EXHIBIT 99.1

TABLE OF CONTENTS

		PAGE
Item 6	Selected Financial Data	1
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	6
Item 7A	Quantitative and Qualitative Disclosure about Market Risk	26
Item 8	Financial Statements and Supplementary Data	27

i

Introductory Statement

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

Name	Definition or Description
/d	Per day
AOCI	Accumulated Other Comprehensive Income (Loss)
APM	Anadarko Pecos Midstream LLC
Bbls	Barrels
Bcf	One billion cubic feet
BTU	A unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit
Citi	Citigroup Global Markets Inc.
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act
CFTC	Commodity Futures Trading Commission
CM	Chesapeake West Texas Processing, L.L.C.
DHS	U.S. Department of Homeland Security
DOT	U.S. Department of Transportation
EFS Haynesville	EFS Haynesville, LLC, a wholly-owned subsidiary of GECC
EIA	Energy Information Administration
ELG	Edwards Lime Gathering LLC and its wholly-owned subsidiaries, ELG Oil LLC and ELG Utility LLC
EPA	Environmental Protection Agency
EPD	Enterprise Products Partners L.P.
ERISA	Employee Retirement Income Security Act of 1974
ETC	Energy Transfer Company, the name assumed by La Grange Acquisition, L.P. for conducting business and shared services, a wholly-owned subsidiary of ETP
ETE	Energy Transfer Equity, L.P.
ETE GP	ETE GP Acquirer LLC
ETP	Energy Transfer Partners, L.P.
FASB	Financial Accounting Standards Board
FASB ASC	FASB Accounting Standards Codification
FERC	Federal Energy Regulatory Commission
Finance Corp.	Regency Energy Finance Corp., a wholly-owned subsidiary of the Partnership
GAAP	Accounting principles generally accepted in the United States of America
GE	General Electric Company
GE EFS	General Electric Energy Financial Services, a unit of GECC, combined with Regency GP Acquirer, L.P. and Regency LP Acquirer, L.P.
GECC	General Electric Capital Corporation, an indirect wholly-owned subsidiary of GE
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 Regency Employees Management LLC
GPM	Gallons per minute
GP Seller	Regency GP Acquirer, L.P.
Gulf States	Gulf States Transmission LLC, a wholly-owned subsidiary of the Partnership
HLPSA	Hazardous Liquid Pipeline Safety Act
Holdco	ETP Holdco Corporation
HPC	RIGS Haynesville Partnership Co., a general partnership, and its wholly-owned subsidiary, Regency Intrastate Gas LP
ICA	Interstate Commerce Act

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Name	Definition or Description
IDRs	Incentive Distribution Rights
IPO	Initial Public Offering of Securities
IRC	Internal Revenue Code
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
MBbls	One thousand barrels
MEP	Midcontinent Express Pipeline LLC
MLP	Master Limited Partnership
MMBtu	One million BTUs
MMcf	One million cubic feet
MQD	Minimum Quarterly Distribution ($0.35 per common unit)
NGA	Natural Gas Act of 1938
NGLs	Natural gas liquids, including ethane, propane, normal butane, iso butane and natural gasoline
NGPA	Natural Gas Policy Act of 1978
NGPSA	Natural Gas Pipeline Safety Act of 1968, as amended
NMED	New Mexico Environmental Development
NPDES	National Pollutant Discharge Elimination System
NYMEX	New York Mercantile Exchange
NASDAQ	NASDAQ Global Select Market
NYSE	New York Stock Exchange
OSHA	Occupational Safety and Health Act
Partnership	Regency Energy Partners LP
Ranch JV	Ranch Westex JV LLC
Regency Western	Regency Western G&P LLC, an indirectly wholly owned subsidiary of the Partnership
RCRA	Resource Conservation and Recovery Act
RGS	Regency Gas Services LP, a wholly-owned subsidiary of the Partnership
RIGS	Regency Intrastate Gas System
SEC	Securities and Exchange Commission
Series A Preferred Units	Series A convertible redeemable preferred units
Services Co.	ETE Services Company, LLC
Southern Union	Southern Union Company
SUGS	Southern Union Gas Services
SXL	Sunoco Logistics Partners L.P.
TCEQ	Texas Commission on Environmental Quality
TRRC	Texas Railroad Commission
WTI	West Texas Intermediate Crude
Zephyr	Zephyr Gas Services LLC, a wholly-owned subsidiary of the Partnership

iii

Item 6. Selected Financial Data

The historical financial information presented below for the Partnership was derived from our audited consolidated financial statements as of and for the periods presented below. The Partnership completed the SUGS acquisition on April 30, 2013, which was a reorganization of entities under common control. The Partnership’s consolidated financial statements have been retrospectively adjusted to reflect consolidation of SUGS beginning March 26, 2012 (the date ETE acquired Southern Union). This change only impacted periods in 2012, and no annual amounts prior to 2012 have been adjusted. See “Item 7. Management’s Discussions and Analysis of Financial Condition and Results of Operations” for a discussion of why our results may not be comparable, either from period to period or going forward. All tabular dollar amounts, except per unit data, are in millions.

	Successor									Predecessor
	Year Ended December 31, 2012			Year Ended December 31, 2011			Period from Acquisition (May 26, 2010) to December 31, 2010			Period from January 1, 2010 to May 25, 2010			Year Ended December 31, 2009			Year Ended December 31, 2008
Statement of Operations Data:
Total revenues	$	2,000		$	1,434		$	716		$	505		$	1,043		$	1,785
Total operating costs and expenses	1,970			1,394			702			485			816			1,635
Operating income	30			40			14			20			227			150
Other income and deductions:
Income from unconsolidated affiliates	105			120			54			16			8			—
Interest expense, net	(122		)	(103		)	(48		)	(35		)	(78		)	(63		)
Loss on debt refinancing, net	(8		)	—			(16		)	(2		)	—			—
Other income and deductions, net	29			17			(8		)	(4		)	(15		)	—
Income (loss) from continuing operations before income taxes	34			74			(4		)	(5		)	142			87
Income tax expense (benefit)	—			—			1			—			(1		)	—
Income (loss) from continuing operations	$	34		$	74		$	(5	)	$	(5	)	$	143		$	87
Discontinued operations:
Net (loss) income from operations of east Texas assets	—			—			(1		)	—			(3		)	14
Net income (loss)	34			74			(6		)	(5		)	140			101
Net income attributable to noncontrolling interest	(2		)	(2		)	—			—			—			—
Net income (loss) attributable to Regency Energy Partners LP	$	32		$	72		$	(6	)	$	(5	)	$	140		$	101
Amounts attributable to Series A Preferred Units	10			8			5			3			4			—
General partner’s interest, including IDRs	9			7			3			1			5			4
Amount allocated to non-vested common units	—			—			—			—			1			1
Beneficial conversion feature for Class D common units	—			—			—			—			1			7
Pre-acquisition income from SUGS allocated to predecessor equity	(14		)	—			—			—			—			—
Limited partners’ interest in net income (loss)	$	27		$	57		$	(14	)	$	(9	)	$	129		$	89
Basic and diluted income (loss) from continuing operations per unit:
Basic income (loss) from continuing operations per common and subordinated unit	$	0.16		$	0.39		$	(0.09	)	$	(0.10	)	$	1.63		$	1.14
Diluted income (loss) from continuing operations per common and subordinated units	0.13			0.32			(0.09		)	(0.10		)	1.63			1.10
Distributions per common and subordinated unit	1.84			1.81			0.89			0.89			1.78			1.71

1

Basic and diluted income (loss) on discontinued operations per unit	$	—	$	—	$	(0.01	)	$	—		$	(0.03	)	$	0.21
Basic and diluted net income (loss) per unit:
Basic net income (loss) per common and subordinated unit	$	0.16	$	0.39	$	(0.10	)	$	(0.10	)	$	1.61		$	1.34
Diluted net income (loss) per common and subordinated unit	0.13		0.32		(0.10		)	(0.10		)	1.60			1.28
Income per Class D common unit due to beneficial conversion feature	$	—	$	—	$	—		$	—		$	0.11		$	0.99

	Successor						Predecessor
	December 31, 2012		December 31, 2011		December 31, 2010		December 31, 2009		December 31, 2008
Balance Sheet Data (at period end):
Property, plant and equipment, net	$	3,686	$	1,886	$	1,660	$	1,456	$	1,704
Total assets	8,123		5,568		4,770		2,533		2,459
Long-term debt (long-term portion only)	2,157		1,687		1,141		1,014		1,126
Series A Preferred Units	73		71		71		52		—
Partners’ capital	5,340		3,531		3,294		1,243		1,099

	Successor									Predecessor
	Year Ended December 31, 2012			Year Ended December 31, 2011			Period from Acquisition (May 26, 2010) to December 31, 2010			Period from January 1, 2010 to May 25, 2010			Year Ended December 31, 2009			Year Ended December 31, 2008
Cash Flow Data:
Net cash flows provided by (used in):
Operating activities	$	324		$	254		$	80		$	89		$	144		$	181
Investing activities	(807		)	(955		)	(297		)	(148		)	(156		)	(949		)
Financing activities	535			693			203			72			21			735
Other Financial Data:
Adjusted total segment margin(1)	$	608		$	421		$	235		$	154		$	361		$	402
Adjusted EBITDA(1)	525			422			218			108			211			259
Maintenance capital expenditures	58			22			7			8			20			18

 _______________________

(1) See “—Non-GAAP Financial Measures” for a reconciliation to its most directly comparable GAAP measure.

Non-GAAP Financial Measures

We include in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” the following non-GAAP financial measures: EBITDA, adjusted EBITDA, total segment margin, and adjusted total segment margin. We provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures as calculated and presented in accordance with GAAP.

We define EBITDA as net income (loss) plus interest expense, net, income tax expense, net, and depreciation and amortization expense. We define adjusted EBITDA as EBITDA plus or minus the following:

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

• unit-based compensation expenses;

• loss (gain) on asset sales, net;

• loss on debt refinancing;

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

• net income attributable to noncontrolling interest; and

2

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

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

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

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

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

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

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

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

We define segment margin, generally, as revenues minus cost of sales. We calculate our Gathering and Processing segment margin and Natural Gas Transportation segment margin as revenues generated from operations less the cost of natural gas and NGLs purchased and other costs of sales, including third-party transportation and processing fees. We do not record segment margin for our investments in unconsolidated affiliates (HPC, MEP, Lone Star, Ranch JV and Grey Ranch) because we record our ownership percentages of their net income as income from unconsolidated affiliates in accordance with the equity method of accounting. We calculate our Contract Services segment margin as revenues minus direct costs, primarily compressor unit repairs, associated with those revenues. We calculate total segment margin as the sum of segment margin of our segments less intersegment eliminations. We define adjusted segment margin as segment margin adjusted for non-cash (gains) losses from commodity derivatives. Our adjusted total segment margin equals the sum of our operating segments’ adjusted segment margins or segment margins, as applicable, including intersegment eliminations.

