Citigroup Global Markets Inc.
CM		Chesapeake West Texas Processing, L.L.C.
Coal Handling		Coal Handling Solutions LLC, Kingsport Handling LLC, and Kingsport Services LLC, now known as Materials Handling Solutions LLC
Eagle Rock		Eagle Rock Energy Partners, L.P.
EFS Haynesville		EFS Haynesville, LLC, a wholly-owned subsidiary of GECC
ELG		Edwards Lime Gathering LLC and its wholly-owned subsidiaries, ELG Oil LLC and ELG Utility LLC
EPD		Enterprise Products Partners L.P.
ETC		Energy Transfer Company, the name assumed by La Grange Acquisition, L.P. for conducting business and shared services, a wholly-owned subsidiary of ETP
ETE		Energy Transfer Equity, L.P.
ETE Common Holdings		ETE Common Holdings, LLC, a wholly-owned subsidiary of ETE
ETE GP		ETE GP Acquirer LLC
ETP		Energy Transfer Partners, L.P.
ETP GP		Energy Transfer Partners GP, LP
Exchange Act		Securities Exchange Act of 1934, as amended
FASB		Financial Accounting Standards Board
FASB ASC		FASB Accounting Standards Codification
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 of the Partnership
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
IRS		Internal Revenue Service
KMP		Kinder Morgan Energy Partners, L.P.
LDH		LDH Energy Asset Holdings LLC
LIBOR		London Interbank Offered Rate
Lone Star		Lone Star NGL LLC
LTIP		Long-Term Incentive Plan

Table of Contents



Name		Definition or Description
MEP		Midcontinent Express Pipeline LLC
Mi Vida JV		Mi Vida JV LLC
MLP		Master Limited Partnership
NGLs		Natural gas liquids, including ethane, propane, normal butane, iso butane and natural gasoline
NMED		New Mexico Environmental Development
NYSE		New York Stock Exchange
ORS		Ohio River System LLC
PADEP		Pennsylvania Department of Environmental Protection
Partnership		Regency Energy Partners LP
PEPL		Panhandle Eastern Pipe Line Company, LP
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
Securities Act		Securities Act of 1933, as amended
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
Services Co.		ETE Services Company, LLC
Southern Union		Southern Union Company
SUGS		Southern Union Gas Services
SUN		Sunoco LP (formerly known as Susser, L.P.)
Sweeny JV		Sweeny Gathering, L.P.
SXL		Sunoco Logistics Partners L.P.
TCEQ		Texas Commission on Environmental Quality
U.S.		United States
Wells Fargo		Wells Fargo Securities, LLC
WTI		West Texas Intermediate Crude

Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Partners

Regency Energy Partners LP

We have audited the accompanying consolidated balance sheets of Regency Energy Partners LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income, cash flows, and partners’ capital and noncontrolling interest for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of Midcontinent Express Pipeline LLC, a 50 percent owned investee company, the Partnership’s investment in which is accounted for under the equity method of accounting. The Partnership’s investment in Midcontinent Express Pipeline LLC as of December 31, 2014 and 2013 was $695 million and $549 million, respectively, and its equity in the earnings of Midcontinent Express Pipeline LLC was $45 million, $40 million, and $42 million, respectively, for each of the three years in the period ended December 31, 2014. Those statements were audited by other auditors, whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Midcontinent Express Pipeline LLC, is based solely on the report of the other auditors.

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

In our opinion, based on our audits and the report of the other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Regency Energy Partners LP and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership’s internal control over financial reporting as of December 31, 2014, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 26, 2015 (not separately included herein) expressed an unqualified opinion thereon.

/s/ GRANT THORNTON LLP

Dallas, Texas

February 26, 2015

Table of Contents

REGENCY ENERGY PARTNERS LP

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)



	December 31,
	2014			2013
ASSETS
Current Assets:
Cash and cash equivalents	$	24		$	19
Trade accounts receivable, net of allowance for doubtful accounts of $7 and $1	483			292
Related party receivables	45			28
Inventories	67			42
Derivative assets	75			3
Other current assets	9			16
Total current assets	703			400
Property, Plant and Equipment:
Gathering and transmission systems	5,207			1,671
Compression equipment	2,378			1,627
Gas plants and buildings	386			825
Other property, plant and equipment	679			414
Natural resources	454			—
Construction-in-progress	1,156			513
Total property, plant and equipment	10,260			5,050
Less accumulated depreciation and depletion	(1,043		)	(632		)
Property, plant and equipment, net	9,217			4,418
Other Assets:
Investments in unconsolidated affiliates	2,418			2,097
Other, net of accumulated amortization of debt issuance costs of $28 and $24	103			57
Total other assets	2,521			2,154
Intangible Assets and Goodwill:
Intangible assets, net of accumulated amortization of $212 and $107	3,439			682
Goodwill	1,223			1,128
Total intangible assets and goodwill	4,662			1,810
TOTAL ASSETS	$	17,103		$	8,782

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

Table of Contents

REGENCY ENERGY PARTNERS LP

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)



	December 31,
	2014		2013
LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST
Current Liabilities:
Drafts payable	$	15	$	26
Trade accounts payable	529		291
Related party payables	64		69
Accrued expenses	43		25
Accrued interest	81		38
Other current liabilities	24		26
Total current liabilities	756		475
Long-term derivative liabilities	16		19
Other long-term liabilities	72		30
Long-term debt, net	6,641		3,310
Commitments and contingencies
Series A Preferred Units, redemption amount of $38 and $38	33		32
Partners’ Capital and Noncontrolling Interest:
Common units (412,681,151 and 214,287,955 units authorized; 409,406,482 and 210,850,232 units issued and outstanding at December 31, 2014 and 2013)	8,531		3,886
Class F units (6,274,483 units authorized, issued and outstanding at December 31, 2014 and 2013)	153		146
General partner interest	781		782
Total partners’ capital	9,465		4,814
Noncontrolling interest	120		102
Total partners’ capital and noncontrolling interest	9,585		4,916
TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST	$	17,103	$	8,782

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

Table of Contents

REGENCY ENERGY PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS

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



	Years Ended December 31,
	2014			2013			2012
REVENUES
Gas sales, including related party amounts of $80, $71, and $42	$	1,903		$	826		$	508
NGL sales, including related party amounts of $282, $81, and $28	1,741			1,053			991
Gathering, transportation and other fees, including related party amounts of $23, $26, and $29	989			545			401
Net realized and unrealized gain (loss) from derivatives	93			(8		)	23
Other	225			105			77
Total revenues	4,951			2,521			2,000
OPERATING COSTS AND EXPENSES
Cost of sales, including related party amounts of $66, $56, and $35	3,452			1,793			1,387
Operation and maintenance	448			296			228
General and administrative	158			88			100
(Gain) loss on asset sales, net	(1		)	2			3
Depreciation, depletion and amortization	541			287			252
Goodwill impairment	370			—			—
Total operating costs and expenses	4,968			2,466			1,970
OPERATING (LOSS) INCOME	(17		)	55			30
Income from unconsolidated affiliates	195			135			105
Interest expense, net	(304		)	(164		)	(122		)
Loss on debt refinancing, net	(25		)	(7		)	(8		)
Other income and deductions, net	12			7			29
(LOSS) INCOME BEFORE INCOME TAXES	(139		)	26			34
Income tax expense (benefit)	3			(1		)	—
NET (LOSS) INCOME	$	(142	)	$	27		$	34
Net income attributable to noncontrolling interest	(15		)	(8		)	(2		)
NET (LOSS) INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP	$	(157	)	$	19		$	32
Amounts attributable to Series A preferred units	4			6			10
General partner’s interest, including IDRs	31			11			9
Beneficial conversion feature for Class F units	7			4			—
Pre-acquisition loss from SUGS allocated to predecessor equity	—			(36		)	(14		)
Limited partners’ interest in net (loss) income	$	(199	)	$	34		$	27
Basic and diluted (loss) income per common unit:
Limited partners’ interest in net (loss) income	$	(199	)	$	34		$	27
Weighted average number of common units outstanding	348,070,121			196,227,348			167,492,735
Basic (loss) income per common unit	$	(0.57	)	$	0.17		$	0.16
Diluted (loss) income per common unit	$	(0.57	)	$	0.17		$	0.13
Distributions per common unit	$	1.975		$	1.87		$	1.84
Amount allocated to beneficial conversion feature for Class F units	$	7		$	4		$	—
Total number of Class F units outstanding	6,274,483			6,274,483			—
Income per Class F unit due to beneficial conversion feature	$	1.08		$	0.72		$	—

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

Table of Contents

REGENCY ENERGY PARTNERS LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

(Dollars in millions)



	Years Ended December 31,
	2014			2013		2012
Net (loss) income	$	(142	)	$	27	$	34
Other comprehensive income:
Net cash flow hedge amounts reclassified to earnings	—			—		6
Change in fair value of cash flow hedges	—			—		(4		)
Total other comprehensive income	$	—		$	—	$	2
Comprehensive (loss) income	$	(142	)	$	27	$	36
Comprehensive income attributable to noncontrolling interest	15			8		2
Comprehensive (loss) income attributable to Regency Energy Partners LP	$	(157	)	$	19	$	34

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

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REGENCY ENERGY PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)



	Years Ended December 31,
	2014			2013			2012
OPERATING ACTIVITIES
Net (loss) income	$	(142	)	$	27		$	34
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	525			293			259
Income from unconsolidated affiliates	(195		)	(135		)	(105		)
Derivative valuation changes	(93		)	6			(12		)
(Gain) loss on asset sales, net	(1		)	2			3
Unit-based compensation expenses	10			7			5
Revaluation of unconsolidated affiliate upon acquisition	(6		)	—			—
Goodwill impairment	370			—			—
Cash flow changes in current assets and liabilities:
Trade accounts receivable and related party receivables	28			(96		)	—
Other current assets and other current liabilities	34			(54		)	10
Trade accounts payable and related party payables	(16		)	119			18
Distributions of earnings received from unconsolidated affiliates	204			142			121
Cash flow changes in other assets and liabilities	1			125			(9		)
Net cash flows provided by operating activities	719			436			324
INVESTING ACTIVITIES
Capital expenditures	(1,088		)	(1,034		)	(560		)
Contributions to unconsolidated affiliates	(355		)	(148		)	(356		)
Distributions in excess of earnings of unconsolidated affiliates	68			249			83
Acquisitions, net of cash received	(805		)	(475		)	—
Proceeds from asset sales	11			15			26
Net cash flows used in investing activities	(2,169		)	(1,393		)	(807		)
FINANCING ACTIVITIES
Borrowings (repayments) under revolving credit facility, net	380			318			(140		)
Proceeds from issuance of senior notes	1,580			1,000			700
Redemptions of senior notes	(983		)	(163		)	(88		)
Debt issuance costs	(31		)	(24		)	(15		)
Partner distributions and distributions on unvested unit awards	(706		)	(386		)	(322		)
Noncontrolling interest contributions, net of distributions	3			17			42
Contributions from previous parent	—			—			51
Drafts payable	(11		)	18			4
Common units issued under unit offerings, equity distribution program and LTIP, net of issuance costs, forfeitures and tax withholding	1,227			149			311
Distributions to Series A Preferred Units	(4		)	(6		)	(8		)
Net cash flows provided by financing activities	1,455			923			535

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

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REGENCY ENERGY PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)



	Years Ended December 31,
	2014		2013			2012
Net change in cash and cash equivalents	5		(34		)	52
Cash and cash equivalents at beginning of period	19		53			1
Cash and cash equivalents at end of period	$	24	$	19		$	53

Supplemental cash flow information:
Accrued capital expenditures	$	102	$	60		$	136
Issuance of Class F and common units in connection with SUGS Acquisition	—		961			—
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 exchanged in connection with the Eagle Rock Midstream Acquisition	499		—			—
Interest paid, net of amounts capitalized	303		146			112
Accrued capital contribution to unconsolidated affiliate	—		13			23

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

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REGENCY ENERGY PARTNERS LP

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

AND NONCONTROLLING INTEREST

(Dollars in millions)