Total segment margin and adjusted total segment margin are included as a supplemental disclosure because they are primary performance measures used by our management as they represent the result of product sales, service fee revenues and product purchases, a key component of our operations. We believe total segment margin and adjusted total segment margin are important measures because they are directly related to our volumes and commodity price changes. Operation and maintenance expense is a separate measure used by management to evaluate operating performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of our operation and maintenance expenses. These expenses are largely independent of the volumes we transport or process and fluctuate depending on the activities performed during a specific period. We do not deduct operation and maintenance expenses from total revenue in calculating total segment margin and adjusted total segment margin because we separately evaluate commodity volume and price changes in these margin amounts. As an indicator of our operating performance, total segment margin or adjusted total segment margin should not be considered an alternative to, or more meaningful than, net income as determined in accordance with GAAP. Our total segment margin and adjusted total segment margin may not be comparable to a similarly titled measure of another company because other entities may not calculate these measures in the same manner.

3

	Successor									Predecessor
	Year Ended December 31, 2012			Year Ended December 31, 2011			Period from Acquisition (May 26, 2010) to December 31, 2010			Period from January 1, 2010 to May 25, 2010			Year Ended December 31, 2009			Year Ended December 31, 2008
Reconciliation of “Adjusted EBITDA” to net cash flows provided by operating activities and to net income (loss)
Net cash flows provided by operating activities	$	324		$	254		$	80		$	89		$	144		$	181
Add (deduct):
Depreciation and amortization, including debt issuance cost write-off and amortization and bond premium write-off and amortization	(259		)	(175		)	(78		)	(51		)	(116		)	(105		)
Income from unconsolidated affiliates	105			120			54			16			8			—
Derivative valuation change	12			21			(33		)	(12		)	(5		)	15
(Loss) gain on assets sales, net	(3		)	2			—			—			133			(1		)
Unit-based compensation expenses	(5		)	(3		)	(2		)	(12		)	(6		)	(4		)
Gain on insurance settlements	—			—			—			—			—			3
Trade accounts receivable, accrued revenues and related party receivables	—			8			—			11			(11		)	(19		)
Other current assets and other current liabilities	(10		)	(11		)	13			(25		)	(4		)	(6		)
Trade accounts payable, accrued cost of gas and liquids, related party payables, and deferred revenues	(18		)	(23		)	15			(9		)	4			41
Distributions of earnings received from unconsolidated affiliates	(121		)	(119		)	(57		)	(12		)	(8		)	—
Cash flow changes in other assets and liabilities	9			—			2			—			1			(4		)
Net income (loss)	34			74			(6		)	(5		)	140			101
Add (deduct):
Interest expense, net	122			103			48			35			78			63
Depreciation and amortization	252			169			77			46			110			103
Income tax expense (benefit)	—			—			1			—			(1		)	—
EBITDA	408			346			120			76			327			267
Add (deduct):
Patnership’s interest in unconsolidated affiliates adjusted EBITDA (1) (2) (3) (4)	227			213			102			21			11			—
Income from unconsolidated affiliates	(105		)	(120		)	(54		)	(16		)	(8		)	—
Non-cash (gain) loss from commodity and embedded derivatives	(19		)	(18		)	31			11			5			(15		)
Loss (gain) on assets sales, net	3			(2		)	—			—			(133		)	1
Other expense, net	11			3			19			16			9			6
Adjusted EBITDA	$	525		$	422		$	218		$	108		$	211		$	259
(1) 100% of HPC’s Adjusted EBITDA is calculated as follows:
Net income	$	70		$	109		$	72		$	35		$	20		$	—
Add:
Depreciation and amortization	36			35			20			12			9			—
Interest expense	2			1			—			—			—			—
Impairment of property, plant and equipment	22			—			—			—			—			—
Other expense, net	2			—			—			—			—			—
HPC’s Adjusted EBITDA	132			145			92			47			29			—
Ownership Interest	49.99		%	49.99		%	49.99		%	45		%	38		%	—		%
Partnership’s interest in HPC’s Adjusted EBITDA	$	65		$	72		$	46		$	21		$	11		$	—
(2) 100% of MEP’s EBITDA is calculated as follows:
Net income	$	83		$	85		$	43		$	—		$	—		$	—
Add:

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Depreciation and amortization	69			70			40			—			—			—
Interest expense, net	52			51			29			—			—			—
MEP’s Adjusted EBITDA	204			206			112			—			—			—
Ownership Interest	50		%	50		%	49		%	—		%	—		%	—		%
Partnership’s interest in MEP’s Adjusted EBITDA	$	102		$	103		$	56		$	—		$	—		$	—
(3) 100% of Lone Star’s Adjusted EBITDA is calculated as follows:
Net income	$	147		$	94		$	—		$	—		$	—		$	—
Add:
Depreciation and amortization	52			32			—			—			—			—
Lone Star’s Adjusted EBITDA	199			126			—			—			—			—
Ownership Interest	30		%	30		%	—		%	—		%	—		%	—		%
Partnership’s interest in Lone Star’s Adjusted EBITDA	$	60		$	38		$	—		$	—		$	—		$	—
(4) 100% of Ranch JV’s Adjusted EBITDA is calculated as follows:
Net loss	$	(2	)	$	—		$	—		$	—		$	—		$	—
Add:
Depreciation and amortization	1			—			—			—			—			—
Ranch JV’s Adjusted EBITDA	(1		)	—			—			—			—			—
Ownership Interest	33.33		%	—		%	—		%	—		%	—		%	—		%
Partnership’s interest in Ranch JV’s Adjusted EBITDA	$	—		$	—		$	—		$	—		$	—		$	—

	Successor									Predecessor
	Year Ended December 31, 2012			Year Ended December 31, 2011			Period from Acquisition (May 26, 2010) to December 31, 2010			Period from January 1, 2010 to May 25, 2010			Year Ended December 31, 2009			Year Ended December 31, 2008
Reconciliation of net income (loss) to “Adjusted total segment margin”
Net income (loss)	$	34		$	74		$	(6	)	$	(5	)	$	140		$	101
Add (deduct):
Operation and maintenance	228			147			78			48			117			120
General and administrative	100			67			44			37			57			51
Loss (gain) on assets sales, net	3			(2		)	—			—			(133		)	—
Management services termination fee	—			—			—			—			—			4
Transaction expenses	—			—			—			—			—			2
Depreciation and amortization	252			169			76			42			100			93
Income from unconsolidated affiliates	(105		)	(120		)	(54		)	(16		)	(8		)	—
Interest expense, net	122			103			48			35			78			63
Loss on debt refinancing, net	8			—			16			2			—			—
Other income and deductions, net	(29		)	(17		)	8			4			15			—
Income tax expense (benefit)	—			—			1			—			(1		)	—
Discontinued operations	—			—			1			—			3			(14		)
Total segment margin	613			421			212			147			368			420
Add (deduct):
Non-cash (gain) loss from commodity derivatives	(5		)	—			23			7			(7		)	(18		)
Adjusted total segment margin	$	608		$	421		$	235		$	154		$	361		$	402

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion analyzes our financial condition and results of operations. You should read the following discussion of our financial condition and results of operations in conjunction with our historical consolidated financial statements and notes included elsewhere in this document.

We are a growth-oriented publicly-traded Delaware limited partnership formed in 2005 engaged in the gathering and processing, compression, treating and transportation of natural gas and the transportation, fractionation and storage of NGLs. We focus on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring, Avalon and Granite Wash shales. Our assets are primarily located in Texas, Louisiana, Arkansas, Pennsylvania, California, Mississippi, Alabama, New Mexico, and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma.

We divide our operations into five business segments. During the fourth quarter of 2012, the Partnership realigned the composition of its segments and updated the segment names to reflect the realignment. Accordingly, we have restated segment information for earlier periods to reflect this new segment alignment as follows:

• Gathering and Processing. We provide “wellhead-to-market” services to producers of natural gas, which include transporting raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate NGLs from the raw natural gas and selling or delivering the pipeline-quality natural gas and NGLs to various markets and pipeline systems. This segment also includes our 33.33% membership interest in Ranch JV, which processes natural gas delivered from the NGLs-rich Bone Spring and Avalon shale formations in west Texas. The Partnership completed the SUGS Acquisition on April 30, 2013. The Partnership completed the SUGS Acquisition on April 30, 2013; therefore, the Gathering and Processing segment amounts have been retrospectively adjusted to reflect the SUGS acquisition beginning March 26, 2012.

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

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

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

• Corporate. The Corporate segment comprises our corporate offices.

Gathering and Processing segment. Results of operations from our Gathering and Processing segment are determined primarily by the volumes of natural gas that we gather and process, our current contract portfolio and natural gas and NGL prices. We measure the performance of this segment primarily by the adjusted segment margin it generates. We gather and process natural gas pursuant to a variety of arrangements generally categorized as “fee-based” arrangements, “percent-of-proceeds” arrangements and “keep-whole” arrangements. Under fee-based arrangements, we earn fixed cash fees for the services that we render. Under the latter two types of arrangements, we generally purchase raw natural gas and sell processed natural gas and NGLs. We regard the adjusted segment margin generated by our sales of natural gas and NGLs under percent-of-proceeds and keep-whole arrangements as comparable to the revenues generated by fixed fee arrangements to the extent that they are hedged.

Percent-of-proceeds and keep-whole arrangements involve commodity price risk to us because our adjusted segment margin is based in part on natural gas and NGL prices. We seek to minimize our exposure to fluctuations in commodity prices in several ways, including managing our contract portfolio. In managing our contract portfolio, we classify our gathering and processing contracts according to the nature of commodity risk implicit in the settlement structure of those contracts.

We also minimize our exposure to commodity price fluctuations by executing swap and put option contracts settled against ethane, propane, butane, natural gasoline, natural gas and WTI market prices. We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.

In addition, we perform a producer services function whereby we purchase natural gas from producers or gas marketers at receipt points on our systems, including HPC, and transport that gas to delivery points on HPC’s system at which we sell the natural gas at market price. We regard the segment margin with respect to those purchases and sales as the economic equivalent of a fee for

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our transportation service. These contracts are frequently settled in terms of an index price for both purchases and sales. In order to minimize commodity price risk, we attempt to match sales with purchases at the index price. We typically sell natural gas under pricing terms related to a market index. To the extent possible, we match the pricing and timing of our supply portfolio to our sales portfolio in order to lock in our margin and reduce our overall commodity price exposure. To the extent our natural gas position is not balanced, we will be exposed to the commodity price risk associated with the price of natural gas. Refer to “Item 7A. Quantitative and Qualitative Disclosure about Market Risk” for further details.

Natural Gas Transportation segment. HPC has the capacity to transport up to 2.1 Bcf/d of natural gas. Results of HPC’s operations are determined primarily by the volumes of natural gas transported and subscribed on its intrastate pipeline system and the level of fees charged to customers or the margins received from purchases and sales of natural gas. HPC generates revenues and segment margins principally under fee-based transportation contracts. Approximately 89% of the margin HPC earns is related to fixed capacity reservation charges that are not directly dependent on throughput volumes or commodity prices.

MEP pipeline system, operated by KMP, has the capability to transport up to 1.8 Bcf/d of natural gas, and the pipeline capacity is fully subscribed with long-term binding commitments from creditworthy shippers. Results of MEP’s operations are determined primarily by the volumes of natural gas transported and subscribed on its interstate pipeline system and the level of fees charged to customers. MEP generates revenues and segment margins principally under fee-based transportation contracts. The margin MEP earns is primarily related to fixed capacity reservation charges that are not directly dependent on throughput volumes or commodity prices. If a sustained decline in commodity prices should result in a decline in volumes, MEP’s revenues would not be significantly impacted until expiration of the current contracts.

Gulf States is a small interstate pipeline that uses cost-based rates and terms and conditions of service for shippers wishing to secure capacity for interstate transportation service. Rates charged are largely governed by long-term negotiated rate agreements.

NGL Services segment. Lone Star owns and operates a NGLs storage, fractionation and transportation business. Lone Star's storage assets are primarily located in Mont Belvieu, Texas and its West Texas Pipeline, which passes through the Barnett shale, and its Lone Star West Texas Gateway NGL Pipeline, which passes through the Eagle Ford shale, transports NGLs through intrastate pipeline systems that originate in the Permian and Delaware basins in west Texas, and terminates at the Mont Belvieu storage and fractionation complex. Lone Star also owns and operates fractionation and processing assets located in Louisiana and Texas, including the Lone Star Fractionator I, located at Mont Belvieu, which began service in December 2012. Results of Lone Star's operations are based upon fee-based revenues and commodity pricing which are determined primarily by volumes stored, processed or transported, the level of fees charged to customers and the value of the commodity in the market at the time of sale. The margin Lone Star earns is primarily related to the volume of NGLs stored, processed and transported.

Contract Services segment. We own and operate a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems. We also own and operate a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management. Fees charged for compression and treating services are typically fixed and are based on the revenue generating horsepower.

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

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

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

We do not record segment margin for our investments in unconsolidated affiliates (HPC, MEP, Lone Star, Ranch JV and Grey Ranch) because we record our ownership percentage of their net income as income from unconsolidated affiliates in accordance with the equity method of accounting.

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

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

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

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

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

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

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

• non-cash unit-based compensation;

• loss (gain) on asset sales, net;

• loss on debt refinancing;

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

• net income attributable to noncontrolling interest; and

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

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

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

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

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

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

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

GENERAL TRENDS AND OUTLOOK. We expect our business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove incorrect, our actual results may vary materially from our expected results.

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Energy Outlook. In its annual energy outlook forecast, the EIA projects that domestic production of crude oil will increase from an average of 5.6 million Bbls/d in 2011 to 7.9 million Bbls/d by 2014, a 40% increase. Although production is projected to gradually decline beyond 2020, overall crude production is expected to remain above 6.1 million Bbls/d through 2040.

Natural gas production from shales is expected to increase to 19 trillion cubic feet by 2040 from 5 trillion cubic feet produced in 2010. Natural gas production from shales amounted to 23% of total natural gas produced in the U.S. in 2010 and is projected to grow to 56% by 2040.

The increase in natural gas consumption is expected to come primarily from the industrial and electric power sectors. Natural gas used in the industrial sector is projected to grow from 6.8 trillion cubic feet in 2011 to 7.8 trillion cubic feet in 2025. The natural gas share of electricity generation rose to 24% in 2010 and is expected to continue increasing to 30% in 2040.

Recently, however, as drilling activities have been more focused on shale plays with a high concentration of NGLs and crude oil, some producers have announced plans to reduce gas drilling activities in order to focus on oil and NGLs prospects.

Effect of Interest Rates and Inflation. Interest rates on existing and future credit facilities and future debt offerings could be significantly higher than current levels, causing our financing costs to increase accordingly. Although increased financing costs could limit our ability to raise funds in the capital markets, we expect to remain competitive with respect to acquisitions and capital projects since our competitors would face similar circumstances.

Inflation in the United States has been relatively low in recent years and has not had a material effect on our results of operations. It may in the future, however, increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. Our operating revenues and costs are influenced to a greater extent by price changes in natural gas and NGLs. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along a portion of increased costs to our customers in the form of higher fees.

RECENT DEVELOPMENTS

SUGS Acquisition. In April 2013, we and Regency Western acquired SUGS from Southern Union, a wholly owned subsidiary of Holdco, for $1.5 billion. We financed the acquisition by issuing to Southern Union 31,372,419 of common units and 6,274,483 recently created Class F common units. The Class F common units are not entitled to participate in the Partnership’s distributions for twenty-four months post-transaction closing. The remaining $600 million, less $107 million of closing adjustments, was paid in cash. In addition, ETE has agreed to forgo IDR payments on the Partnership common units issued with this transaction for the twenty-four months post-transaction closing and to suspend the $10 million annual management fee paid by the Partnership for two years post-transaction close.

The acquisition of SUGS expands the Partnership’s presence in the Permian Basin in west Texas, one of the most prolific, high growth, oil and liquids-rich basins in North America.

We accounted for the acquisition in a manner similar to the pooling of interest method of accounting, as it was a transaction between commonly controlled entities. Under this method of accounting, we reflected historical balance sheet data for us and SUGS instead of reflecting the fair market value of SUGS assets and liabilities from the date of the acquisition forward. We retrospectively adjusted our financial statements to include the operations of SUGS from March 26, 2012 (the date upon which common control began).

Eagle Ford Expansion. In May 2012, we announced the construction of an expansion to ELG in the Eagle Ford shale ("Edwards Lime Expansion") which will increase the system's capacity by 90 MMcf/d to 160 MMcf/d, and will provide for additional crude transportation and stabilization capacity of 17,000 Bbls/d. We own a 60% interest in ELG and operate the assets. Contracts on the expansion are fee-based, which includes reservation fees. Capital expenditures related to the expansion are expected to total $150 million, of which we will contribute $90 million; this amount is included in our previously announced 2012 growth capital projections. The project is expected to be completed in the first half of 2013.

Dubach Processing Facility Expansion. In August 2012, we announced an expansion of the Dubach processing facility in north Louisiana which will increase the processing capacity of the facility to 210 MMcf/d by adding an incremental 70 MMcf/d of cryogenic processing capacity and 20 MMcf/d of JT capacity. The $75 million capital expenditure related to the Dubach expansion also includes the construction of high-pressure gathering lines to transport production to the facility. The project, which is expected to come online in the second quarter of 2013, is backed by fee-based contracts and an acreage dedication.

Lone Star Expansion. In February 2012, Lone Star announced it would construct a second 100,000 Bbls/d NGL fractionation facility at Mont Belvieu, Texas. Lone Star expects this second fractionator to be completed in the fourth quarter of 2013 at an estimated cost of $350 million, of which our proportionate estimated capital contributions are $105 million. In December 2012, Lone Star announced that its West Texas Gateway NGL Pipeline and Lone Star Fractionator I were placed in service, both before

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originally anticipated. The West Texas Gateway NGL Pipeline, which passes through the Eagle Ford shale, is a 570-mile, 16-inch pipeline that transports NGLs produced in the Permian and Delaware Basins in West Texas to Mont Belvieu, Texas and has an initial capacity of 209,000 Bbls/d. The Fractionator I, located at Mont Belvieu, Texas, has a capacity of 100,000 barrels per day of NGLs and will handle NGL barrels delivered from several sources, including the West Texas Gateway NGL pipeline.

Ranch JV Expansion. In June 2012, Ranch JV's 25 MMcf/d refrigeration processing plant began operations. In December 2012, Ranch JV’s 100 MMcf/d cryogenic processing plant began operations.

RESULTS OF OPERATIONS

Year Ended December 31, 2012 vs. Year Ended December 31, 2011

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

	Year Ended December 31, 2012			Year Ended December 31, 2011			Change			Percent
Total revenues	$	2,000		$	1,434		$	566		39	%
Cost of sales	1,387			1,013			374			37
Total segment margin (1)	613			421			192			46
Operation and maintenance	228			147			81			55
General and administrative	100			67			33			49
Loss (gain) on asset sales, net	3			(2		)	5			250
Depreciation and amortization	252			169			83			49
Operating income	30			40			(10		)	25
Income from unconsolidated affiliates	105			120			(15		)	13
Interest expense, net	(122		)	(103		)	(19		)	18
Loss on debt refinancing, net	(8		)	—			(8		)	100
Other income and deductions, net	29			17			12			71
Income before income taxes	34			74			(40		)	54
Income tax expense	—			—			—			100
Net income	$	34		$	74		$	(40	)	54
Net income attributable to the noncontrolling interest	(2		)	(2		)	—			—
Net income attributable to Regency Energy Partners LP	$	32		$	72		$	(40	)	56	%
Gathering and processing segment margin	$	423		$	233		$	190		82	%
Non-cash gain from commodity derivatives	(5		)	—			(5		)	100
Adjusted gathering and processing segment margin	$	418		$	233		$	185		79
Natural gas transportation segment margin	2			3			(1		)	33
Contract services segment margin (2)	189			185			4			2
Corporate segment margin	20			17			3			18
Intersegment eliminations (2)	(21		)	(17		)	(4		)	24
Adjusted total segment margin	$	608		$	421		$	187		44	%

_______________________

(1) For reconciliation of segment margin to the most directly comparable financial measure calculated and presented in accordance with GAAP, read “Item 6. Selected Financial Data.”

(2) Contract Services segment margin includes intersegment revenues of $21 million and $17 million for the years ended December 31, 2012 and 2011, respectively. These intersegment revenues were eliminated upon consolidation.

Net Income Attributable to Regency Energy Partners LP. Net income attributable to Regency Energy Partners LP decreased to $32 million in the year ended December 31, 2012 from $72 million in the year ended December 31, 2011. The major components of this change were as follows:

• $192 million increase in total segment margin, $145 million of which relates to the acquisition of SUGS. The remaining increase is mainly due to increased volumes in south and west Texas and north Louisiana in our Gathering and Processing segment. Although the decline in commodity prices lowered revenues and cost of sales, it had little impact to our total segment margin, as we continue to grow our fee-based revenues in south and west Texas as well as north Louisiana; and

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• $12 million increase in other income and deductions, net, primarily due to a $16 million one-time producer payment received in March 2012 related to an assignment of certain contracts offset by a decrease in the non-cash gain on the embedded derivatives related to the Series A Preferred Units; offset by

• $81 million increase in operations and maintenance expense, $62 million of which relates to the acquisition of SUGS, with the remaining increase of $19 million primarily related to increases in employee costs, compressor maintenance costs, and ad valorem taxes due to growth in west and south Texas and north Louisiana;

• $33 million increase in general and administrative expenses, $37 million of which relates to the acquisition of SUGS, offset by a $4 million decrease primarily due to lower professional fees and office expenses;

• $83 million increase in depreciation and amortization expense, $51 million of which relates to the acquisition of SUGS. The remaining $32 million increase is primarily related to the completion of various organic growth projects placed in service during 2012, as well as a $12 million increase related to the accelerated depreciation and amortization of certain tangible and intangible assets and an out-of-period adjustment of $7 million recorded in March 2012 (further discussed below);

• $19 million increase in interest expense, net, primarily related to a full year of interest associated with the $500 million 2021 Notes issued in May 2011 as well as three months of interest associated with our $700 million 2023 Notes issued in October 2012;

• $8 million net loss on debt refinancing related to the redemption of 35% of our outstanding 2016 Notes at a price of 109.375% of the principal amount plus accrued interest in May 2012; and

• $15 million decrease in income from unconsolidated affiliates, $9 million of which relates to the acquisition of SUGS due to an impairment of the investment in Grey Ranch. The remaining decrease is primarily related to a decrease in equity income from HPC associated with non-cash asset impairment charges related to its idle property, plant, and equipment.