	Regency Energy Partners LP
	Common Units			Class F Units		General Partner Interest			Predecessor Equity			AOCI			Non-controlling Interest		Total
Balance - December 31, 2011	$	3,173		$	—	$	330		$	—		$	(5	)	$	33	$	3,531
Common unit offerings, net of costs	297			—		—			—			—			—		297
Issuance of common units under equity distribution program, net of costs	15			—		—			—			—			—		15
Common units issued under LTIP, net of forfeitures and tax withholding	(1		)	—		—			—			—			—		(1		)
Unit-based compensation expenses	5			—		—			—			—			—		5
Partner distributions	(309		)	—		(13		)	—			—			—		(322		)
Net income (loss)	37			—		9			(14		)	—			2		34
Noncontrolling interest contributions, net of distributions	—			—		—			—			—			42		42
Distributions to Series A Preferred Units	(8		)	—		—			—			—			—		(8		)
Accretion of Series A Preferred Units	(2		)	—		—			—			—			—		(2		)
Net cash flow hedge amounts reclassified to earnings	—			—		—			—			5			—		5
Contribution of net investment to unitholders	—			—		—			1,747			(3		)	—		1,744
Balance - December 31, 2012	$	3,207		$	—	$	326		$	1,733		$	(3	)	$	77	$	5,340
Contribution of net investment to the Partnership	—			—		1,925			(1,928		)	3			—		—
Issuance of common units in connection with the SUGS Acquisition, net of costs	819			—		(819		)	—			—			—		—
Issuance of Class F units in connection with the SUGS Acquisition, net of costs	—			142		(142		)	—			—			—		—
Contribution of assets between entities under common control below historical cost	—			—		(504		)	231			—			—		(273		)
Issuance of common units under equity distribution program, net of costs	149			—		—			—			—			—		149
Conversion of Series A Preferred Units for common units	41			—		—			—			—			—		41
Unit-based compensation expenses	7			—		—			—			—			—		7
Partner distributions and distributions on unvested unit awards	(371		)	—		(15		)	—			—			—		(386		)
Noncontrolling interest contributions, net of distributions	—			—		—			—			—			17		17
Net income (loss)	40			4		11			(36		)	—			8		27
Distributions to Series A Preferred Units	(6		)	—		—			—			—			—		(6		)
Balance - December 31, 2013	$	3,886		$	146	$	782		$	—		$	—		$	102	$	4,916

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

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REGENCY ENERGY PARTNERS LP

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

AND NONCONTROLLING INTEREST

(Dollars in millions)



	Regency Energy Partners LP
	Common Units			Class F Units		General Partner Interest			Noncontrolling Interest		Total
Balance - December 31, 2013	$	3,886		$	146	$	782		$	102	$	4,916
Issuance of common units under equity distribution program, net of costs	428			—		—			—		428
Issuance of common units to ETE Common Holdings	800			—		—			—		800
Issuance of common units in connection with Hoover Acquisition	109			—		—			—		109
Issuance of common units in connection with PVR Acquisition	3,906			—		—			—		3,906
Issuance of common units in connection with Eagle Rock Midstream Acquisition	266			—		—			—		266
Common units issued under LTIP, net of forfeitures and tax withholding	(1		)	—		—			—		(1		)
Unit-based compensation expenses	10			—		—			—		10
Partner distributions and distributions on unvested unit awards	(674		)	—		(32		)	—		(706		)
Noncontrolling interest contributions, net of distributions	—			—		—			3		3
Net (loss) income	(195		)	7		31			15		(142		)
Distributions to Series A Preferred Units	(4		)	—		—			—		(4		)
Balance - December 31, 2014	$	8,531		$	153	$	781		$	120	$	9,585

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

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REGENCY ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

1. ORGANIZATION AND BASIS OF PRESENTATION

Organization. The consolidated financial statements presented herein contain the results of Regency Energy Partners LP and its subsidiaries (the “Partnership”), a Delaware limited partnership. The Partnership was formed on September 8, 2005, and completed its IPO on February 3, 2006. The Partnership and its subsidiaries are engaged in the business of gathering 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.

Pending Merger with ETP. On January 25, 2015, the Partnership and ETP entered into the Merger Agreement pursuant to which the Partnership will merge with a wholly-owned subsidiary of ETP, with the Partnership continuing as the surviving entity and becoming a wholly-owned subsidiary of ETP (the “Merger”). At the effective time of the Merger (the “Effective Time”), each Partnership common unit and Class F unit will be converted into the right to receive 0.4066 ETP common units, plus a number of additional ETP common units equal to $0.32 per Partnership unit divided by the lesser of (i) the volume weighted average price of ETP common units for the five trading days ending on the third trading day immediately preceding the Effective Time and (ii) the closing price of ETP common units on the third trading day immediately preceding the Effective Time, rounded to the nearest ten thousandth of a unit. Each Series A Preferred Unit will be converted into the right to receive a preferred unit representing a limited partner interest in ETP, a new class of units in ETP to be established at the Effective Time. Early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, for the Merger was granted by the United States Federal Trade Commission on February 24, 2015. The transaction is expected to close in the second quarter of 2015 and is subject to other customary closing conditions including approval by the Partnership’s unitholders.

Basis of presentation. The consolidated financial statements of the Partnership have been prepared in accordance with GAAP and include the accounts of all controlled subsidiaries after the elimination of all intercompany accounts and transactions. Certain prior year numbers have been conformed to the current year presentation.

Reclassifications. During 2014, the Partnership reclassified amounts within property, plant and equipment asset categories. These reclassifications did not have any impact on amounts recorded for depreciation, depletion or amortization in 2014, and because the reclassified amounts have no significant effect on our consolidated balance sheets, prior period balances have not been adjusted for comparability purposes.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

Common Control Transactions. Entities and assets acquired from ETE and its affiliates are accounted for as common control transactions whereby the net assets acquired are combined with the Partnership’s net assets at their historical amounts. If consideration transferred differs from the carrying value of the net assets acquired, the excess or deficiency is treated as a capital transaction similar to a dividend or capital contribution. To the extent that such transactions require prior periods to be recast, historical net equity amounts prior to the transaction date are reflected in predecessor equity.

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

Equity Method Investments. The equity method of accounting is used to account for the Partnership’s interest in investments of greater than 20% voting interest or where the Partnership exerts significant influence over an investee but lacks control over the investee. Even though there 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. The Partnership acquired a 50% interest in Coal Handling as part of the PVR Acquisition and purchased the remaining 50% interest effective December 31, 2014 for $16 million, resulting in a gain on the purchase due to the revaluation of the Partnership’s previously held non-controlling interest.

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Inventories. Inventories are valued at the lower of cost or market and include materials and parts primarily utilized by the Contract Services and Gathering & Processing segments.

Property, Plant and Equipment. Property, plant and equipment is recorded at historical cost of construction or, upon acquisition, the fair value of the assets acquired. Gains or losses on sales or retirements of assets are included in operating income unless the disposition is treated as discontinued operations. Natural gas and NGLs used to maintain pipeline minimum pressures is classified as property, plant and equipment. Financing costs associated with the construction of larger assets requiring ongoing efforts over a period of time are capitalized. For the years ended December 31, 2014, 2013 and 2012, the Partnership capitalized interest of $14 million, $2 million and $1 million, respectively. The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. Expenditures to extend the useful lives of the assets are capitalized.

Depreciation expense related to property, plant and equipment was $418 million, $258 million, and $219 million for the years ended December 31, 2014, 2013 and 2012, respectively. In March 2012, the Partnership recorded a $7 million “out-of-period” adjustment to depreciation expense to correct the estimated useful lives of certain assets to comply with its policy.

Depreciation of property, plant and equipment is recorded on a straight-line basis over the following estimated useful lives:



Functional Class of Property		Useful Lives (Years)
Gathering and Transmission Systems		20 - 40
Compression Equipment		2 - 30
Gas Plants and Buildings		5 - 20
Other Property, Plant and Equipment		3 - 15

Depletion expense related to the Natural Resources segment was $11 million for the year ended December 31, 2014. Coal properties are depleted on an area-by-area basis at a rate based on the cost of the mineral properties and the number of tons of estimated proven and probable coal reserves contained therein. Proven and probable coal reserves have been estimated by the Partnership’s own geologists. The Partnership’s estimates of coal reserves are updated periodically and may result in adjustments to coal reserves and depletion rates that are recognized prospectively. From time to time, the Partnership carries out core-hole drilling activities on coal properties in order to ascertain the quality and quantity of the coal contained in those properties. These core-hole drilling activities are expensed as incurred. The Partnership depletes timber using a methodology consistent with the units-of-production method, which is based on the quantity of timber harvested. The Partnership determines depletion of oil and gas royalty interests by the units-of-production method and these amounts could change with revisions to estimated proved recoverable reserves.

Intangible Assets. As of December 31, 2014, intangible assets consisted of trade names and customer relations, and are amortized on a straight line basis over their estimated useful lives, which is the period over which the assets are expected to contribute directly or indirectly to the Partnership’s future cash flows. The estimated useful lives range from 8 to 30 years.

The Partnership assesses long-lived assets, including property, plant and equipment and intangible assets, for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is assessed by comparing the carrying amount of an asset to undiscounted future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured as the amount by which the carrying amounts exceed the fair value of the assets. The Partnership did not record any impairment in 2014, 2013, or 2012.

Goodwill. Goodwill represents the excess of the purchase price over the fair value of identifiable net assets acquired in a business combination. Goodwill is not amortized, but is tested for impairment annually based on the carrying values as of November 30 or December 31 depending upon the reporting unit, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may not be recovered. The Partnership has the option to first assess qualitative factors to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying amount as a basis for determining whether further impairment testing is necessary. Impairment is indicated when the carrying amount of a reporting unit exceeds its fair value. To estimate the fair value of the reporting units, the Partnership makes estimates and judgments about future cash flows, as well as revenues, cost of sales, operating expenses, capital expenditures and net working capital based on assumptions that are consistent with the Partnership’s most recent forecast. At the time it is determined that an impairment has occurred, the carrying value of the goodwill is written down to its fair value.

In 2014, a $370 million goodwill impairment charge was recorded related to the Permian reporting unit within the Gathering and Processing segment. The decline in estimated fair value of that reporting unit is primarily driven by the significant decline in commodity prices in the fourth quarter of 2014, and the resulting impact to future commodity prices as well as increases in future estimated operations and maintenance expenses. As a result of the Partnership’s determination that the estimated fair value of the reporting unit being less than the carrying value, the Partnership performed the second step of the goodwill impairment assessment,

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which requires the assets and liabilities of the reporting unit to be fair valued on a hypothetical basis. Any excess value over the estimated fair value of the reporting unit, determined in this case through established valuation techniques such as discounted cash flow methods and market comparable analyses, compared to the hypothetical fair value of all assets and liabilities of the reporting unit is the implied fair value of goodwill. To the extent that the implied fair value of goodwill is less than the carrying value of goodwill, an impairment is recognized to eliminate any excess carrying amounts.

No other goodwill impairments were identified or recorded for the Partnership’s other reporting units in 2014. No goodwill impairment charges were incurred in 2013 or 2012.

Other Assets, net. Other assets, net primarily consists of debt issuance costs, which are capitalized and amortized to interest expense, net over the life of the related debt.

Gas Imbalances. Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements are recorded monthly as other current assets or other current liabilities using then current market prices or the weighted average prices of natural gas or NGLs at the plant or system pursuant to imbalance agreements for which settlement prices are not contractually established.

Within certain volumetric limits determined at the sole discretion of the creditor, these imbalances are generally settled by deliveries of natural gas. Imbalance receivables and payables as of December 31, 2014 and 2013 were immaterial.

Asset Retirement Obligations. Legal obligations associated with the retirement of long-lived assets are recorded at fair value at the time the obligations are incurred, if a reasonable estimate of fair value can be made. Present value techniques are used which reflect assumptions such as removal and remediation costs, inflation, and profit margins that third parties would demand to settle the amount of the future obligation. The Partnership does not include a market risk premium for unforeseeable circumstances in its fair value estimates because such a premium cannot be reliably estimated. Upon initial recognition of the liability, costs are capitalized as a part of the long-lived asset and allocated to expense over the useful life of the related asset. The liability is accreted to its present value each period with accretion being recorded to operating expense with a corresponding increase in the carrying amount of the liability. The ARO assets and liabilities were immaterial as of December 31, 2014.