Adjusted Total Segment Margin. Adjusted total segment margin increased to $608 million in the year ended December 31, 2012 from $421 million in the year ended December 31, 2011. The major components of this increase were as follows:

• Adjusted Gathering and Processing segment margin increased to $418 million for the year ended December 31, 2012 from $233 million for the year ended December 31, 2011, $144 million of which relates to the acquisition of SUGS with the remaining increase primarily due to the volume growth in south and west Texas and north Louisiana. Total Gathering and Processing segment throughput increased to 1,816,000 MMBtu/d during the year ended December 31, 2012 from 1,187,000 MMBtu/d during the year ended December 31, 2011. Total NGL gross production increased to 69,000 Bbls/d during the year ended December 31, 2012 from 32,000 Bbls/d during the year ended December 31, 2011;

• Contract Services segment margin increased to $189 million in the year ended December 31, 2012 from $185 million in 2011. Contract Services segment margin includes both revenues from external customers as well as intersegment revenues and is primarily based on revenue generating horsepower. Revenue generating horsepower, inclusive of intersegment revenue generating horsepower, increased to 919,000 as of December 31, 2012 from 846,000 as of December 31, 2011. The increase in revenue generating horsepower is primarily attributable to additional horsepower placed into service in south Texas for the Gathering and Processing segment to provide compression services to third party customers;

• Corporate segment margin increased to $20 million in the year ended December 31, 2012 from $17 million in the year ended December 31, 2011, which was primarily attributable to the increase in the management fee received from HPC beginning in April 2012; and

• Intersegment eliminations increased to $21 million in the year ended December 31, 2012 from $17 million in the year ended December 31, 2011. The increase was primarily due to an increase in transactions between Gathering and Processing and the Contract Services segments as a result of additional services provided in south Texas for the Gathering and Processing segment to provide compression and treating services to external customers.

Operation and Maintenance. Operation and maintenance expense increased to $228 million in the year ended December 31, 2012 from $147 million in the year ended December 31, 2011. The increase is primarily due to the following:

• $62 million increase as a result of the acquisition of SUGS;

• $8 million increase in employee expenses for organic growth projects in south and west Texas and an increase in employee headcount;

• $5 million increase in compressor maintenance costs primarily related to an increase in materials and maintenance costs; and

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• $5 million increase in ad valorem taxes primarily related to our organic growth projects.

General and Administrative. General and administrative expense increased to $100 million in the year ended December 31, 2012 from $67 million in the year ended December 31, 2011. This increase is primarily the result of the following:

• $37 million increase as a result of the acquisition of SUGS;

• $3 million decrease in professional fees associated with decreases in legal and consulting fees;

• $2 million increase in employee expenses, including primarily management incentive plan expenses and benefits; offset by

• $2 million decrease in office expenses related to lower rent expenses.

Depreciation and Amortization. Depreciation and amortization expense increased to $252 million in the year ended December 31, 2012 from $169 million in the year ended December 31, 2011, $51 million of which was related to the acquisition of SUGS. The remaining increase was the result of $13 million of additional depreciation and amortization expense due to the completion of various organic growth projects since December 2011, a $12 million increase related to the acceleration of depreciation and amortization of certain tangible and intangible assets that management determined had shorter economic useful lives, and a $7 million increase related to an “out-of-period” adjustment for all periods subsequent to May 26, 2010 (the “Successor” period) related to our Contract Services segment to adjust the estimated useful lives of certain assets to comply with our policy. The amounts associated with the out-of-period adjustment related to the year ended December 31, 2011 and to the period from May 26, 2010 to December 31, 2010 were $4 million and $3 million, respectively. Had these amounts been recorded to their respective period, the depreciation and amortization expense for the year ended December 31, 2012 and 2011 would have been $245 million and $173 million, respectively.

Income from Unconsolidated Affiliates. Income from unconsolidated affiliates decreased to $105 million for the year ended December 31, 2012 from $120 million for the year ended December 31, 2011. SUGS recorded an $8 million impairment related to its investment in Grey Ranch during 2012.

The schedule summarizes the components of income from unconsolidated affiliates and our ownership interest for the years ended December 31, 2012 and 2011, respectively:

	Year Ended December 31, 2012
	HPC			MEP			Lone Star			Ranch JV			Grey Ranch (1)			Total
Net income (loss)	$	70		$	83		$	147		(2		)	(18		)
Ownership interest	49.99		%	50		%	30		%	33.33		%	50		%
Share of unconsolidated affiliates’ net income (loss)	35			42			44			(1		)	(9		)
Less: Amortization of excess fair value of unconsolidated affiliates	(6		)	—			—			—			—
Income (loss) from unconsolidated affiliates	$	29		$	42		$	44		$	(1	)	$	(9	)	$	105
	Year Ended December 31, 2011
	HPC			MEP(2)			Lone Star(3)			Ranch JV(4)			Total
Net income	$	109		$	85		$	94		$	—
Ownership interest	49.99		%	50		%	30		%	33.33		%
Share of unconsolidated affiliates’ net income	55			43			28			—
Less: Amortization of excess fair value of unconsolidated affiliates	(6		)	—			—			—
Income from unconsolidated affiliates	$	49		$	43		$	28		$	—		$	120

_______________________

⁽¹⁾  Grey Ranch was acquired as part of the SUGS Acquisition in March 2012.

⁽²⁾  Ownership interest in MEP increased to 50% in September 2011 due to the purchase of an additional 0.1% interest.

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⁽³⁾  Represents Lone Star net income from May 2, 2011 (date of acquisition) to December 31, 2011.

⁽⁴⁾  We acquired a 33.33% membership interest in Ranch JV in December 2011.

HPC’s net income decreased to $70 million for the year ended December 31, 2012 from $109 million for the year ended December 31, 2011, primarily due to a $22 million non-cash asset impairment charge related to its surplus equipment acquired during the RIGS' 2009 Haynesville Expansion Project and not anticipated to be utilized in future expansion projects. In addition, HPC's margin decreased by $10 million year-over-year, mainly due to the expiration of certain contracts not renewed and lower throughput. Shippers who are choosing not to renew their contracts are primarily doing so because they hold excess firm transportation capacity out of the Haynesville shale.  This excess capacity is a result of moving drilling rigs out of the Haynesville area to richer gas plays, which has slowed supply growth and contributed to the decrease in throughput.

MEP's net income decreased to $83 million for the year ended December 31, 2012 from $85 million for the year ended December 31, 2011. Lone Star's net income increased to $147 million from $94 million, due to its net income in the prior year only reflecting the activity from initial contribution, May 2, 2011 to December 31, 2011.

The following table presents operational data for each of our unconsolidated affiliates for the years ended December 31, 2012 and 2011:

		Year Ended December 31,
		2012	2011
HPC	Throughput (MMBtu/d)	854,388	1,321,266
MEP	Throughput (MMBtu/d)	1,409,079	1,360,658
Lone Star	West Texas Pipeline – Total Volumes (Bbls/d)	134,274	130,246	(1)
	Refinery Services – Geismar Throughput (Bbls/d)	17,152	15,676	(1)
Ranch JV	Throughput (MMBtu/d) (2)	3,274	N/A

_______________________

(1) All of Lone Star’s operational volumes represent the period from May 2, 2011 (acquisition date) to December 31, 2011.

(2) Ranch JV began operations in June 2012.

N/A:    We acquired a 33.33% membership interest in Ranch JV in December 2011.

Interest Expense, net. Interest expense, net increased to $122 million in the year ended December 31, 2012 from $103 million in the year ended December 31, 2011. The increase was primarily attributable to a full year of interest associated with the $500 million 2021 Notes issued in May 2011 as well as three months of interest associated with the $700 million 2023 Notes issued in October 2012.

Other Income and Deductions, net. Other income and deductions, net increased to a $29 million gain in the year ended December 31, 2012 from a $17 million gain in the year ended December 31, 2011 primarily due to a $16 million one-time producer payment received in March 2012 related to an assignment of certain contracts, offset by a decrease in the non-cash mark-to-market gain in the embedded derivative related to the Series A Preferred Units.

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Year Ended December 31, 2011 vs. Combined Year Ended December 31, 2010

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

				Combined Year Ended December 31, 2010
	Successor						Predecessor
	Year Ended December 31, 2011			Period from Acquisition (May 26,  2010) to  December 31, 2010			Period from January 1, 2010 to May 25, 2010			Combined Year Ended December 31, 2010			Change			Percent
Total revenues	$	1,434		$	716		$	505		$	1,221		$	213		17	%
Cost of sales	1,013			504			358			862			151			17
Total segment margin (1)	421			212			147			359			62			17
Operation and maintenance	147			78			48			126			21			18
General and administrative	67			44			37			81			(14		)	17
Gain on asset sales, net	(2		)	—			—			—			(2		)	100
Depreciation and amortization	169			76			42			118			51			43
Operating income	40			14			20			34			6			18
Income from unconsolidated subsidiaries	120			54			16			70			50			72
Interest expense, net	(103		)	(48		)	(35		)	(83		)	(20		)	24
Loss on debt refinancing, net	—			(16		)	(2		)	(18		)	18			100
Other income and deductions, net	17			(8		)	(4		)	(12		)	29			243
Income (loss) from continuing operations before income taxes	74			(4		)	(5		)	(9		)	83			983
Income tax expense	—			1			—			1			(1		)	51
Net income (loss) from continuing operations	74			(5		)	(5		)	(10		)	84			888
Discontinued operations	—			(1		)	—			(1		)	1			100
Net income (loss)	$	74		$	(6	)	$	(5	)	$	(11	)	$	85		774
Net income attributable to the noncontrolling interest	(2		)	—			—			—			(2		)	100
Net income (loss) attributable to Regency Energy Partners LP	$	72		$	(6	)	$	(5	)	$	(11	)	$	83		731	%
Gathering and processing segment margin	$	233		$	110		$	86		$	196		$	37		19	%
Non-cash loss from commodity derivatives	—			23			7			30			(30		)	100
Adjusted gathering and processing segment margin	$	233		$	133		$	93		$	226		$	7		3
Natural gas transportation segment margin	3			3			1			4			(1		)	25
Contract services segment margin (2)	185			103			62			165			20			12
Corporate segment margin	17			10			7			17			—			—
Intersegment eliminations (2)	(17		)	(14		)	(9		)	(23		)	6			26
Adjusted total segment margin	$	421		$	235		$	154		$	389		$	32		8	%

 _______________________

(1) For reconciliation of segment margin to the most directly comparable financial measure calculated and presented in accordance with GAAP, read “Item 6. Selected Financial Data.”

(2) Contract Services segment margin includes intersegment revenues of $17 million and $23 million for the years ended December 31, 2011 and 2010 respectively. These intersegment revenues were eliminated upon consolidation.

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Net (Loss) Income Attributable to Regency Energy Partners LP. Net income (loss) attributable to Regency Energy Partners LP increased to a net income of $72 million in the year ended December 31, 2011 from a net loss of $11 million in the year ended December 31, 2010. The major components of this change were as follows:

• $62 million increase in total segment margin mainly due to increased volumes in south Texas and a full year of treating services within our Contract Services segment margin, which were acquired in September 2010;

• $50 million increase in income from unconsolidated affiliates primarily from our acquisitions of a 49.9% interest in MEP in May 2010 and a 30% interest in Lone Star in May 2011;

• $29 million increase in other income and deductions, net due to the non-cash gain on the embedded derivatives related to the Series A Preferred Units;

• the absence of an $18 million redemption premium paid in 2010 and recorded as a loss on debt refinancing, net;

• $14 million decrease in general and administrative expenses primarily due to the absence of a $10 million one-time charge of unit-based compensation expense in 2010 related to the vesting of outstanding LTIP grants upon the acquisition of our General Partner by ETE; offset by

• $51 million increase in depreciation and amortization expense primarily related to additional assets placed in service during 2011 and a full year of depreciation related to the fair value adjustment of our long-lived assets upon the acquisition of our General Partner;

• $21 million increase in operations and maintenance expense primarily due to increased compression and pipeline maintenance as well as a full year of operations of treating services within our Contract Services segment, which were acquired in September 2010; and

• $20 million increase in interest expense, net, primarily related to the interest associated with the $500 million 2021 Notes issued in May 2011 to partially fund the acquisition of our 30% interest in Lone Star as well as a full year of interest associated with the $600 million 2018 Notes issued in October 2010.

Adjusted Total Segment Margin. Adjusted total segment margin increased to $421 million in the year ended December 31, 2011 from $389 million in the year ended December 31, 2010. The major components of this change were as follows:

• Adjusted Gathering and Processing segment margin increased to $233 million for the year ended December 31, 2011 from $226 million for the year ended December 31, 2010 primarily due to the increased volumes in the Eagle Ford shale in south Texas and Permian Delaware Basin in west Texas. Total Gathering and Processing segment throughput increased to 1,187,000 MMBtu/d during the year ended December 31, 2011 from 996,800 MMBtu/d during the year ended December 31, 2010. Total NGL gross production increased to 32,000 Bbls/d during the year ended December 31, 2011 from 26,000 Bbls/d during the year ended December 31, 2010;

• Contract Services segment margin increased to $185 million in the year ended December 31, 2011 from $165 million in the year ended December 31, 2010. The increase was primarily attributable to the increased revenue generating horsepower provided to third parties as well as a full year of margin contributed from our treating services, which were acquired in September 2010. As of December 31, 2011, total revenue generating horsepower was 846,000, compared to 845,000 as of December 31, 2010; and

• Intersegment eliminations decreased to $17 million in the year ended December 31, 2011 from $23 million in the year ended December 31, 2010. The decrease was due to decreased intersegment transactions between the Gathering and Processing and the Contract Compression segment as a result of the transfer of certain compression units from the Contract Compression segment to the Gathering and Processing segment in the second quarter of 2011.

Operation and Maintenance. Operation and maintenance expense increased to $147 million in the year ended December 31, 2011 from $126 million in the year ended December 31, 2010. The increase is primarily due to the following:

• $7 million increase in compressor maintenance costs primarily related to an increase in lube oil and materials costs;

• $6 million increase in pipeline maintenance expenses in our Gathering and Processing segment;

• $3 million increase in employee expenses primarily due to higher short-term incentive compensation accrual;

• $3 million increase in plant operating expenses primarily related to our contract treating services within our Contract Services segment, which was acquired in September 2010; and

• $2 million increase in consumable products.

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General and Administrative. General and administrative expense decreased to $67 million in the year ended December 31, 2011 from $81 million in the year ended December 31, 2010. This increase is primarily due to the following:

• $13 million decrease in employee costs primarily due to the shared services integration and resulting reduction in headcount; and

• the absence of $10 million one-time charge in unit-based compensation primarily related to the vesting of outstanding LTIP grants upon the acquisition of our General Partner by ETE in May 2010; offset by

• $11 million increase in related party general and administrative expenses for the services agreements with Services Co. and ETC.

Depreciation and Amortization. Depreciation and amortization expense increased to $169 million in the year ended December 31, 2011 from $118 million in the year ended December 31, 2010. This increase was the result of $35 million of additional depreciation and amortization expense due to the completion of various organic growth projects since December 2010 and a $9 million increase related to our treating assets within the Contract Services segment that we acquired in September 2010. Additionally, there was a $8 million increase in depreciation and amortization expense incurred related to the increase of property, plant and equipment amounts resulting from the fair value adjustments upon the change in control resulting from the acquisition of our General Partner in May 2010. Had the change in control occurred on January 1, 2010, our depreciation and amortization expense on a pro forma basis for the combined year ended December 31, 2010 would have been $125 million.

Income from Unconsolidated Affiliates. Income from unconsolidated affiliates increased to $120 million for the year ended December 31, 2011 from $70 million for the year ended December 31, 2010. The schedule summarizes the components of income from unconsolidated affiliates and our ownership interest for the years ended December 31, 2011 and 2010, respectively:

	Year Ended December 31, 2011
	HPC			MEP			Lone Star(4)			Total
Net income	$	109		$	85		$	94
Ownership interest	49.99		%	50%(1)			30		%
Share of unconsolidated affiliates’ net income	55			43			28
Less: Amortization of excess fair value of unconsolidated affiliates	(6		)	—			—
Income from unconsolidated affiliates	$	49		$	43		$	28		$	120
	Year Ended December 31, 2010
	HPC			MEP(2)			Lone Star			Total
Net income	$	107		$	43		N/A
Ownership interest	48.3%(3)			49.9		%	N/A
Share of unconsolidated affiliates’ net income	51			22			N/A
Less: Amortization of excess fair value of unconsolidated affiliates	(3		)	—			N/A
Income from unconsolidated affiliates	$	48		$	22		N/A			$	70

_______________________

(1) Ownership interest in MEP increased to 50% in September 2011 due to the purchase of an additional 0.1% interest.

(2) Represents the MEP net income from May 26, 2010 (date of acquisition) to December 31, 2010.

(3) Ownership interest in HPC increased from 43% to 49.99% on April 30, 2010.

(4) Represents Lone Star net income from May 2, 2011 (date of acquisition) to December 31, 2011.

N/A:    We acquired a 30% membership interest in Lone Star on May 2, 2011.

HPC’s net income increased to $109 million for the year ended December 31, 2011 from $107 million for the year ended December 31, 2010, primarily due to higher throughput in 2010. Throughput increased to 1,321,000 MMBtu/d for the year ended December 31, 2011 from 1,278,000 MMBtu/d for the year ended December 31, 2010.

MEP’s net income increased to $85 million for the year ended December 31, 2011 from $43 million for the period from May 26, 2010 (acquisition date) to December 31, 2010, primarily due to reporting a full year of operations.

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The following table presents operational data for each of our unconsolidated affiliates for the years ended December 31, 2011 and 2010:

		Year Ended December 31,
		2011		2010
HPC	Throughput (MMBtu/d)	1,321,266		1,277,881
MEP	Throughput (MMBtu/d)	1,360,658		1,408,778	(2)
Lone Star	West Texas Pipeline – Total Volumes (Bbls/d)	130,246	(1)	N/A
	Refinery Services – Geismar Throughput (Bbls/d)	15,676	(1)	N/A

_______________________

(1) All of Lone Star’s operational volumes represent the period from May 2, 2011 (acquisition date) to December 31, 2011.

(2) Despite the decrease in throughput, MEP’s revenues remained relatively stable throughout the period, because almost all of MEP’s revenues are derived from firm transportation contracts with fixed fees.

N/A: We acquired a 30% membership interest in Lone Star on May 2, 2011.

Interest Expense, Net. Interest expense, net increased to $103 million in the year ended December 31, 2011 from $83 million in the year ended December 31, 2010. The increase was primarily attributable to interest associated with the $500 million 2021 Notes issued in May 2011 and a full year of interest associated with the $600 million 2018 Notes issued in October 2010.

Other Income and Deductions, net. Other income and deductions, net increased to a $17 million gain in 2011 from a $12 million loss in 2010 primarily due to the non-cash value change in the embedded derivatives related to the Series A Preferred Units issued in September 2009.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

We expect our sources of liquidity will include:

• cash generated from operations and occasional asset sales;

• borrowings under our revolving credit facility;

• distributions received from unconsolidated affiliates;

• debt offerings; and

• issuance of additional partnership units.

We expect our 2013 capital expenditures, including capital contributions to our unconsolidated affiliates, to be as follows (in millions):

	2013
Growth Capital Expenditures
Gathering and Processing segment	$	465
NGL Services segment	175
Contract Services segment	160
Total	$	800
Maintenance Capital Expenditures, including our proportionate share related to our unconsolidated affiliates	$	45

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

Working Capital (Deficit) Surplus. Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our obligations as they become due. When we incur growth capital expenditures, we may experience working capital deficits as we fund construction expenditures out of working capital until they are permanently financed. Our working

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

Our working capital deficitincreased to $149 million at December 31, 2012 from a deficit of $47 million at December 31, 2011. This increase was primarily due to the following:

• an increase of $22 million in trade accounts payable net of trade accounts receivable, primarily due to the timing of payments and accruals for operating expenses and capital projects;

• an increase of $45 million in other current liabilities, net of other current assets $41 million of which is related to the acquisition of SUGS;

• an increase of $82 million in related party payables, $64 million of which is related to the acquisition of SUGS and an accrual of $23 million capital contribution to Lone Star; offset by

• an increase of $52 million in cash and cash equivalents, primarily due to the capital contributions to ELG from its joint venture partners to fund its capital expansion projects.

Cash Flows from Discontinued Operations. We combined the cash flows from discontinued operations with the cash flows from continuing operations. The cash flows from discontinued operations related to our operating, investing and financing activities were insignificant. We do not expect the absence of cash flows from these discontinued operations will have a significant impact on our future liquidity.

Cash Flows from Operating Activities. Net cash flows provided by operating activities increased to $324 million in the year ended December 31, 2012 from $254 million in the year ended December 31, 2011. The increase was primarily due to the acquisition of SUGS. Net cash flows provided by operating activities increased to $254 million in the year ended December 31, 2011 from $169 million in the year ended December 31, 2010.

For all periods, we used our cash flows from operating activities together with borrowings under our credit facility to fund our working capital requirements, which include operation and maintenance expenses, maintenance capital expenditures and repayment of working capital borrowings. From time to time during each period, the timing of receipts and disbursements require us to borrow under our revolving credit facility.

Cash Flows used in Investing Activities. Net cash flows used in investing activities decreased to $807 million in the year ended December 31, 2012 from $955 million in the year ended December 31, 2011, which was primarily due to larger capital contributions made to Lone Star in 2011, and $124 million in capital expenditures by SUGS in 2012.

Net cash flows used in investing activities increased to $955 million in the year ended December 31, 2011 from $445 million in the year ended December 31, 2010. The increase was primarily due to the acquisition of a 30% interest in Lone Star in May 2011 for $594 million, offset by an increase in distributions in excess of earnings of unconsolidated affiliates of $15 million.

Growth Capital Expenditures. Growth capital expenditures are capital expenditures made to acquire additional assets to increase our business, to expand and upgrade existing systems and facilities or to construct or acquire similar systems or facilities. In the year ended December 31, 2012, we incurred $945 million of growth capital expenditures. Growth capital expenditures for the year ended December 31, 2012 consisted of $476 million for organic growth projects in our Gathering and Processing segment; $318 million for organic growth projects of Lone Star in NGL Services segment; and $151 million for the fabrication of new compressor packages and new treating plants for our Contract Services segment.