Environmental. The Partnership’s operations are subject to federal, state and local laws and rules and regulations regarding water quality, hazardous and solid waste management, air quality control and other environmental matters. These laws, rules and regulations require the Partnership to conduct its operations in a specified manner and to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with applicable environmental laws, rules and regulations may expose the Partnership to significant fines, penalties and/or interruptions in operations. The Partnership’s environmental policies and procedures are designed to achieve compliance with such applicable laws and regulations. These evolving laws and regulations and claims for damages to property, employees, other persons and the environment resulting from current or past operations may result in significant expenditures and liabilities in the future.

Predecessor Equity. Predecessor equity included on the consolidated statements of partners’ capital and noncontrolling interest represents SUGS member’s capital prior to the acquisition date (April 30, 2013).

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

Coal Royalties Revenues and Deferred Income. The Partnership recognizes coal 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

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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 in other income as it is earned.

Derivative Instruments. The Partnership’s net income and cash flows are subject to volatility stemming from changes in market prices such as natural gas prices, NGLs prices, processing margins and interest rates. The Partnership uses product-specific swaps to create offsetting positions to specific commodity price exposures, and uses interest rate swap contracts to create offsetting positions to specific interest rate exposures. Derivative financial instruments are recorded on the balance sheet at their fair value based on their settlement date. The Partnership employs derivative financial instruments in connection with an underlying asset, liability and/or anticipated transaction and not for speculative purposes. Furthermore, the Partnership regularly assesses the creditworthiness of counterparties to manage the risk of default. As of December 31, 2014 and 2013, no derivative financial instruments were designated as hedges. In the statement of cash flows, the effects of settlements of derivative instruments are classified consistent with the related hedged transactions.

Benefits. The Partnership provides medical, dental, and other healthcare benefits to employees. The total amount incurred by the Partnership for the years ended December 31, 2014, 2013 and 2012, was $17 million, $9 million and $9 million, respectively, in operation and maintenance and general and administrative expenses, as appropriate. The Partnership also provides a matching contribution to its employee’s 401(k) accounts which vest immediately upon contribution. The total amount of matching contributions for the years ended December 31, 2014, 2013 and 2012 was $9 million, $7 million and $4 million, respectively, and were recorded in operation and maintenance and general and administrative expenses, as appropriate. The Partnership has no pension obligations or other post-employment benefits. Beginning January 1, 2013, the Partnership provides a 3% profit sharing contribution to employee 401(k) accounts for all employees with base compensation below a specified threshold. The contribution is in addition to the 401(k) matching contribution and employees become vested based on years of service.

Income Taxes. The Partnership is generally not subject to income taxes, except as discussed below, because its income is taxed directly to its partners. The Partnership is subject to the gross margins tax enacted by the state of Texas. The Partnership has one wholly-owned subsidiary that is subject to income tax and provides for deferred income taxes using the asset and liability method. Accordingly, deferred taxes are recorded for differences between the tax and book basis that will reverse in future periods. The Partnership has deferred tax liabilities of $20 million and $22 million as of December 31, 2014 and 2013, respectively, related to the difference between the book and tax basis of property, plant and equipment and intangible assets and they are included in other long-term liabilities in the accompanying consolidated balance sheets. The Partnership follows the guidance for uncertainties in income taxes where a liability for an unrecognized tax benefit is recorded for a tax position that does not meet the “more likely than not” criteria. The Partnership has not recorded any uncertain tax positions meeting the more likely than not criteria as of December 31, 2014 and 2013. The Partnership recognized $3 million for current and deferred federal and state income tax for the year ended December 31, 2014 and an immaterial amount for current and deferred federal and state income tax benefit for the years ended December 31, 2013 and 2012.

Effective with the Partnership’s acquisition of SUGS on April 30, 2013, SUGS is generally no longer subject to federal income taxes and subject only to gross margins tax in the state of Texas. Substantially all previously recorded current and deferred tax liabilities were settled with Southern Union, along with all other intercompany receivables and payables at the date of acquisition.

The Partnership has its 2007 and 2008 tax years under audit by the IRS. Until this matter is fully resolved, it is not known whether any amounts ultimately recorded would be material, or how such adjustments would affect unitholders. The statute of limitations for these audits has been extended to December 31, 2015.

Equity-Based Compensation. The Partnership accounts for common unit options and phantom units by recognizing the grant-date fair value of awards into expense as they are earned, using an estimated forfeiture rate. The forfeiture rate assumption is reviewed annually to determine whether any adjustments to expense are required. Cash restricted units are recorded in other long-term liabilities on our consolidated balance sheet. The fair value of cash restricted units is remeasured at the end of each reporting period, based on the trading price of our common units, and compensation expense is recorded using the straight-line method over the vesting period.

Earnings per Unit. Basic net income per common unit is computed through the use of the two-class method, which allocates earnings to each class of equity security based on their participation in distributions and deemed distributions. Accretion of the Series A Preferred Units is considered as deemed distributions. Distributions and deemed distributions to the Series A Preferred Units reduce the amount of net income available to the general partner and limited partner interests. The general partners’ interest in net income or loss consists of its respective percentage interest, make-whole allocations for any losses allocated in a prior tax year and IDRs. After deducting the General Partner’s interest, the limited partners’ interest in the remaining net income or loss is

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allocated to each class of equity units based on distributions and beneficial conversion feature amounts, if applicable, then divided by the weighted average number of common and subordinated units outstanding in each class of security. Diluted net income per common unit is computed by dividing limited partners’ interest in net income, after deducting the General Partner’s interest, by the weighted average number of units outstanding and the effect of non-vested phantom units, Series A Preferred Units and unit options. For special classes of common units, such as the Class F units issued with a beneficial conversion feature, the amount of the benefit associated with the period is added back to net income and the unconverted class is added to the denominator.

New Accounting Pronouncement. In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that 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. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including 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.

3. PARTNERS’ CAPITAL AND DISTRIBUTIONS

Units Activity. The changes in common and Class F units were as follows:



	Common		Class F
Balance - December 31, 2011	157,437,608		—
Common unit offerings, net of costs	12,650,000		—
Issuance of common units under the equity distribution agreement, net of cost	691,129		—
Issuance of common units under LTIP, net of forfeitures and tax withholding	172,720		—
Balance - December 31, 2012	170,951,457		—
Issuance of common units under LTIP, net of forfeitures and tax withholding	184,995		—
Issuance of common units under the equity distribution agreement, net of cost	5,712,138		—
Conversion of Series A preferred units for common units	2,629,223		—
Issuance of common units and Class F units in connection with SUGS Acquisition	31,372,419	⁽¹⁾	6,274,483	⁽²⁾
Balance - December 31, 2013	210,850,232		6,274,483
Issuance of common units under LTIP, net of forfeitures and tax withholding	163,054		—
Issuance of common units under the equity distribution agreements	14,827,919		—
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 in connection with Eagle Rock Midstream Acquisition	8,245,859		—
Issuance of common units to ETE Common Holdings	30,890,565		—
Balance - December 31, 2014	409,406,482		6,274,483


(1)	ETE has agreed to forgo IDR payments on the Partnership common units issued with the SUGS Acquisition for twenty-four months post-transaction closing.


(2)	The Class F units are not entitled to participate in the Partnership’s distributions or earnings for twenty-four months post-transaction closing.

Equity Distribution Agreement. In June 2012, the Partnership entered into an equity distribution agreement with Citi under which the Partnership offered and sold common units for an aggregate offering price of $200 million, from time to time through Citi, as sales agent for the Partnership. Sales of these common 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. For the years ended December 31, 2014 and 2013, the Partnership received net proceeds of $34 million and $149 million, respectively, from common units sold pursuant to this equity distribution agreement. No amounts remain available to be issued under this agreement and it is no longer effective.

In May 2014, the Partnership entered into an equity distribution agreement with a group of banks and investment companies (the “Managers”) under which the Partnership offered and sold common units for an aggregate offering price of $400 million, from time to time through the Managers, 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 the Managers. The Partnership used the net proceeds

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from the sale of these units for general partnership purposes. For the year ended December 31, 2014, the Partnership received net proceeds of $395 million from common units sold pursuant to this equity distribution agreement. No amounts remained available to be issues under this agreement and it is no longer effective.

In January 2015, the Partnership entered into an equity distribution agreement with another group of banks and investment companies (the "2015 Managers") under which the Partnership may offer and sell common units for an aggregate offering price of up to $1 billion, from time to time through the 2015 Managers, as sales agent for the Partnership. Sales of these common 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 the 2015 Managers. The Partnership may also sell common units to the 2015 Managers as principal for their own accounts at a price agreed upon at the time of sale. Any sale of common units to the 2015 Managers as principal would be pursuant to the terms of a separate agreement between the Partnership and the 2015 Managers. The Partnership intends to use the net proceeds from the sale of these common units for general partnership purposes.

Common Units Sold. 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 credit facility, to redeem certain senior notes of the Partnership and for general partnership purposes. In July 2014, the Partnership 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.

Public Common Unit Offerings. In March 2012, the Partnership issued 12,650,000 common units representing limited partner interests in a public offering at a price of $24.47 per common unit, resulting in net proceeds of $297 million. In May 2012, the Partnership used the net proceeds from this offering to redeem 35%, or $88 million, in aggregate principal amounts of its outstanding senior notes due 2016; pay related premium, expenses and accrued interest; and repay outstanding borrowings under the revolving credit facility.

Beneficial Conversion Feature. The Partnership issued 6,274,483 Class F units in connection with the SUGS Acquisition. At the commitment date (February 27, 2013), the sales price of $23.91 per unit represented a $2.19 per unit discount from the fair value of the Partnership’s common units as of April 30, 2013. Under FASB ASC 470-20, “Debt with Conversion and Other Options,” the discount represents a beneficial conversion feature that is treated as a non-cash distribution for purposes of calculating earnings per unit. The beneficial conversion feature is reflected in income per unit using the effective yield method over the period the Class F units are outstanding, as indicated on the statement of operations in the line item entitled “beneficial conversion feature for Class F units.” The Class F units are convertible to common units on a one-for-one basis on May 8, 2015.

Noncontrolling Interest. The Partnership operates ELG, a gas gathering joint venture in south Texas in which other third party companies own a 40% interest, and ORS, a gathering joint venture in Ohio in which a third party company owns a 25% interest, which are reflected on the Partnership’s consolidated balance sheet as noncontrolling interest.

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

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

General Partner Interest and Incentive Distribution Rights. The General Partner is entitled to its proportionate share of all quarterly distributions that the Partnership makes prior to its liquidation. The General Partner has the right, but not the obligation, to contribute a proportionate amount of capital to the Partnership to maintain its current general partner interest. The General Partner’s initial 2% interest in these distributions has been reduced since the Partnership has issued additional units and the General Partner has not contributed a proportionate amount of capital to the Partnership to maintain its General Partner interest. The General Partner ownership interest as of December 31, 2014 was 0.69%. This General Partner interest is represented by 2,834,381 equivalent units as of December 31, 2014.

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

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In connection with the SUGS Acquisition, ETE agreed to forgo IDR payments on the Partnership common units issued with this transaction for the twenty-four months post-transaction closing.

Distributions. The Partnership made the following cash distributions per unit during the years ended December 31, 2014 and 2013:



Distribution Date	Cash Distribution (per common unit)
November 14, 2014	$	0.5025
August 14, 2014	0.490
May 15, 2014	0.480
February 14, 2014	0.475

November 14, 2013	$	0.470
August 14, 2013	0.465
May 13, 2013	0.460
February 14, 2013	0.460

The Partnership paid a cash distribution of $0.5025 per common unit on February 13, 2015.

4. (LOSS) INCOME PER LIMITED PARTNER UNIT

The following table provides a reconciliation of the numerator and denominator of the basic and diluted (loss) earnings per unit computations for the years ended December 31, 2014, 2013, and 2012.