Maintenance Capital Expenditures. Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets or to maintain the existing operating capacity of our assets and extend their useful lives. In the year ended December 31, 2012 and 2011, we incurred $58 million and $22 million, respectively, of maintenance capital expenditures, including our proportionate share related to unconsolidated affiliates.

Cash Flows from Financing Activities. Net cash flows provided by financing activities decreased to $535 million in the year ended December 31, 2012 from $693 million in the year ended December 31, 2011. The decrease was primarily due to a decrease in proceeds from common unit offerings of $124 million, an $88 million senior notes redemption in 2012, and an increase in partner distributions of $48 million.

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Net cash flows provided by financing activities increased to $693 million in the year ended December 31, 2011 from $275 million in the year ended December 31, 2010. The increase was primarily due to the following:

• the absence in 2011 of $358 million related to the redemption of our 2013 Senior Notes;

• a net increase in our revolving credit facility borrowings of $182 million; partially offset by

• an increase in Partner distributions of $70 million.

Capital Resources

Description of Our Indebtedness. As of December 31, 2012, our aggregate outstanding indebtedness totaled $2.16 billion and consisted of $192 million borrowings under our revolving credit facility and $1.97 billion of outstanding senior notes as compared to our aggregate outstanding indebtedness as of December 31, 2011, which totaled $1.69 billion and consisted of $332 million in borrowings under our revolving credit facility and $1.36 billion of outstanding senior notes.

Revolving Credit Facility. In May 2013, RGS entered into the Sixth Amended and Restated 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 and Sixth Amended and Restated 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.

The new credit agreement and the guarantees are senior to the Partnership's and the guarantors' secured obligations, including the Series A Preferred Units, to the extent of the value of the assets securing such obligations. As of June 30, 2013, the Partnership was in compliance with all of the financial covenants contained within the new credit agreement.

The Partnership treated the May 2013 amendment of the revolving credit facility as a modification of an existing revolving credit agreement and, therefore, wrote off debt issuance costs of $1 million to interest expense, net in the period from January 1, 2013 to June 30, 2013. In addition, the Partnership capitalized $7 million of loan fees which will be amortized over the remaining term.

Borrowings under our revolving credit facility are secured by substantially all of our assets and are guaranteed by us and our subsidiaries. The revolving credit facility and the guarantees are senior to the Partnership’s and the other guarantor’s unsecured obligations.

The outstanding balance under the revolving credit facility bears interest at LIBOR plus a margin or alternate base rate (equivalent to the U.S. prime 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 0.625% to 1.50% for base rate loans, 1.625% to 2.50% for Eurodollar loans.

We pay (i) a commitment fee ranging from 0.30% to 0.45% 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 1.625% to 2.50% 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.

The revolving credit facility contains financial covenants requiring RGS and its subsidiaries to maintain a debt to consolidated EBITDA (as defined in the credit agreement) ratio less than 5.00 for the first eight quarters (after March 2015, an increase is allowed in the permitted total leverage ratio for the first two fiscal quarters following any $50 million or greater acquisition), 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, 2012 and 2011, RGS and its subsidiaries were in compliance with these covenants.

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The revolving credit facility restricts the ability of RGS to pay dividends and distributions other than reimbursements of the Partnership for expenses and payment of dividends to the Partnership to the amount of available cash (as defined) so long as no default or event of default has occurred or is continuing. The revolving credit facility 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 transaction documents (as defined in the revolving credit facility);

• 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 revolving credit facility or reasonable extensions thereof.

Senior Notes due 2016. In May 2009, we and Finance Corp. issued $250 million of senior notes that mature on June 1, 2016 (“2016 Notes”). The 2016 Notes bear interest at 9.375% with interest payable semi-annually in arrears on June 1 and December 1. The net proceeds were used to partially repay loans under our revolving credit facility. In May 2012, we redeemed 35%, or $88 million of the 2016 Notes, bringing the total outstanding balance to $163 million.

In June 2013, the Partnership redeemed all of the $163 million outstanding 9.375% 2016 Senior Notes for $178 million cash, inclusive of accrued and unpaid interest of $7 million and other fees and expenses.

Senior Notes due 2018. In October 2010, we and Finance Corp. issued $600 million of senior notes that mature on December 1, 2018 (“2018 Notes”). The 2018 Notes bear interest at 6.875% paid semi-annually in arrears on June 1 and December 1, commencing June 1, 2011. The proceeds were used to redeem the senior notes due 2013 and to partially repay outstanding borrowings under the revolving credit facility.

At any time before December 1, 2013, up to 35% of the 2018 Notes can be redeemed at a price of 106.875% of the principal amount plus accrued interest. Beginning December 1 of the years indicated below, we may redeem all or part of these notes at the redemption prices, expressed as percentages of the principal amount, set forth below:

December 1 of year ending:	Percentage of Redemption
2014	103.438%
2015	101.719%
2016 and thereafter	100.000%

At any time prior to December 1, 2014, we may also redeem all or part of the notes at a price equal to 100% of the principal amount of notes redeemed plus accrued interest and the applicable premium, which equals to the greater of (1) 1% of the principal amount of the note; or (2) the excess of the present value at such redemption date of (i) the redemption price of the note at December 1, 2014 plus (ii) all required interest payments due on the note through December 1, 2014, computed using a discount rate equal to the treasury rate (as defined) as of such redemption date plus 50 basis points, over the principal amount of the note.

Senior Notes due 2021. In May 2011, we and Finance Corp. issued $500 million of senior notes that mature on July 15, 2021 (“2021 Notes”). The 2021 Notes bear interest at 6.5% paid semi-annually in arrears on January 15 and July 15, commencing on January 15, 2012. The proceeds were used to pay down the balance on our revolving credit facility.

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

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

At any time prior to July 15, 2016, we may also redeem all or part of the notes at a price equal to 100% of the principal amount of notes redeemed plus accrued interest and the applicable premium, which equals to the greater of (1) 1% of the principal amount of the note; or (2) the excess of the present value at such redemption date of (i) the redemption price of the note at July 15, 2016 plus (ii) all required interest payments due on the note through July 15, 2016, computed using a discount rate equal to the treasury rate (as defined) as of such redemption date plus 50 basis points, over the principal amount of the note.

Senior Notes due 2023. In October 2012, we and Finance Corp. issued $700 million of senior notes that mature on April 15, 2023 (“2023 Notes”). The 2023 Notes bear interest at 5.5% paid semi-annually in arrears on April 15 and October 15, commencing on April 15, 2013. The proceeds were used to pay down the balance on our revolving credit facility.

At any time prior to October 15, 2015, we may redeem up to 35% of the 2023 Notes at a price equal to 105.5% of the principal amount plus accrued interest. Beginning on October 15 of the years indicated below, we may redeem all or part of the 2023 Notes at the redemption prices, expressed as percentages of the principal amount, set forth below:

July 15 of year ending:	Percentage of Redemption
2017	102.750%
2018	101.833%
2019	100.917%
2020 and thereafter	100.000%

At any time prior to October 15, 2017, we may also redeem all or part of the notes at a price equal to 100% of the principal amount of notes redeemed plus accrued interest and the applicable premium, which equals to the greater of (1) 1% of the principal amount of the note; or (2) the excess of the present value at such redemption date of (i) the redemption price of the note at October 15, 2017 plus (ii) all required interest payments due on the note through October 15, 2017, computed using a discount rate equal to the treasury rate (as defined) as of such redemption date plus 50 basis points, over the principal amount of the note.

Private Placement of Senior Notes due 2023. In April 2013, in conjunction with the closing of the SUGS Acquisition, the Partnership and Finance Corp. issued $600 million senior notes in a private placement (the “2023 4.5% Notes”) pursuant to Section 4(2) of the Securities Act. The 2023 4.5% Notes bear interest at 4.5% payable semi-annually in arrears on May 1 and November 1, commencing November 1, 2013 and the 2023 4.5% Notes mature on November 1, 2023.

At any time prior to August 1, 2023, we may redeem some or all of the 2023 4.5% Notes at a price equal to 100% of the principal amount plus a make-whole premium and accrued interest. On or after August 1, 2023, we may redeem some or all of the 2023 4.5% Notes at a price equal to 100% plus accrued interest.

Upon a change of control, as defined in the indenture, followed by a ratings decline within 90 days, each holder of the 2023 4.5% Notes will be entitled to require us to purchase all or a portion of its notes at a purchase price of 101% of the principal amount plus accrued interest and liquidated damages, if any. Our ability to purchase the notes upon a change of control will be limited by the terms of our debt agreements, including our revolving credit facility.

The 2023 4.5% Notes contain various covenants that limit, among other things, our ability, and the ability of certain of our subsidiaries, to:

• incur additional indebtedness;

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

• make certain investments;

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• incur liens;

• enter into certain types of transactions with affiliates; and

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

If the 2023 4.5% Notes achieve investment grade ratings by both Moody's and S&P and no default or event or default has occurred and is continuing, we will no longer be subject to many of the foregoing covenants.

The 2023 4.5% Notes are jointly and severally guaranteed by all of our consolidated subsidiaries, other than Finance Corp. and a minor subsidiary. PEPL Holdings provided a guarantee of collection with respect to the payment of the principal amounts of the senior notes issued by us. The senior notes and the guarantees are unsecured and rank equally with all of our and the guarantors' existing and future unsecured obligations. The senior notes and the guarantees will be senior in right of payment to any of our and the guarantor's future obligations that are, by their terms, expressly subordinated in right of payment to the notes and the guarantees. The senior notes and the guarantees will be effectively subordinated to our and the guarantors' secured obligations, including our revolving credit facility, to the extent of the value of the assets securing and obligations.

Senior Notes Covenants. Upon a change of control, as defined in the indenture, followed by a rating decline within 90 days, each holder of the 2018 Notes, 2021 Notes, 2023 Notes, and the 2023 4.5% Notes (collectively “Senior Notes”), will be entitled to require us to purchase all or a portion of its notes at a purchase price of 101% of the principal amount plus accrued interest and liquidated damages, if any. Our ability to purchase the notes upon a change of control will be limited by the terms of our debt agreements, including our revolving credit facility.

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

• incur additional indebtedness;

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

• make certain investments;

• incur liens;

• enter into certain types of transactions with affiliates; and

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

If the Senior Notes achieve investment grade ratings by both Moody’s and S&P and no default or event of default has occurred and is continuing, we will no longer be subject to many of the foregoing covenants. At December 31, 2012, we were in compliance with these covenants.

All of the Senior Notes are jointly and severally guaranteed by all of our consolidated subsidiaries, other than Finance Corp. and a minor subsidiary. The Senior Notes and the guarantees are unsecured and rank equally with all of our and the guarantors’ existing and future unsecured obligations. The Senior Notes and the guarantees will be senior in right of payment to any of our and the guarantors’ future obligations that are, by their terms, expressly subordinated in right of payment to the notes and the guarantees. The Senior Notes and the guarantees will be effectively subordinated to our and the guarantors’ secured obligations, including our revolving credit facility, to the extent of the value of the assets securing such obligations.

Equity Offerings. In April 2013, we issued 31,372,419 and 6,274,483 common and Class F common units, respectively, to Southern Union as part of the SUGS Acquisition. In March 2012, we 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, we used the net proceeds from this offering to redeem 35% of our outstanding senior notes due 2016; pay related premium, expenses and accrued interest; and repay outstanding borrowings under the revolving credit facility.