	Years Ended December 31,
	2014							2013					2012
	Loss (Numerator)			Units (Denominator)	Per-Unit Amount			Income (Numerator)		Units (Denominator)	Per-Unit Amount		Income (Numerator)			Units (Denominator)	Per-Unit Amount
Basic (loss) income per unit
Limited Partners’ interest in net (loss) income	$	(199	)	348,070,121	$	(0.57	)	$	34	196,227,348	$	0.17	$	27		167,492,735	$	0.16
Effect of Dilutive Securities:
Common unit options	—			—				—		22,714			—			10,854
Phantom units *	—			—				—		357,230			—			223,325
Series A Preferred Units	—			—				—		2,050,854			(5		)	4,658,700
Diluted (loss) income per unit	$	(199	)	348,070,121	$	(0.57	)	$	34	198,658,146	$	0.17	$	22		172,385,614	$	0.13

__________________


*	Amount assumes maximum conversion rate for market condition awards.

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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 period presented:



	Year Ended December 31, 2014
Common unit options	25,959
Phantom units	469,264
Series A Preferred Units	2,059,503

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

5. 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 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 Common Holdings and borrowings under the Partnership’s revolving credit facility. The Partnership accounted 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 complemented the Partnership’s core gathering and processing business and further diversified the Partnership’s geographic presence in the mid-continent region, east Texas and south Texas. Revenues and net income attributable to Eagle Rock’s operations included in the statement of operations for the year ended December 31, 2014 were $903 million and $30 million, respectively.

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	$	120
Property, plant and equipment	1,295
Other long-term assets	4
Goodwill ⁽¹⁾	49
Total Assets Acquired	$	1,468
Liabilities
Current liabilities	$	116
Long-term debt	499
Long-term liabilities	12
Total Liabilities Assumed	$	627

Net Assets Acquired	$	841

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

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, 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 enhanced the Partnership’s geographic diversity by adding 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 and net income

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attributable to PVR’s operations included in the statement of operations for the year ended December 31, 2014 were $956 million and $166 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 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.

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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 increased the Partnership’s fee-based 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 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 and net income attributable to Hoover’s operations included in the statement of operations for the year ended December 31, 2014 were $35 million and less than $1 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.

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Pro Forma Results of Operations

The following unaudited pro forma consolidated results of operations for the years ended December 31, 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 acquisitions occurred on January 1, 2013, nor is it indicative of future results of operations. Actual results for the year ended December 31, 2014 include PVR, Hoover, and the Eagle Rock midstream business from their respective dates of acquisition.



	Years Ended December 31,
	2014			2013
Revenues	$	5,780		$	4,695
Net loss attributable to the Partnership	(252		)	(195		)

Basic net loss per Limited Partner unit	$	(0.76	)	$	(0.50	)
Diluted net loss per Limited Partner unit	$	(0.76	)	$	(0.50	)

2013

SUGS Acquisition. In April 2013, the Partnership acquired SUGS from Southern Union, a wholly-owned subsidiary of Holdco, for $1.5 billion (the “SUGS Acquisition”).

The Partnership accounted for the SUGS Acquisition in a manner similar to the pooling of interest method of accounting as it was a transaction between commonly controlled entities. The Partnership retrospectively adjusted its financial statements to include the balances and operations of SUGS for periods March 26, 2012 to April 30, 2013. The SUGS Acquisition did not impact historical earnings per unit as pre-acquisition earnings were allocated to predecessor equity.

The assets acquired and liabilities assumed in the SUGS Acquisition were as follows:



	April 30, 2013
Current assets	$	113
Property, plant and equipment, net	1,608
Goodwill	337
Other non-current assets	1
Total Assets Acquired	$	2,059
Less:
Current liabilities	(93		)
Non-current liabilities	(36		)
Net Assets Acquired	$	1,930

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



	Years Ended December 31,
	2013 ⁽¹⁾			2012
Revenues:
Partnership	$	2,253		$	1,339
SUGS ⁽¹⁾	268			661
Combined	$	2,521		$	2,000

Net income (loss):
Partnership	$	63		$	48
SUGS ⁽¹⁾	(36		)	(14		)
Combined	$	27		$	34


⁽¹⁾	Combined amounts attributable to SUGS include the period from March 26, 2012 to December 31, 2012 for the year ended December 31, 2012, and the period from January 1, 2013 to April 30, 2013 for the year ended December 31, 2013. Subsequent to the closing of the SUGS Acquisition on April 30, 2013, the results of SUGS were attributable to the Partnership.

6. INVESTMENTS IN UNCONSOLIDATED AFFILIATES

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



			December 31,
	Ownership	Type	2014		2013
HPC	49.99%	General Partner	$	422	$	442
MEP	50.00%	Membership Interest	695		549
Lone Star	30.00%	Membership Interest	1,162		1,070
Ranch JV	33.33%	Membership Interest	38		36
Aqua - PVR	51.00%	Membership Interest	46		—
Mi Vida JV	50.00%	Membership Interest	54		—
Others⁽¹⁾			1		—
			$	2,418	$	2,097

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

The Partnership’s interests in the Aqua - PVR joint venture was acquired in the PVR 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 following tables summarize the changes in the Partnership’s investment activities in each of the unconsolidated affiliates for the years ended December 31, 2014, 2013 and 2012:



	Year Ended December 31, 2014
	HPC			MEP⁽²⁾			Lone Star			Ranch JV			Aqua - PVR			Mi Vida JV		Others ⁽⁴⁾
Contributions to unconsolidated affiliates	$	—		$	175		$	114		$	—		$	—		$	54	$	—
Distributions from unconsolidated affiliates	(48		)	(73		)	(137		)	(8		)	(1		)	—		(4		)
Share of earnings of unconsolidated affiliates’ net income (loss)	33			45			116			9			(4		)	—		2
Amortization of excess fair value of investment ⁽¹⁾	(6		)	—			—			—			—			—		—

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	Year Ended December 31, 2013
	HPC ⁽³⁾			MEP			Lone Star			Ranch JV			Others ⁽⁴⁾
Contributions to unconsolidated affiliates	$	—		$	—		$	137		$	2		$	—
Distributions from unconsolidated affiliates	(238		)	(72		)	(79		)	(2		)	—
Share of earnings of unconsolidated affiliates’ net income	36			40			64			1			—
Amortization of excess fair value of investment ⁽¹⁾	(6		)	—			—			—			—



	Year Ended December 31, 2012
	HPC			MEP			Lone Star			Ranch JV			Others ⁽⁴⁾
Contributions to unconsolidated affiliates	$	—		$	—		$	343		$	36		$	—
Distributions from unconsolidated affiliates	(61		)	(75		)	(68		)	—			—
Share of earnings of unconsolidated affiliates’ net income (loss)	35			42			44			(1		)	(9		)
Amortization of excess fair value of investment ⁽¹⁾	(6		)	—			—			—			—

__________________

(1)

The Partnership’s investment in HPC was adjusted to its fair value on May 26, 2010 and the excess fair value over net book value was comprised of two components: (1) $155 million was attributed to HPC’s long-lived assets and is being amortized as a reduction of income from unconsolidated affiliates over the useful lives of the respective assets, which vary from 15 to 30 years, and (2) $32 million could not be attributed to a specific asset and therefore will not be amortized in future periods.


(2)	The Partnership contributed $175 million to MEP in September 2014 for the repayment of MEP’s debt.

(3)

HPC entered into a $500 million 5-year revolving credit facility in September 2013, pursuant to which the Partnership pledged its 49.99% equity interest in HPC. Upon closing such credit facility, HPC borrowed $370 million to fund a non-recurring return of investment to its partners of which the Partnership received $185 million. The amount outstanding under this facility was $450 million as of December 31, 2014. The Partnership’s contingent obligation with respect to the outstanding borrowings under this facility was $225 million at December 31, 2014.


(4)	Includes Coal Handling, Grey Ranch, and Sweeny JV.

Summarized Financial Information

Consolidated financial statements for HPC, MEP, and Lone Star are filed as exhibits to this Form 10-K. The following tables present aggregated selected balance sheet and income statement data for Ranch JV (on a 100% basis) for all periods presented:



	December 31,
	2014		2013
Current assets	$	16	$	7
Property, plant and equipment, net	95		100
Other assets	4		4
Total assets	$	115	$	111

Current liabilities	$	2	$	3
Equity	113		108
Total liabilities and equity	$	115	$	111



	Years Ended December 31,
	2014		2013		2012
Revenue	$	41	$	16	$	1
Operating income (loss)	29		4		(2		)
Net income (loss)	29		4		(2		)

7. DERIVATIVE INSTRUMENTS

Policies. The Partnership established comprehensive risk management policies and procedures to monitor and manage the market risks associated with commodity prices, counterparty credit and interest rates. The General Partner is responsible for delegation

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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.

The Partnership has swap contracts settled against certain NGLs, condensate and natural gas market prices.

Marketing & Trading. The Partnership conducts natural gas marketing and trading activities 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 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 December 31, 2014, the Partnership had $1.5 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 December 31, 2014 was $82 million, which would be reduced by less than $1 million due to the netting feature. The Partnership has elected to present assets and liabilities under master netting agreements gross on the consolidated balance sheets.

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

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The Partnership’s derivative assets and liabilities, including credit risk adjustments, as of December 31, 2014 and 2013 are detailed below:



	Assets				Liabilities
	December 31,				December 31,
	2014		2013		2014		2013
Derivatives not designated as cash flow hedges
Current amounts
Commodity contracts	$	75	$	3	$	—	$	9
Long-term amounts
Commodity contracts	10		1		—		—
Embedded derivatives in Series A Preferred Units	—		—		16		19
Total derivatives	$	85	$	4	$	16	$	28

The Partnership’s statements of operations for the years ended December 31, 2014, 2013 and 2012 were impacted by derivative instruments activities as detailed below:



		Years Ended December 31,
		2014		2013		2012
Derivatives in cash flow hedging relationships:		Change in Value Recognized in AOCI on Derivatives (Effective Portion)
Commodity derivatives		$	—	$	—	$	(4	)
Derivatives in cash flow hedging relationships:	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
Commodity derivatives	Revenue	$	—	$	—	$	6



		Years Ended December 31,
		2014		2013			2012
Derivatives not designated in a hedging relationship:	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) from De-designation Amortized from AOCI into Income
Commodity derivatives	Revenue	$	—	$	—		$	(5	)
Derivatives not designated in a hedging relationship:	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Recognized in Income from Derivatives
Commodity derivatives	Revenue	$	93	$	(9	)	$	16
Embedded derivatives	Other income & deductions	3		6			14
		$	96	$	(3	)	$	30

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8. LONG-TERM DEBT

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



	December 31,
	2014			2013
Senior notes	$	5,089		$	2,800
Revolving loans	1,504			510
Unamortized premiums and discounts	48			—
Long-term debt	$	6,641		$	3,310
Availability under revolving credit facility:
Total credit facility limit	$	2,000		$	1,200
Revolving loans	(1,504		)	(510		)
Letters of credit	(23		)	(14		)
Total available	$	473		$	676

Long-term debt maturities as of December 31, 2014 for each of the next five years are as follows:



Year Ended December 31,	Amount
2015	$	—
2016	—
2017	—
2018	—
2019	2,003
Thereafter	4,590
Total *	$	6,593


*	Excludes a $67 million unamortized premium on the 2020 PVR Notes and the 2021 PVR Notes assumed by the Partnership and a $19 million unamortized discount on the combined 2022 Notes.

Revolving Credit Facility

In the years ended December 31, 2014, 2013 and 2012 the Partnership borrowed $3.86 billion, $1.83 billion and $1.56 billion, respectively, under its revolving credit facility; these borrowings were to fund capital expenditures and acquisitions. During the same periods, the Partnership repaid $3.48 billion, $1.52 billion and $1.70 billion, respectively, with proceeds from equity offerings and issuances of senior notes.

In February 2014, RGS entered into the First Amendment (the "First Amendment") to the Sixth Amended and Restated Credit Agreement (the “Credit Agreement”) to, among other things, expressly permit the pending PVR and Eagle Rock Midstream acquisitions, and to increase the commitment base to $1.5 billion and increase the uncommitted incremental facility to $500 million. The First Amendment allowed the Partnership to assume the legacy PVR senior notes that mature prior to the 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 of credit in excess of $25 million; increase in the general basket of permitted investments from $300 million to $500 million; add provisions permitting investments in ORS, affording it similar treatment to the Partnership’s existing joint ventures; and update various swap agreement provisions to conform to current market standards.

In November 2014, RGS entered into the Seventh Amended and Restated Credit Agreement (the "New Credit Agreement") to increase the commitment to $2 billion and extended the maturity date to November 25, 2019. The material differences between the Credit Agreement and the New Credit Agreement include:


•	the addition of provisions permitting investments in Mi Vida JV affording it similar treatment to the Partnership’s existing joint ventures;


•	an increase in certain permitted covenant baskets; and


•	updates to various pricing terms and the permitted maximum total leverage ratio to reflect the Partnership’s growth.

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In connection with the New Credit Agreement, the Partnership capitalized $5 million of net loan fees related to the amendments completed in the year ended December 31, 2014, which are being amortized over the remaining term.

In May 2013, RGS entered into the Credit Agreement to increase the commitment to $1.2 billion with a $300 million uncommitted incremental facility and extended the maturity date to May 21, 2018. The material differences between the Fifth Amended and Restated Credit Agreement and the Credit Agreement include:


•	A 75 bps decrease in pricing, with an additional 50 bps decrease upon the achievement of an investment grade rating;


•	No limitation on the maximum amount that the loan parties may invest in joint ventures existing on the date of the credit agreement so long as the Partnership is in pro forma compliance with the financial covenants;


•	The addition of a “Restricted Subsidiary” structure such that certain designated subsidiaries are not subject to the credit facility covenants and do not guarantee the obligations thereunder or pledge their assets in support thereof;


•	The addition of provisions such that upon the achievement of an investment grade rating by the Partnership, the collateral package will be released; the facility will become unsecured; and the covenant package will be significantly reduced;


•	An eight-quarter increase in the permitted Total Leverage Ratio; and


•	After March 2015, an increase in the permitted total leverage ratio for the two fiscal quarters following any $50 million or greater acquisition.

In connection with the Credit Agreement, the Partnership capitalized $6 million of net loan fees related to this amendment which are being amortized over the remaining term.

Borrowings under the New Credit Agreement are secured by substantially all of the Partnership’s assets and are guaranteed by the Partnership and its consolidated subsidiaries, except for ELG and ORS. The New Credit Agreement and the guarantees thereunder are senior to the Partnership’s and the guarantors’ unsecured obligations.

The outstanding balance under the New Credit Agreement bears interest at LIBOR plus a margin or alternate base rate (equivalent to the U.S. prime lending rate) plus a margin, or a combination of both. The alternate base rate used to calculate interest on base rate loans will be calculated based on the greatest to occur of a base rate, a federal funds effective rate plus 0.50% and an adjusted one-month LIBOR rate plus 1.00%. The applicable margin shall range from 0.50% to 1.25% for base rate loans, 1.50% to 2.25% for Eurodollar loans. The weighted average interest rate on the amounts outstanding under the Partnership’s Credit Agreement was 2.17% as of December 31, 2014 and 2013.

RGS must pay (i) a commitment fee ranging from 0.25% to 0.375% per annum of the unused portion of the revolving loan commitments, (ii) a participation fee for each revolving lender participating in letters of credit ranging from 1.5% to 2.25% per annum of the average daily amount of such lender’s letter of credit exposure and (iii) a fronting fee to the issuing bank of letters of credit equal to 0.20% per annum of the average daily amount of the letter of credit exposure. These fees are included in interest expense, net in the consolidated statement of operations.

The New Credit Agreement contains financial covenants requiring RGS and its subsidiaries to maintain a debt to consolidated EBITDA (as defined in the credit agreement) ratio less than 5.50, a consolidated EBITDA to consolidated interest expense ratio greater than 2.50 and a secured debt to consolidated EBITDA ratio less than 3.25. At December 31, 2014 and 2013, RGS and its subsidiaries were in compliance with these covenants.

The New Credit Agreement restricts the ability of RGS to pay dividends and distributions other than reimbursements to the Partnership for expenses and payment of dividends to the Partnership for the amount of available cash (as defined) so long as no default or event of default has occurred or is continuing. The New Credit Agreement also contains various covenants that limit (subject to certain exceptions), among other things, the ability of RGS to:


•	incur indebtedness;


•	grant liens;


•	enter into sale and leaseback transactions;


•	make certain investments, loans and advances;


•	dissolve or enter into a merger or consolidation;


•	enter into asset sales or make acquisitions;


•	enter into transactions with affiliates;


•	prepay other indebtedness or amend organizational documents or transactions documents (as defined in the New Credit Agreement);


•	issue capital stock or create subsidiaries; or


•	engage in any business other than those businesses in which it was engaged at the time of the effectiveness of the New Credit Agreement or reasonable extension thereof.

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In February 2015, RGS exercised the accordion feature of the New Credit Agreement to increase commitments under the revolving credit facility by $500 million to a total of $2.5 billion. The increased commitments will be available pursuant to the same terms and subject to the same interest rates and fees as the existing commitments under the New Credit Agreement.

Senior Notes

The Partnership and Finance Corp. have the following series of senior notes (collectively “Senior Notes”):


•	$400 million in aggregate principal amount of our 5.75% senior notes due September 1, 2020 (the “2020 Notes“) with interest payable semi-annually in arrears on March 1 and September 1;


•	$500 million in aggregate principal amount of our 6.5% senior notes due July 15, 2021 (the “2021 Notes“) with interest payable semi-annually in arrears on January 15 and July 15;


•	$900 million in aggregate principal of our 5.875% senior notes due March 1, 2022 (the “2022 Notes“), issued in February 2014, with interest payable semi-annually in arrears on March 1 and September 1;


•	$700 million in aggregate principal amount of our 5.5% senior notes due April 15, 2023 (the “2023 5.5% Notes“) with interest payable semi-annually in arrears on April 15 and October 15;


•	$600 million in aggregate principal amount of our 4.5% senior notes due November 1, 2023 (the “2023 4.5% Notes“) with interest payable semi-annually in arrears on May 1 and November 1;


•	$390 million, after partial redemption, in aggregate principal amount of our 8.375% senior notes due June 1, 2020 (the “2020 PVR Notes“) with interest payable semi-annually in arrears on June 1 and December 1;


•	$400 million in aggregate principal amount of our 6.5% senior notes due May 15, 2021 (the “2021 PVR Notes“) with interest payable semi-annually in arrears on May 15 and November 15;


•	$499 million in aggregate principal amount of our 8.375% senior notes due June 1, 2019 (the “2019 Notes“) with interest payable semi-annually in arrears on June 1 and December 1; and


•	$700 million in aggregate principal amount of our 5% senior notes due October 1, 2022 (the “October 2022 Notes“) with interest payable semi-annually in arrears on April 1 and October 1.

In May 2009, the Partnership and Finance Corp. issued $250 million of senior notes with a maturity of June 1, 2016 (the “2016 Notes”). The 2016 Notes bore interest at 9.375% with interest payable semi-annually in arrears on June 1 and December 1. In May 2012, the Partnership redeemed 35%, or $88 million, of the 2016 Notes, bringing the total outstanding principal amount to $163 million. A redemption premium of $8 million was charged to loss on debt refinancing, net in the consolidated statements of operations and $4 million of accrued interest was paid. The Partnership also wrote off the unamortized loan fee of $1 million and unamortized bond premium of $2 million to loss on debt refinancing, net in the consolidated statement of operations. In June 2013, the Partnership redeemed all amounts outstanding 2016 Notes for $178 million cash, inclusive of accrued and unpaid interest of $7 million and other fees and expenses.

In February 2014, the Partnership and Finance Corp. issued $900 million of senior notes that mature on March 1, 2022 (the “2022 Notes”). The 2022 Notes bear interest at 5.875% with interest payable semi-annually in arrears on September 1 and March 1. At any time prior to December 1, 2021, 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 December 1, 2021, the Partnership may redeem some or all of the 2022 Notes at a redemption price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date. The 2022 Notes rank equally with the Partnership’s other Senior Notes.

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”, and together with the 2021 PVR Notes, the "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. The PVR Notes rank equally with the Partnership’s other Senior Notes.

On March 24, 2014, in accordance with the Partnership’s obligations under the indentures governing the PVR Notes, the Partnership commenced change of control offers pursuant to which holders of such notes were entitled to require the Partnership to repurchase all or a portion of its PVR 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 PVR Notes expired on April 22, 2014 and, on April 23, 2014, the Partnership accepted for purchase less than $1 million in aggregate principal amount of 2021 PVR Notes.

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In July 2014, in connection with the Eagle Rock Midstream Acquisition, the Partnership exchanged $499 million of 8.375% Senior Notes due 2019 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 rank equally with the Partnership’s other 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 October 2022 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 October 2022 Notes at a redemption price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date. The October 2022 Notes rank equally with the Partnership’s other 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.

In December 2014, the Partnership redeemed all of the outstanding $600 million 2018 Notes, for a total price of 103.438% or $621 million.

The Senior Notes issued by the Partnership and Finance Corp. are fully and unconditionally guaranteed, on a joint and several

basis, by all of the Partnership’s consolidated subsidiaries, except for ELG and ORS.

The Senior Notes are redeemable at any time prior to the dates specified below at a price equal to 100% of the principal amount of the applicable series, plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date:


•	2020 Notes - Redeemable, in whole or in part, prior to June 1, 2020 at 100% of the principal amount plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date; redeemable, in whole or in part, on or after June 1, 2020 at 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date


•	2021 Notes - Any time prior to July 15, 2014, up to 35% may be redeemed at a price of 106.5% plus accrued and unpaid interest, if any; beginning July 15, 2016, 100% may be redeemed at fixed redemption price of 103.25% (July 15, 2017 - 102.167%, July 15, 2018 - 101.083% and July 15, 2019 and thereafter - 100%) plus accrued and unpaid interest, if any, to the redemption date


•	2022 Notes - Redeemable, in whole or in part, prior to December 1, 2021 at 100% at the principal amount plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date; redeemable, in whole or in part, on or after December 1, 2021 at 100% at the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date


•	2023 5.5% Notes - Any time prior to October 15, 2015, up to 35% may be redeemed at a price of 105.5% plus accrued and unpaid interest, if any; beginning October 15, 2017, 100% may be redeemed at fixed redemption price of 102.75% (October 15, 2018 - 101.833%, October 15, 2019 - 100.917% and October 15, 2020 and thereafter - 100%) plus accrued and unpaid interest, if any, to the redemption date


•	2023 4.5% Notes - Redeemable, in whole or in part, prior to August 1, 2023 at 100% of the principal amount plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date; redeemable, in whole or in part, on or after August 1, 2023 at 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date


•	2020 PVR Notes - Any time prior to June 1, 2015, up to 35% may be redeemed at a price of 108.375% plus accrued and unpaid interest, if any; beginning June 1, 2016, 100% may be redeemed at fixed redemption price of 104.188% (June 1, 2017 - 102.094%, June 1, 2018 and thereafter - 100%) plus accrued and unpaid interest, if any, to the redemption date

•

2021 PVR Notes - Any time prior to May 15, 2016, up to 35% may be redeemed at a price of 106.5% plus accrued and unpaid interest and liquidated damages, if any; beginning May 15, 2016, 100% may be redeemed at a fixed redemption price of 104.875% (May 15, 2017 - 103.250%, May 15, 2018 - 101.625% and May 15, 2019 and thereafter - 100%) plus accrued and unpaid interest, if any, to the redemption date

•

2019 Notes - Redeemable, in whole or in part, prior to June 1, 2015 at 100% at the principal amount plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date; beginning June 1, 2015, 100% may be redeemed at a fixed redemption price of 104.188% (June 1, 2016 - 102.094% and June 1, 2017 and thereafter - 100%) plus accrued and unpaid interest, if any, to the redemption date


•	October 2022 Notes - Redeemable, in whole or in part, prior to July 1, 2022 at 100% of the principal amount plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date; redeemable, in whole or in part, on or

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after July 1, 2022 at 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date

Upon a change of control followed by a ratings downgrade within 90 days of a change of control, each holder of the Partnership’s Senior Notes, other than the PVR Notes, will be entitled to require the Partnership to repurchase all or a portion of its notes at a purchase price of 101% plus accrued and unpaid interest, if any. Upon a change of control, the indenture governing the PVR Notes requires the Partnership to make an offer to repurchase all outstanding notes at 101% of the principal amount thereof, plus accrued and unpaid interest (and additional interest, if any) to the date of repurchase. The Partnership’s ability to repurchase the Senior Notes upon a change of control will be limited by the terms of our debt agreements, including the Partnership’s revolving credit facility.