In October 2011, we sold 11,500,000 common units in an underwritten public offering, and received $232 million in proceeds. In May 2011, we issued 8,500,001 common units representing limited partnership interests resulting in net proceeds of $204 million, to partially fund our capital contribution to Lone Star. These units were issued in a private placement conducted in accordance with the exemption from the registration requirements of the Securities Act of 1933, as amended, under section 4(2) thereof. These units were subsequently registered with the SEC.

Equity Distribution Agreement. In June 2012, we entered into an Equity Distribution Agreement with Citi under which we may offer and sell common units, representing limited partner interests, having an aggregate offering price of up to $200 million, from time to time through Citi, as sales agent for us. Sales of these units, if any, 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

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transactions, or as otherwise agreed upon by us and Citi. We may also sell common units to Citi as principal for our own account at a price agreed upon at the time of sale. Any sale of common units to Citi as principal would be pursuant to the terms of a separate agreement between us and Citi. We intend to use the net proceeds from the sale of these units for general partnership purposes. As of December 31, 2012 and June 30, 2013, we received net proceeds of $15 million and $128 million, respectively, from units issued pursuant to this Equity Distribution Agreement.

Cash Distributions from Unconsolidated Affiliates. The following table summarizes the cash distributions from unconsolidated affiliates for the year ended December 31, 2012 and 2011:

	Successor						Predecessor
	Year ended December 31,				Period from Acquisition (May 26, 2010) to December 31, 2010		Period from January 1, 2012 to May 25, 2010
	2012		2011
HPC	$	61	$	65	$	53	$	12
MEP	75		83		43		N/A
Lone Star	68		22		N/A		N/A

Contractual Obligations. The following table summarizes our total contractual cash obligations as of December 31, 2012:

	Payments Due By Period
Contractual Obligations	Total		Less than 1 year		1-3 years		3-5 years		More than 5  years
Long-term debt (including interest) (1)	$	3,158	$	137	$	443	$	395	$	2,183
Operating leases	50		6		6		4		34
Purchase obligations (2)	402		149		70		76		107
Distributions and redemption of Series A Preferred Units (3)	153		6		7		7		133
Capital contribution commitments to unconsolidated affiliate (4)	1		1		—		—		—
Other	39		5		8		10		16
Total (5)	$	3,803	$	304	$	534	$	492	$	2,473

  _______________________

(1) Assumes a constant LIBOR interest rate of 0.843% plus applicable margin (2.50% as of December 31, 2012) for our revolving credit facility. The principal of our outstanding senior notes ($1.96 billion) bears a weighted average fixed rate of 6.5%.

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

(3) Assumes that the Series A Preferred Units are redeemed for cash on September 2, 2029, and an annual distribution of $8 million. In July 2013, the Partnership was notified by two of the Series A Preferred Units holders of their election to convert their Series A Preferred Units to common units; these holders owned 2.4 million Series A Preferred Units and were excluded from the calculation above.

(4) Includes committed capital contributions to Ranch JV.

(5) Excludes deferred tax liabilities of $22 million as the amount payable by period cannot be readily estimated in light of net operating loss carryforwards and future business plans for the entity that generated the deferred tax liability.

OTHER MATTERS

Legal. We are involved in various claims, proceedings, lawsuits and audits by taxing authorities incidental to our business. These claims and lawsuits in the aggregate are not expected to have a material adverse effect on our business, financial condition, results of operations or cash flows.

Environmental Matters. For information regarding environmental matters, please read “Item 1. Business-Regulation-Environmental Matters,” as well as “Footnote 12. Commitments and Contingencies.”

23

IRS Audits. The IRS commenced audits of our 2007 and 2008 federal income tax returns on January 27, 2010. The IRS has now completed its audit of these returns and proposed certain adjustments.  We have filed a protest with the IRS to initiate the appeals process and appeal certain of these adjustments. Until this matter is fully resolved, we do not know whether any amounts ultimately recorded would be material, or how such adjustments would affect unitholders. The IRS is also conducting an audit of the 2007 through 2009 tax returns of one of our wholly owned subsidiaries and has proposed certain adjustments. The subsidiary has filed a protest with the IRS.

The statute of limitations for each of these audits has been extended to December 31, 2014. We, through our tax matters partner (our General Partner) and our tax advisers, will cooperate with the IRS examiners auditing these returns. Unitholders should consult their tax advisers if they have any questions.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could be different from those estimates.

The critical judgment areas in the application of our accounting policies that currently affect our financial condition and results of operations are as follows:

Revenue and Cost of Sales Recognition. We record revenue and cost of gas and NGLs on the gross basis for those transactions where we act as the principal and take title to gas that we purchase for resale. When our customers pay us a fee for providing a service such as gathering or transportation we record the fees separately in revenues. We estimate certain revenue and expenses since actual amounts are not confirmed until after the financial closing process due to the standard settlement dates in the gas industry. We calculate estimated revenues using actual pricing and measured volumes. In the subsequent production month, we reverse the accrual and record the actual results. Prior to the settlement date, we record actual operating data to the extent available, such as actual operating and maintenance and other expenses. We do not expect actual results to differ materially from our estimates.

Purchase Method of Accounting. We make various assumptions in developing models for determining the fair values of assets and liabilities associated with business acquisitions. These fair value models, developed with the assistance of outside consultants, apply discounted cash flow approaches to expected future operating results, considering expected growth rates, development opportunities, and future pricing assumptions, to arrive at an economic value for the business acquired. We then determine the fair value of the tangible assets based on estimates of replacement costs less obsolescence. Identifiable intangible assets acquired consist primarily of customer relations and trade names. We value customer relations as the fair value of avoided customer churn costs compared to industry norms. We value trade names using the avoided royalty payment approach. We determine the value of liabilities assumed based on their expected future cash outflows. We record goodwill as the excess of the purchase price of each business unit over the sum of amounts allocated to the tangible assets and separately recognized intangible assets acquired, less liabilities assumed by the business unit.

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 ours at their historical amounts. If any cash consideration transferred in such a transaction exceeds the carrying value of the net assets acquired, the excess is treated a s a capital transaction with our general partner, similar to a dividend. If the carrying value of the net assets acquired exceeds any cash consideration transferred and limited partner units are also issued as consideration, then the limited partner units are recorded at an amount equal to the excess of the carrying value of the net assets acquired over any cash consideration transferred. To the extent that such transactions require prior periods to be recast, historical net equity amounts prior to the transaction date are reflected as predecessor equity.

Goodwill. We review the carrying value of goodwill on an annual basis or on an as needed basis, for indicators of impairment at each reporting unit that has recorded goodwill. We determine our reporting units based on identifiable cash flows of a reporting unit and how reporting unit managers evaluate the results of operations of the entity. Impairment is indicated whenever the carrying value of a reporting unit exceeds the estimated fair value of a reporting unit. We first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether further impairment testing is necessary. For purposes of evaluating impairment of goodwill, we estimate the fair value of a reporting unit based upon future net discounted cash flows. In calculating these estimates, historical operating results and anticipated future economic factors, such as estimated volumes and demand for services, commodity prices, and operating costs are considered as a component of the calculation of future discounted cash flows. Further, the discount rate requires estimates of the cost of equity and debt financing. The estimates of fair value of these reporting units could change if actual volumes, prices, costs or discount rates vary from these estimates.

24

Equity Method Investments. The equity method of accounting is used to account for our interest in investments of greater than 20% voting stock or where we exert significant influence over an investee and lack control over the investee.

Depreciation Expense, Cost Capitalization and Impairment. Our assets consist primarily of natural gas gathering pipelines, processing plants, transmission pipelines, treating equipment, and natural gas compression equipment. We capitalize all construction-related direct labor and material costs, as well as indirect construction costs. Indirect construction costs include general engineering costs and the costs of funds used in construction. Capitalized interest represents the cost of funds used to finance the construction of new facilities and is expensed over the life of the constructed asset through the recording of depreciation expense. We capitalize the costs of renewals and betterments that extend the useful life, while we expense the costs of repairs, replacements and maintenance projects as incurred.

We generally compute depreciation using the straight-line method over the estimated useful life of the assets. Certain assets such as land, NGL line pack and natural gas line pack are non-depreciable. The computation of depreciation expense requires judgments regarding the estimated useful lives and salvage value of assets. As circumstances warrant, we review depreciation estimates to determine if any changes are needed. Such changes could involve an increase or decrease in estimated useful lives or salvage values, which would impact future depreciation expense.

We review long-lived assets for impairment whenever events or changes in circumstances indicate that the related carrying amounts may not be recoverable. Determining whether an impairment has occurred typically requires various estimates and assumptions, including determining which undiscounted cash flows are directly related to the potentially impaired asset, the useful life over which cash flows will occur, their amount, and the asset’s residual value, if any. In turn, measurement of an impairment loss requires a determination of fair value, which is based on the best information available. We derive the required undiscounted cash flow estimates from our historical experience and our internal business plans. To determine fair value, we use our internal cash flow estimates discounted at an appropriate interest rate, quoted market prices when available and independent appraisals, as appropriate.

Equity Based Compensation. Restricted units are valued at the grant date closing price of the Partnership’s common units. Phantom units are issued as either service condition awards (also defined as “time-based awards” in the LTIP plan) or market condition awards (also defined as “performance-based awards” in the LTIP plan). For service condition awards, the grant date fair value equals the grant date closing price of the Partnership’s common units. For the market condition awards, we performed a Monte Carlo simulation that incorporated variables such as unit price volatility, merger and acquisition activity within the peer group, changes in credit ratings of the peer group members, and employee turnover. The grant date closing price of the Partnership’s common units is also a factor in determining the grant-date fair value of the market condition awards.

Fair Value Measurements. Financial assets and liabilities, goodwill, indefinite-lived intangible assets, property, plant and equipment and asset retirement obligations are valued using 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.

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

RECENT ACCOUNTING PRONOUNCEMENTS

See discussion of new accounting pronouncements in Note 2 in the Notes to the Consolidated Financial Statements.

25

Item 7A. Quantitative and Qualitative Disclosure about Market Risk

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

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

We have swap contracts that settle against NGLs (propane, butane, and natural gasoline), condensate and natural gas market prices.

The following table sets forth certain information regarding our hedges outstanding at December 31, 2012. The relevant index price that we pay for NGLs is the monthly average of the daily closing price for deliveries of commodities into Mont Belvieu, Texas, as reported by the Oil Price Information Service (OPIS). The relevant index price for natural gas is NYMEX on the pricing dates as defined by the swap contracts. The relevant index for WTI is the monthly average of the daily price of WTI as reported by the NYMEX.

December 31, 2012
Period	Underlying	Notional Volume/ Amount		We Pay	We Receive Weighted Average Price		Fair Value Asset/(Liability)		Effect of Hypothetical Change in Index*
							(in millions)
January 2013-December 2013	Propane	79	(MBbls)	Index	1.03	($/gallon)	1		1
January 2013-December 2014	Normal Butane	236	(MBbls)	Index	1.62	($/gallon)	—		2
January 2013-March 2013	Natural Gasoline	7	(MBbls)	Index	2.27	($/gallon)	—		—
January 2013-December 2014	West Texas Intermediate Crude	356	(MBbls)	Index	99.47	($/Bbl)	2		3
January 2013-December 2014	Natural Gas	8,395,000	(MMBtu)	Index	3.87	($/MMBtu)	1		3
					Total Fair Value		$	4

 _______________________

* Price risk sensitivities were calculated assuming a theoretical 10% change in prices regardless of term or historical relationships between the contractual price of the instrument and the underlying commodity price. Interest rate sensitivity assumes a 100 basis point increase or decrease in the LIBOR yield curve. The price sensitivity results are presented in absolute terms.    