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


•	incur additional indebtedness;


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


•	make certain investments;


•	incur liens;


•	enter into certain types of transactions with affiliates; and


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

If the Senior Notes achieve investment grade ratings by both Moody’s and Standard & Poor’s and no default or event of default has occurred and is continuing, the Partnership will no longer be subject to many of the foregoing covenants. At December 31, 2014, the Partnership was in compliance with these covenants.

9. INTANGIBLE ASSETS

Activity related to intangible assets, net consisted of the following:



	Customer Relations			Trade Names			Total
Balance at January 1, 2013	$	655		$	57		$	712
Amortization	(26		)	(4		)	(30		)
Balance at December 31, 2013	629			53			682
Amortization	(105		)	(3		)	(108		)
Intangible assets acquired	2,865			—			2,865
Balance at December 31, 2014	$	3,389		$	50		$	3,439

The average remaining amortization periods for customer relations and trade names are 28 and 15 years, respectively. The expected amortization of the intangible assets for each of the five succeeding years is $135 million.

10. FAIR VALUE MEASURES

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


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


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


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

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

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

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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.

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



	Fair Value Measurement at December 31,
	2014						2013
	Fair Value Total		Level 2		Level 3		Fair Value Total		Level 2		Level 3
Assets
Commodity Derivatives:
Natural Gas	$	26	$	26	$	—	$	2	$	2	$	—
Natural Gas Liquids	23		23		—		2		2		—
Condensate	36		36		—		—		—		—
Total Assets	$	85	$	85	$	—	$	4	$	4	$	—
Liabilities
Commodity Derivatives:
Natural Gas	$	—	$	—	$	—	$	4	$	4	$	—
Natural Gas Liquids	—		—		—		4		4		—
Condensate	—		—		—		1		1		—
Embedded Derivatives in Series A Preferred Units	16		—		16		19		—		19
Total Liabilities	$	16	$	—	$	16	$	28	$	9	$	19

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	December 31, 2014
Credit Spread	4.76	%
Volatility	35.8	%

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 following table presents the changes in Level 3 derivatives measured on a recurring basis for the years ended December 31, 2014 and 2013. There were no transfers between Level 2 and Level 3 derivatives for the years ended December 31, 2014 and 2013.



	Embedded Derivatives in Series A Preferred Units
Balance at January 1, 2013	$	25
Change in fair value, net of gain at conversion of $26 million	(6		)
Balance at December 31, 2013	19
Change in fair value	(3		)
Balance at December 31, 2014	$	16

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 December 31, 2014 and 2013 was $5.1 billion and $2.8 billion, respectively. The fair value of the Senior Notes is a Level 1 valuation based on third party market value quotations.

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11. LEASES

The following table is a schedule of future minimum lease payments for office space and certain equipment leased by the Partnership, that had initial or remaining non-cancelable lease terms in excess of one year as of December 31, 2014:



For the year ending December 31,	Operating Lease
2015	$	5
2016	5
2017	4
2018	3
2019	2
Thereafter	26
Total minimum lease payments	$	45

Total rent expense for operating leases, including those leases with terms of less than one year, was $20 million, $11 million and $11 million for the years ended December 31, 2014, 2013 and 2012, respectively.

12. 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.

ETP Merger Shareholder Litigation. Following the January 26, 2015 announcement of the definitive merger agreement with ETP, purported Partnership unitholders filed lawsuits in state and federal courts in Dallas, Texas asserting claims relating to the proposed transaction.

On February 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 unfair process and failing to maximize the merger consideration; (2) the General Partner’s directors breached the implied covenant of good faith and fair dealing by engaging in a flawed merger process; and (3) the non-director defendants aided and abetted in these claimed breaches. The plaintiffs seek an injunction preventing the defendants from closing the proposed transaction or an order rescinding the transaction if it has already been completed. The plaintiffs also seek money damages and court costs, including attorney’s fees.

On February 9, 2015, Stuart Yeager, a purported Partnership unitholder, filed a class action petition on behalf of the Partnership’s common unitholders and a derivative suit on behalf of the Partnership in the 134th Judicial District Court of Dallas County, Texas (the “Yeager Lawsuit”). The allegations, claims, and relief sought in the Yeager Lawsuit are nearly identical to those in the Engel Lawsuit.

On February 10, 2015, Lucien Coggia a purported Partnership unitholder, filed a class action petition on behalf of the Partnership’s common unitholders and a derivative suit on behalf of the Partnership in the 192nd Judicial District Court of Dallas County, Texas (the “Coggia Lawsuit”). The allegations, claims, and relief sought in the Coggia Lawsuit are nearly identical to those in the Engel Lawsuit.

On February 3, 2015, Linda Blankman, 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 “Blankman Lawsuit”). The allegations and claims in the Blankman Lawsuit are similar to those in the Engel Lawsuit. However, the Blankman Lawsuit does not allege any derivative claims and includes the Partnership as a defendant rather than a nominal party. The lawsuit also omits one of the General Partner’s directors, Richard Brannon, who was named in the Engel Lawsuit. The Blankman Lawsuit alleges that the General Partner’s directors breached their fiduciary duties to the unitholders by failing to maximize the value of the Partnership, failing to properly value the Partnership, and ignoring conflicts of interest. The plaintiff also asserts a claim against the non-director defendants for aiding and abetting the directors’ alleged breach of fiduciary duty. The Blankman Lawsuit seeks the same relief that the plaintiffs seek in the Engel Lawsuit.

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On February 6, 2015, Edwin Bazini, 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 “Bazini Lawsuit”). The allegations, claims, and relief sought in the Bazini Lawsuit are nearly identical to those in the Blankman Lawsuit.

On February 11, 2015, Mark Hinnau, 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 “Hinnau Lawsuit”). The allegations, claims, and relief sought in the Hinnau Lawsuit are nearly identical to those in the Blankman Lawsuit.

On February 11, 2015, Stephen Weaver, 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 “Weaver Lawsuit”). The allegations, claims, and relief sought in the Weaver Lawsuit are nearly identical to those in the Blankman Lawsuit.

On February 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.

Each of these lawsuits is at a preliminary stage. We 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.

PVR Shareholder Litigation. Five putative class action lawsuits challenging the PVR Acquisition are currently pending. All of the cases name PVR, PVR GP and the then-incumbent directors of PVR GP, as well as the Partnership and the General Partner (collectively, the “Regency Defendants”), as defendants. Each of the lawsuits has been brought by a purported unitholder of PVR, both individually and on behalf of a putative class consisting of public unitholders of 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 alleged breach of these fiduciary duties, and, as to the actions in federal court, 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, (i) injunctive relief, (ii) disclosure of certain additional information concerning the transaction, (iii) 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 deems just and proper. The styles of the pending cases are as follows: David Naiditch v. PVR Partners, L.P., et al. in the Court of Chancery of the State of Delaware); Charles Monatt v. PVR Partners, LP, et al. and Saul Srour v. PVR Partners, L.P., et al., each pending in the Court of Common Pleas for Delaware County, Pennsylvania; Stephen Bushansky v. PVR Partners, L.P., et al.; and Mark Hinnau v. PVR Partners, L.P., et al., pending in the United States District Court for the Eastern District of Pennsylvania.

On January 28, 2014, the defendants entered into a Memorandum of Understanding (“MOU”) with Monatt, Srour, Bushansky, Naiditch and Hinnau pursuant to which defendants and the referenced plaintiffs agreed in principle to a settlement of their lawsuits (“Settled Lawsuits”), which will be memorialized in a separate settlement agreement, subject to customary conditions, including consummation of the PVR Acquisition, which occurred on March 21, 2014, completion of certain confirmatory discovery (which was completed as of September 5, 2014), class certification and final approval by the Court of Common Pleas for Delaware County, Pennsylvania. If the Court approves the settlement, the Settled Lawsuits will be dismissed with prejudice and all defendants will be released from any and all claims relating to the Settled Lawsuits.

The settlement did not affect any provisions of the merger agreement or the form or amount of consideration received by PVR unitholders in the PVR Acquisition. The defendants have denied and continue to deny any wrongdoing or liability with respect to the plaintiffs’ claims in the aforementioned litigation and have entered into the settlement to eliminate the uncertainty, burden, risk, expense, and distraction of further litigation.

Eagle Rock Shareholder Litigation. Three putative class action lawsuits challenging the Eagle Rock Midstream Acquisition were previously filed in federal district court in Houston, Texas. All cases name Eagle Rock and its current directors, as well as the Partnership and a subsidiary, as defendants. One of the lawsuits also names additional Eagle Rock entities as defendants. Each of the lawsuits has been brought by a purported unitholder of Eagle Rock (collectively, the “Plaintiffs”), 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,

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claiming, among other things, that it yields inadequate consideration, was tainted by conflict and constitutes breaches of common law fiduciary duties or contractually imposed duties to the shareholders. Plaintiffs also seek monetary damages and attorneys’ fees. The Partnership and its subsidiary are named as “aiders and abettors” of the allegedly wrongful actions of Eagle Rock and its board. In November 2014, the US District Court issued a Notice of Voluntary Dismissal without Prejudice of all claims in this matter.

PADEP Consent Assessment. On November 21, 2014, our subsidiary, Regency Marcellus Gas Gathering LLC (“Regency Marcellus”), received a Notice of Violation (“NOV”) from the Pennsylvania Department of Environmental Protection (“PADEP”) relating to unpermitted wetlands and streams along the second phase of construction of the Canton Pipeline Project with proposed civil penalties potentially in excess of $100,000. Regency Marcellus has submitted amended permit applications for this phase of construction and is working with the PADEP to acquire amended permits for the proposed crossings of the wetland resources. Regency Marcellus is in discussions with the PADEP regarding the aforementioned NOV. The timing or outcome of this matter cannot reasonably be determined at this time, however we do not expect there to be a material impact on our business or results of operations.

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.

Environmental. The Partnership is responsible for environmental remediation at certain sites on its gathering and processing systems, resulting primarily from releases of hydrocarbons. The Partnership’s remediation program typically involves the management of contaminated soils and may involve remediation of groundwater. Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements and complexity. The ultimate liability and total costs associated with these sites will depend upon many factors. In addition, the Partnership has reclamation and bonding requirements with respect to certain un-leased and inactive coal properties.

The table below reflects the undiscounted environmental liabilities recorded in the consolidated balance sheet at December 31, 2014 and 2013 where management believes a loss is probable and reasonably estimable. The Partnership does not have any material environmental remediation matters assessed as reasonably possible that would require disclosure in the financial statements.



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

The Partnership made expenditures related to environmental remediation of $2 million for the year ended December 31, 2014.

Air Quality Control. The Partnership is currently negotiating settlements to certain enforcement actions by the NMED and the TCEQ. The TCEQ recently initiated a state-wide emissions inventory for the sulfur dioxide emissions from sites with reported emissions of 10 tons per year or more. If this data demonstrates that any source or 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 will address the sulfur dioxide standard.

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 May 2015 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.

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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.

In addition to 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.

13. SERIES A PREFERRED UNITS

On September 2, 2009, the Partnership issued 4,371,586 Series A Preferred Units for net proceeds of $79 million, inclusive of the General Partner’s contribution of $2 million.

Holders may elect to convert Series A Preferred Units to common units at any time. In July 2013, certain holders of Series A Preferred Units exercised their right to convert 2,459,017 Series A Preferred Units into common units. Concurrent with this transaction, the Partnership recognized a $26 million gain in other income and deductions, net, related to the embedded derivative and reclassified $41 million from the Series A Preferred Units into common units. As of December 31, 2014, the remaining Series A Preferred Units were convertible into 2,064,805 common units, and if outstanding, are mandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon (the “Series A Liquidation Value”). The Series A Preferred Units receive fixed quarterly cash distributions of $0.445 per unit if outstanding on the record dates of the Partnership’s common unit distributions.

Distributions on the Series A Preferred Units were accrued for the first two quarters (and not paid in cash) and will result in an increase in the number of common units issuable upon conversion. If on any distribution payment date beginning March 31, 2010, the Partnership (1) fails to pay distributions on the Series A Preferred Units, (2) reduces the distributions on the common units to zero and (3) is prohibited by its material financing agreements from paying cash distributions, such distributions shall automatically accrue and accumulate until paid in cash. If the Partnership has failed to pay cash distributions in full for two quarters (whether or not consecutive) from and including the quarter ended on March 31, 2010, then if the Partnership fails to pay cash distributions on the Series A Preferred Units, all future distributions on the Series A Preferred Units that are accrued rather than being paid in cash by the Partnership will consist of the following: (1) $0.35375 per Series A Preferred Unit per quarter, (2) $0.09125 per Series A Preferred Unit per quarter (the “Common Unit Distribution Amount”), payable solely in common units, and (3) $0.09125 per Series A Preferred Unit per quarter (the “PIK Distribution Additional Amount”), payable solely in common units. The total number of common units payable in connection with the Common Unit Distribution Amount or the PIK Distribution Additional Amount cannot exceed $2 million in any period of 20 consecutive fiscal quarters.

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

The Series A Preferred Units are convertible, at the holder’s option, into common units, provided that the holder must request conversion of at least 375,000 Series A Preferred Units. The conversion price will initially be $18.30, subject to adjustment for customary events (such as unit splits). The number of common units issuable is equal to the issue price of the Series A Preferred Units (i.e. $18.30) being converted plus all accrued but unpaid distributions and accrued but unpaid interest thereon (the “Redeemable Face Amount”), divided by the applicable conversion price.

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

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

In the event of a change of control, the Partnership will be required to make an offer to the holders of the Series A Preferred Units to purchase their Series A Preferred Units for an amount equal to 101% of their Series A Liquidation Value. In addition, in the event of certain business combinations or other transactions involving the Partnership in which the holders of common units receive cash consideration exclusively in exchange for their common units (a “Cash Event”), the Partnership must use commercially reasonable efforts to ensure that the holders of the Series A Preferred Units will be entitled to receive a security issued by the surviving entity in the Cash Event with comparable powers, preferences and rights to the Series A Preferred Units. If the Partnership

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is unable to ensure that the holders of the Series A Preferred Units will be entitled to receive such a security, then the Partnership will be required to make an offer to the holders of the Series A Preferred Units to purchase their Series A Preferred Units for an amount equal to 120% of their Series A Liquidation Value. If the Partnership enters into any recapitalization, reorganization, consolidation, merger, spin-off that is not a Cash Event, the Partnership will make appropriate provisions to ensure that the holders of the Series A Preferred Units receive a security with comparable powers, preferences and rights to the Series A Preferred Units upon consummation of such transaction. Subsequent to the ETE Acquisition, no unitholder exercised this option.

As of December 31, 2014, the Series A Preferred Units were convertible to 2,064,805 common units.

The following table provides a reconciliation of the beginning and ending balances of the Series A Preferred Units for the years ended December 31, 2014 and 2013:



	Units		Amount
Balance at January 1, 2013	4,371,586		$	73
Series A Preferred Units converted to common units	(2,459,017	)	(41		)
Balance at January 1, 2014	1,912,569		32
Accretion to redemption value	N/A		1
Balance at December 31, 2014	1,912,569		$	33		*

* This amount will be accreted to $35 million plus any accrued but unpaid distributions and interest by deducting amounts from

partners’ capital over the remaining periods until the mandatory redemption date of September 2, 2029. Accretion during 2013

was immaterial.

14. RELATED PARTY TRANSACTIONS

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



	December 31,
	2014		2013
Related party receivables
ETE and its subsidiaries	43		25
HPC	1		1
Ranch JV	1		2
Total related party receivables	$	45	$	28

Related party payables
ETE and its subsidiaries	50		68
HPC	3		1
Mi Vida JV	11		—
Total related party payables	$	64	$	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 services 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 Partnership incurred total service fees related to the agreements described above from ETE and its subsidiaries of $6 million, $11 million and $17 million for the years ended December 31, 2014, 2013 and 2012, respectively.

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In conjunction with distributions made by the Partnership to the limited and general partner interests, ETE and its subsidiaries received cash distributions of $175 million, $107 million and $62 million for the years ended December 31, 2014, 2013 and 2012, respectively.

The General Partner has the right, but not the obligation, to contribute a proportionate amount of capital to the Partnership to maintain its general partner interest. No capital contributions were contributed during the years ended December 31, 2014 and 2013.

The Partnership’s Gathering and Processing segment, in the ordinary course of business, sells natural gas and NGLs to subsidiaries of ETE and records the revenue in gas sales and NGL sales. The Partnership’s Contract Services segment provides contract compression services to a subsidiary of ETE and records revenue in gathering, transportation and other fees on the statement of operations. As these transactions are between entities under common control, partners’ capital was increased, which represented a deemed contribution of the excess sales price over the carrying amounts. The Partnership’s Gathering and Processing segment recorded revenues from subsidiaries of ETE of $351 million and cost of sales to subsidiaries of ETE of $52 million for the year ended December 31, 2014. The Partnership’s Contract Services segment recorded revenues from a subsidiary of ETE of $1 million for the year ended December 31, 2014. The Partnership’s Contract Services segment purchased $67 million and $95 million of compression equipment from a subsidiary of ETE during the years ended December 31, 2014 and 2013, respectively.

Prior 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. The amounts were $21 million and $1 million for the period from March 26, 2012 to December 31, 2012. These administrative services were no longer being provided subsequent to the SUGS Acquisition.

Transactions with Lone Star. The Partnership entered into various agreements to sell NGLs to Lone Star. For the year ended December 31, 2014, the Partnership had recorded $257 million in NGL sales under these contracts.

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. For the years ended December 31, 2014, 2013, and 2012, the related party general and administrative expenses reimbursed to the Partnership were $14 million, $18 million, and $20 million, respectively, which is recorded in gathering, transportation and other fees.

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

15. CONCENTRATION RISK

The following table provides information about the extent of reliance on major customers and gas suppliers. Total revenues and cost of sales from transactions with an external customer or supplier amounting to 10% or more of revenue or cost of gas and liquids are disclosed below, together with the identity of the reportable segment.



		Years Ended December 31,
	Reportable Segment	2014		2013		2012
Customer
Customer A	Gathering and Processing	$	—	$	381	$	367
Customer B	Gathering and Processing	780		362		451
Supplier
Supplier A	Gathering and Processing	—		164		171
Supplier B	Gathering and Processing	—		185		—

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

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16. 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, the Partnership’s 75% membership interest in ORS, which will operate a natural gas gathering system in the Utica shale in Ohio, and the Partnership’s 50% interest in Mi Vida JV, which will operate a cryogenic processing plant and related 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 included the Partnership’s 50% interest in Coal Handling, which owns and operates end-user coal handling facilities. The Partnership purchased the remaining 50% interest in these companies effective December 31, 2014.


•	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.

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



	Years Ended December 31,
	2014			2013			2012
External Revenue
Gathering and Processing	$	4,570		$	2,287		$	1,797
Natural Gas Transportation	—			1			1
NGL Services	—			—			—
Contract Services	307			215			183
Natural Resources	58			—			—
Corporate	16			18			19
Eliminations	—			—			—
Total	$	4,951		$	2,521		$	2,000

Intersegment Revenue
Gathering and Processing	$	—		$	—		$	—
Natural Gas Transportation	—			—			—
NGL Services	—			—			—
Contract Services	14			15			21
Natural Resources	—			—			—
Corporate	—			—			—
Eliminations	(14		)	(15		)	(21		)
Total	$	—		$	—		$	—

Cost of Sales
Gathering and Processing	$	3,381		$	1,767		$	1,373
Natural Gas Transportation	—			—			(1		)
NGL Services	—			—			—
Contract Services	67			26			15
Natural Resources	—			—			—
Corporate	4			—			—
Eliminations	—			—			—
Total	$	3,452		$	1,793		$	1,387

Segment Margin
Gathering and Processing	$	1,189		$	520		$	423
Natural Gas Transportation	—			1			2
NGL Services	—			—			—
Contract Services	254			204			189
Natural Resources	58			—			—
Corporate	12			18			20
Eliminations	(14		)	(15		)	(21		)
Total	$	1,499		$	728		$	613

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	Years Ended December 31,
	2014			2013			2012
Operation and Maintenance
Gathering and Processing	$	360		$	237		$	183
Natural Gas Transportation	—			—			—
NGL Services	—			—			—
Contract Services	86			72			66
Natural Resources	12			—			—
Corporate	3			1			—
Eliminations	(13		)	(14		)	(21		)
Total	$	448		$	296		$	228

Depreciation, Depletion and Amortization
Gathering and Processing	$	385		$	186		$	159
Natural Gas Transportation	—			—			—
NGL Services	—			—			—
Contract Services	134			98			86
Natural Resources	14			—			—
Corporate	8			3			7
Eliminations	—			—			—
Total	$	541		$	287		$	252



Income from Unconsolidated Affiliates
Gathering and Processing	$	5	$	1	$	(10	)
Natural Gas Transportation	72		70		71
NGL Services	116		64		44
Contract Services	—		—		—
Natural Resources	2		—		—
Corporate	—		—		—
Eliminations	—		—		—
Total	$	195	$	135	$	105

Expenditures for Long-Lived Assets
Gathering and Processing	$	700	$	721	$	395
Natural Gas Transportation	—		—		—
NGL Services	—		—		—
Contract Services	371		311		164
Natural Resources	—		—		—
Corporate	17		2		1
Eliminations	—		—		—
Total	$	1,088	$	1,034	$	560

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	December 31,
	2014		2013		2012
Assets
Gathering and Processing	$	12,069	$	4,748	$	4,210
Natural Gas Transportation	1,119		991		1,232
NGL Services	1,162		1,070		948
Contract Services	2,035		1,897		1,672
Natural Resources	529		—		—
Corporate	189		76		61
Eliminations	—		—		—
Total	$	17,103	$	8,782	$	8,123

Investments in Unconsolidated Affiliates
Gathering and Processing	$	139	$	36	$	35
Natural Gas Transportation	1,117		991		1,231
NGL Services	1,162		1,070		948
Contract Services	—		—		—
Natural Resources	—		—		—
Corporate	—		—		—
Eliminations	—		—		—
Total	$	2,418	$	2,097	$	2,214

Goodwill
Gathering and Processing ⁽¹⁾	$	732	$	651	$	651
Natural Gas Transportation	—		—		—
NGL Services	—		—		—
Contract Services	476		477		477
Natural Resources	15		—		—
Corporate	—		—		—
Eliminations	—		—		—
Total	$	1,223	$	1,128	$	1,128

(1) In 2014, the Partnership recorded a $370 million impairment charge at the Permian reporting unit within this segment.

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



	Years Ended December 31,
	2014			2013			2012
Total segment margin	$	1,499		$	728		$	613
Operation and maintenance	(448		)	(296		)	(228		)
General and administrative	(158		)	(88		)	(100		)
Gain (loss) on assets sales, net	1			(2		)	(3		)
Depreciation, depletion and amortization	(541		)	(287		)	(252		)
Goodwill impairment	(370		)	—			—
Income from unconsolidated affiliates	195			135			105
Interest expense, net	(304		)	(164		)	(122		)
Loss on debt refinancing, net	(25		)	(7		)	(8		)
Other income and deductions, net	12			7			29			*
(Loss) income before income taxes	$	(139	)	$	26		$	34

__________________


*	Other income and deductions, net for the year ended December 31, 2012, included a one-time producer payment of $16 million related to an assignment of certain contracts.

17. EQUITY-BASED COMPENSATION

In December 2011, the Partnership’s unitholders approved the Regency Energy Partners LP 2011 Long-Term Incentive Plan (the “2011 Incentive Plan”), which provides for awards of options to purchase the Partnership’s common units; awards of the Partnership’s restricted units, phantom units and common units; awards of distribution equivalent rights; awards of common unit appreciation rights; and other unit-based awards to employees, directors and consultants of the Partnership and its affiliates and subsidiaries. The 2011 Incentive Plan will be administered by the Compensation Committee of the board of directors, which may, in its sole discretion, delegate its powers and duties under the 2011 Incentive Plan to the Chief Executive Officer. Up to 3,000,000 of the Partnership’s common units may be granted as awards under the 2011 Incentive Plan, with such amount subject to adjustment as provided for under the terms of the 2011 Incentive Plan.

The 2011 Incentive Plan may be amended or terminated at any time by the board of directors or the Compensation Committee without the consent of any participant or unitholder, including an amendment to increase the number of common units available for awards under the plan; however, any material amendment, such as a change in the types of awards available under the plan, would require the approval of the unitholders of the Partnership. The Compensation Committee is also authorized to make adjustments in the terms and conditions of, and the criteria included in awards under the 2011 Incentive Plan in specified circumstances. The 2011 Incentive Plan is effective until December 19, 2021 or, if earlier, the time at which all available units under the 2011 Incentive Plan have been issued to participants or the time of termination of the plan by the board of directors.

Unit-based compensation expense of $10 million, $7 million, and $5 million is recorded in general and administrative expense in the statement of operations for the years ended December 31, 2014, 2013 and 2012, respectively.

Common Unit Options. The fair value of each option award is estimated on the date of grant using the Black-Scholes Option Pricing Model. Upon the exercise of the common unit options, the Partnership intends to settle these obligations with new issues of common units on a net basis. The common unit options activity for the year ended December 31, 2014 is as follows:



Common Unit Options	Units		Weighted Average Exercise Price
Outstanding at the beginning of period	142,550		$	22.04
Exercised	(34,900	)	20.03
Outstanding at end of period	107,650		22.68
Exercisable at the end of the period	107,650

The common unit options have an intrinsic value of less than $1 million related to non-vested units with a weighted average contractual term of 1.5 years. Intrinsic value is the closing market price of a common unit less the option strike price, multiplied by the number of unit options outstanding as of the end of the period presented. Unit options with an exercise price greater than the end of the period closing market price are excluded.

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Phantom Units. During 2014, the Partnership awarded 1,450,230 phantom units to senior management and certain key employees. These awards are service condition (time-based) grants that vest 60% after the third year of continued employment and 40% after the fifth year of continued employment. Distributions on the phantom units will be paid concurrent with the Partnership’s distribution for common units.

During 2013, the Partnership awarded 62,360 phantom units to senior management and certain key employees. These awards are service condition (time-based) grants that generally vest 60% after the third year of continued employment and 40% after the fifth year of continued employment. Distributions on the phantom units will be paid concurrent with the Partnership’s distribution for common units.

In December 2012, the Partnership awarded 495,375 phantom units to senior management and certain key employees. These awards are service condition (time-based) grants that vest 60% after the third year of continued employment and 40% after the fifth year of continued employment. Also during 2012, 8,250 phantom units were awarded to senior management and key employees as service condition (time-based) grants that generally vest ratably over a 5 year period. Distributions on the phantom units will be paid concurrent with the Partnership’s distribution for common units.

The following table presents phantom unit activity for the year ended December 31, 2014:



Phantom Units	Units		Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period	982,242		$	23.16
Service condition grants	1,450,230		25.24
Vested service condition	(183,380	)	25.25
Forfeited service condition	(81,373	)	24.83
Total outstanding at end of period	2,167,719		24.31

During the years ended December 31, 2014, 2013 and 2012, the weighted average grant date fair value per phantom unit granted was $25.24, $25.44, and $21.39, respectively. The total fair value of awards vested was $5 million, $6 million, and $5 million for the years ended December 31, 2014, 2013 and 2012, respectively, based on the market price of Regency common units as of the vesting date.

The Partnership expects to recognize $42 million of unit-based compensation expense related to non-vested phantom units over a period of 3.9 years.

Cash Restricted Units. The Partnership began granting cash restricted units in 2014. These 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 year ended December 31, 2014:



Cash Restricted Units	Units
Outstanding at the beginning of the period	—
Service condition grants	400,928
Vested service condition	(500	)
Forfeited service condition	(21,100	)
Total outstanding at end of period	379,328

Based on the trading price of Regency common units at December 31, 2014, the Partnership expects to recognize $7 million of unit-based compensation expense related to non-vested cash restricted units over a period of 2.5 years.

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18. 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 December 31, 2014, 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.

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



	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 and noncontrolling interest	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
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
ASSETS
Cash	$	—	$	—	$	19	$	—		$	19
All other current assets	—		366		15		—			381
Property, plant, and equipment, net	—		4,244		174		—			4,418
Investments in subsidiaries	10,446		—		—		(10,446		)	—
Investments in unconsolidated affiliates	—		1,995		—		102			2,097
All other assets	—		1,867		—		—			1,867
TOTAL ASSETS	$	10,446	$	8,472	$	208	$	(10,344	)	$	8,782

LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST
All other current liabilities	—		466		9		—			475
Long-term liabilities	2,832		559		—		—			3,391
Noncontrolling interest	—		—		—		102			102
Total partners’ capital and noncontrolling interest	7,614		7,447		199		(10,446		)	4,814
TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST	$	10,446	$	8,472	$	208	$	(10,344	)	$	8,782



	For the year ended December 31, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Revenues	$	—		$	4,888		$	66	$	(3	)	$	4,951
Operating costs, expenses, and other	—			4,942			35		(9		)	4,968
Operating (loss) income	—			(54		)	31		6			(17		)
Income from unconsolidated affiliates	—			195			—		—			195
Interest expense, net	(290		)	(14		)	—		—			(304		)
Loss on debt refinancing, net	(24		)	(1		)	—		—			(25		)
Equity in consolidated subsidiaries	166			—			—		(166		)	—
Other income and deductions, net	3			9			—		—			12
(Loss) income before income taxes	(145		)	135			31		(160		)	(139		)
Income tax expense (benefit)	4			(2		)	1		—			3
Net (loss) income	(149		)	137			30		(160		)	(142		)
Net income attributable to noncontrolling interest	—			—			—		(15		)	(15		)
Net (loss) income attributable to Regency Energy Partners LP	$	(149	)	$	137		$	30	$	(175	)	$	(157	)

Total other comprehensive income	$	—		$	—		$	—	$	—		$	—
Comprehensive (loss) income	(149		)	137			30		(160		)	(142		)
Comprehensive income attributable to noncontrolling interest	—			—			—		15			15
Comprehensive (loss) income attributable to Regency Energy Partners LP	$	(149	)	$	137		$	30	$	(175	)	$	(157	)

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	For the year ended December 31, 2013
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Revenues	$	—		$	2,489		$	32	$	—		$	2,521
Operating costs, expenses, and other	3			2,448			15		—			2,466
Operating (loss) income	(3		)	41			17		—			55
Income from unconsolidated affiliates	—			135			—		—			135
Interest expense, net	(148		)	(16		)	—		—			(164		)
Loss on debt refinancing, net	(7		)	—			—		—			(7		)
Equity in consolidated subsidiaries	172			—			—		(172		)	—
Other income and deductions, net	7			—			—		—			7
Income before income taxes	21			160			17		(172		)	26
Income tax expense (benefit)	1			(2		)	—		—			(1		)
Net income	20			162			17		(172		)	27
Net income attributable to noncontrolling interest	—			(8		)	—		—			(8		)
Net income attributable to Regency Energy Partners LP	$	20		$	154		$	17	$	(172	)	$	19

Total other comprehensive income	$	—		$	—		$	—	$	—		$	—
Comprehensive income	20			162			17		(172		)	27
Comprehensive income attributable to noncontrolling interest	—			8			—		—			8
Comprehensive income attributable to Regency Energy Partners LP	$	20		$	154		$	17	$	(172	)	$	19

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	For the year ended December 31, 2012
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Revenues	$	—		$	1,985		$	15	$	—		$	2,000
Operating costs, expenses, and other	10			1,951			9		—			1,970
Operating (loss) income	(10		)	34			6		—			30
Income from unconsolidated affiliates	—			105			—		—			105
Interest expense, net	(104		)	(18		)	—		—			(122		)
Gain (loss) on debt refinancing, net	(8		)	—			—		—			(8		)
Equity in consolidated subsidiaries	141			—			—		(141		)	—
Other income and deductions, net	14			15			—		—			29
Income before income taxes	33			136			6		(141		)	34
Income tax expense (benefit)	1			(1		)	—		—			—
Net income	32			137			6		(141		)	34
Net income attributable to noncontrolling interest	—			(2		)	—		—			(2		)
Net income attributable to Regency Energy Partners LP	$	32		$	135		$	6	$	(141	)	$	32

Total other comprehensive income (loss)	$	—		$	2		$	—	$	—		$	2
Comprehensive income	32			139			6		(141		)	36
Comprehensive income attributable to noncontrolling interest	—			2			—		—			2
Comprehensive income attributable to Regency Energy Partners LP	$	32		$	137		$	6	$	(141	)	$	34



	For the year ended December 31, 2014
	Parent		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Cash flows from operating activities	$	—	$	664		$	56		$	(1	)	$	719
Cash flows from investing activities	—		(2,130		)	(30		)	(9		)	(2,169		)
Cash flows from financing activities	—		1,466			(13		)	2			1,455
Change in cash	—		—			13			(8		)	5
Cash at beginning of period	—		—			19			—			19
Cash at end of period	$	—	$	—		$	32		$	(8	)	$	24



	For the year ended December 31, 2013
	Parent		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated Partnership
Cash flows from operating activities	$	—	$	424		$	12		$	—	$	436
Cash flows from investing activities	—		(1,303		)	(90		)	—		(1,393		)
Cash flows from financing activities	—		879			44			—		923
Change in cash	—		—			(34		)	—		(34		)
Cash at beginning of period	—		—			53			—		53
Cash at end of period	$	—	$	—		$	19		$	—	$	19

Table of Contents



	For the year ended December 31, 2012
	Parent		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated Partnership
Cash flows from operating activities	$	—	$	316		$	8		$	—	$	324
Cash flows from investing activities	—		(746		)	(61		)	—		(807		)
Cash flows from financing activities	—		430			105			—		535
Change in cash	—		—			52			—		52
Cash at beginning of period	—		—			1			—		1
Cash at end of period	$	—	$	—		$	53		$	—	$	53

19. QUARTERLY FINANCIAL DATA (UNAUDITED)



	Quarter Ended
2014	December 31			September 30		June 30			March 31
Operating revenues	$	1,427		$	1,483	$	1,178		$	863
Operating (loss) income	(218		)	144		35			22
Net (loss) income attributable to Regency Energy Partners LP	(261		)	103		(8		)	9
Earnings per common units:
Basic net (loss) income per common unit	(0.67		)	0.23		(0.05		)	0.00
Diluted net (loss) income per common unit	(0.67		)	0.23		(0.05		)	0.00

	Quarter Ended
2013	December 31			September 30		June 30			March 31
Operating revenues	$	677		$	665	$	639		$	540
Operating income (loss)	12			24		34			(15		)
Net (loss) income attributable to Regency Energy Partners LP	(1		)	39		10			(29		)
Earnings per common units:
Basic net (loss) income per common unit	(0.03		)	0.16		0.07			(0.06		)
Diluted net (loss) income per common unit	(0.03		)	0.05		0.07			(0.06		)

The three months ended December 31, 2014 includes a $370 million goodwill impairment charge recorded related to the Permian reporting unit within the Gathering and Processing segment.

PANHANDLE EASTERN PIPE LINE COMPANY, LP - FORM 10-K - EX-99.1 - EXHIBIT 99.1 REGENCY FINANCIALS - February 26, 2015

Attached files

PANHANDLE EASTERN PIPE LINE COMPANY, LP Reports