Additionally, SUGS had outstanding at December 31, 2012 receive-fixed natural gas price swaps, accounted for as cash flow hedges, with a total notional amount of 4,562,000 MMBtu. As of April 30, 2013, in connection with our acquisition of SUGS, these outstanding hedges were terminated.

Credit Risk. Our business operations expose us to credit risk, as the margin on any sale is generally a very small percentage of the total sale price. Therefore, a credit loss can be very large relative to our overall profitability. We attempt to ensure that we issue credit only to creditworthy counterparties and that in appropriate circumstances any such extension of credit is backed by adequate collateral such as a letter of credit or a parent company guarantee.

26

Item 8. Financial Statements and Supplementary Data

Index to Consolidated Financial Statements

	Page
Report of Independent Registered Public Accounting Firm	28
Consolidated Balance Sheets as of December 31, 2012 and 2011	30
Consolidated Statements of Operations for the years ended December 31, 2012, 2011, the period from Acquisition (May 26, 2010) to December 31, 2010, and the period from January 1, 2010 to May 25, 2010	31
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2012, 2011, the period from Acquisition (May 26, 2010) to December 31, 2010, and the period from January 1, 2010 to May 25, 2010	33
Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011, the period from Acquisition (May 26, 2010) to December 31, 2010, and the period from January 1, 2010 to May 25, 2010	34
Consolidated Statements of Partners’ Capital and Noncontrolling Interest for the years ended December 31, 2012, 2011, the period from Acquisition (May 26, 2010) to December 31, 2010, and the period from January 1, 2010 to May 25, 2010	35
Notes to Consolidated Financial Statements	37

27

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, 2012 and 2011, and the related consolidated statements of operations, comprehensive income (loss), cash flows, and partners' capital and noncontrolling interest for the years then ended. 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, 2012 and 2011 was $581 million and $614 million, respectively, and its equity in the earnings of Midcontinent Express Pipeline LLC was $42 million and $43 million, respectively, for the years then ended. 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, 2012 and 2011, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1, the accompanying consolidated financial statements have been adjusted to reflect the acquisition of an entity under common control, which has been accounted for in a manner similar to a pooling of interests.

/s/ GRANT THORNTON LLP

Dallas, Texas

August 9, 2013

28

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Partners

Regency Energy Partners LP:

We have audited the accompanying consolidated statements of operations, comprehensive income (loss), cash flows, and partners' capital and noncontrolling interest for the period from May 26, 2010 to December 31, 2010 and the period from January 1, 2010 to May 25, 2010 for Regency Energy Partners LP and subsidiaries. These consolidated financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We did not audit the financial statements of Midcontinent Express Pipeline LLC, (a 49.9% owned investee company which was acquired by the Partnership on May 26, 2010). The Partnership's equity in the earnings of Midcontinent Express Pipeline LLC was $21,219,000 for the period from May 26, 2010 to December 31, 2010. The financial statements of Midcontinent Express Pipeline LLC were audited by other auditors whose report has been furnished to us and included herein, 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 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 results of operations and cash flows for the period from May 26, 2010 to December 31, 2010 and the period from January 1, 2010 to May 25, 2010 for Regency Energy Partners LP and subsidiaries, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Dallas, Texas

February 18, 2011

29

Regency Energy Partners LP

Consolidated Balance Sheets

(in millions except unit data)

	December 31, 2012			December 31, 2011
ASSETS
Current Assets:
Cash and cash equivalents	$	53		$	1
Trade accounts receivable, net of allowance of $1 and $1	115			44
Accrued revenues	107			68
Related party receivables	8			45
Derivative assets	4			4
Other current assets	53			25
Total current assets	340			187
Property, Plant and Equipment:
Gathering and transmission systems	1,308			699
Compression equipment	1,326			847
Gas plants and buildings	568			195
Other property, plant and equipment	377			148
Construction-in-progress	507			192
Total property, plant and equipment	4,086			2,081
Less accumulated depreciation	(400		)	(195		)
Property, plant and equipment, net	3,686			1,886
Other Assets:
Investment in unconsolidated affiliates	2,214			1,925
Long-term derivative assets	1			—
Other, net of accumulated amortization of debt issuance costs of $17 and $10	42			39
Total other assets	2,257			1,964
Intangible Assets and Goodwill:
Intangible assets, net of accumulated amortization of $74 and $45	712			741
Goodwill	1,128			790
Total intangible assets and goodwill	1,840			1,531
TOTAL ASSETS	$	8,123		$	5,568
LIABILITIES & PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST
Current Liabilities:
Drafts payable	$	10		$	3
Trade accounts payable	122			73
Accrued cost of gas and liquids	133			85
Related party payables	95			13
Deferred revenues	17			16
Derivative liabilities	6			11
Other current liabilities	106			33
Total current liabilities	489			234
Long-term derivative liabilities	25			39
Other long-term liabilities	39			6
Long-term debt, net	2,157			1,687
Commitments and contingencies
Series A Preferred Units, redemption amount of $85 and $85	73			71
Partners’ Capital and Noncontrolling Interest:
Common units (174,574,175 and 161,233,046 units authorized; 170,951,457 and 157,437,608 units issued and outstanding at December 31, 2012 and 2011)	3,207			3,173
General partner interest	326			330
Predecessor equity	1,733			—
Accumulated other comprehensive loss	(3		)	(5		)
Total partners’ capital	5,263			3,498
Noncontrolling interest	77			33
Total partners’ capital and noncontrolling interest	5,340			3,531
TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST	$	8,123		$	5,568

See accompanying notes to consolidated financial statements

30

Regency Energy Partners LP

Consolidated Statements of Operations

(in millions except unit data and per unit data)

	Successor									Predecessor
	Year Ended December 31, 2012			Year Ended December 31, 2011			Period from  Acquisition (May 26, 2010) to December 31, 2010			Period from January 1, 2010 to May 25, 2010
REVENUES
Gas sales, including related party amounts of $42, $23, $3, and $—	$	508		$	456		$	291		$	228
NGL sales, including related party amounts of $28, $365, $137, and $—	991			603			238			153
Gathering, transportation and other fees, including related party amounts of $29, $24, $14, and $12	401			351			179			115
Net realized and unrealized gain (loss) from derivatives	23			(19		)	(8		)	(1		)
Other, including related party amounts of $1, $10, $3, and $—	77			43			16			10
Total revenues	2,000			1,434			716			505
OPERATING COSTS AND EXPENSES
Cost of sales, including related party amounts of $35, $22, $13, and $7	1,387			1,013			504			358
Operation and maintenance	228			147			78			48
General and administrative, including related party amounts of $15, $17, $6, and $—	100			67			44			37
Loss (gain) on asset sales, net	3			(2		)	—			—
Depreciation and amortization	252			169			76			42
Total operating costs and expenses	1,970			1,394			702			485
OPERATING INCOME	30			40			14			20
Income from unconsolidated affiliates	105			120			54			16
Interest expense, net	(122		)	(103		)	(48		)	(35		)
Loss on debt refinancing, net	(8		)	—			(16		)	(2		)
Other income and deductions, net	29			17			(8		)	(4		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	34			74			(4		)	(5		)
Income tax expense	—			—			1			—
INCOME (LOSS) FROM CONTINUING OPERATIONS	$	34		$	74		$	(5	)	$	(5	)
DISCONTINUED OPERATIONS
Net loss from operations of east Texas assets	—			—			(1		)	—
NET INCOME (LOSS)	$	34		$	74		$	(6	)	$	(5	)
Net income attributable to noncontrolling interest	(2		)	(2		)	—			—
NET INCOME (LOSS) ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP	$	32		$	72		$	(6	)	$	(5	)
Amounts attributable to Series A Preferred Units	10			8			5			3
General partner’s interest, including IDRs	9			7			3			1
Pre-acquisition income from SUGS allocated to predecessor equity	(14		)	—			—			—
Limited partners’ interest in net income (loss)	$	27		$	57		$	(14	)	$	(9	)
Basic and diluted income (loss) from continuing operations per unit:
Amount allocated to common units	$	27		$	57		$	(12	)	$	(9	)
Weighted average number of common units outstanding	167,492,735			145,490,869			130,619,554			92,788,319
Basic income (loss) from continuing operations per common unit	$	0.16		$	0.39		$	(0.09	)	$	(0.10	)
Diluted income (loss) from continuing operations per common unit	$	0.13		$	0.32		$	(0.09	)	$	(0.10	)

31

Distributions per unit	$	1.84	$	1.81	$	0.89		$	0.89
Basic and diluted loss on discontinued operations per unit	$	—	$	—	$	(0.01	)	$	—
Basic and diluted net income (loss) per unit:
Amount allocated to common units	$	27	$	57	$	(14	)	$	(9	)
Basic net income (loss) per common unit	$	0.16	$	0.39	$	(0.10	)	$	(0.10	)
Diluted net income (loss) per common unit	$	0.13	$	0.32	$	(0.10	)	$	(0.10	)

See accompanying notes to consolidated financial statements

32

Regency Energy Partners LP

Consolidated Statements of Comprehensive Income (Loss)

(in millions)

	Successor									Predecessor
	Year Ended December 31, 2012			Year Ended December 31, 2011			Period from  Acquisition (May 26, 2010) to December 31, 2010			Period from January 1, 2010 to May 25, 2010
Net income (loss)	$	34		$	74		$	(6	)	$	(5	)
Other comprehensive income (loss):
Net cash flow hedge amounts reclassified to earnings	6			19			—			2
Change in fair value of cash flow hedges	(4		)	(13		)	(11		)	18
Total other comprehensive income (loss)	$	2		$	6		$	(11	)	$	20
Comprehensive income (loss)	$	36		$	80		$	(17	)	$	15
Comprehensive income (loss) attributable to noncontrolling interest	2			2			—			—
Comprehensive income (loss) attributable to Regency Energy Partners LP	$	34		$	78		$	(17	)	$	15

See accompanying notes to consolidated financial statements

33

Regency Energy Partners LP

Consolidated Statements of Cash Flows

(in millions)

	Successor									Predecessor
	Year Ended December 31, 2012			Year Ended December 31, 2011			Period from  Acquisition (May 26, 2010) to December 31, 2010			Period from January 1, 2010 to May 25, 2010
OPERATING ACTIVITIES
Net income (loss)	$	34		$	74		$	(6	)	$	(5	)
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:
Depreciation and amortization, including debt issuance cost amortization and bond premium amortization	260			175			79			49
Write-off of debt issuance costs and bond premium	(1		)	—			(1		)	2
Income from unconsolidated affiliates	(105		)	(120		)	(54		)	(16		)
Derivative valuation changes	(12		)	(21		)	33			12
Loss (gain) on asset sales, net	3			(2		)	—			—
Unit-based compensation expenses	5			3			2			12
Cash flow changes in current assets and liabilities:
Trade accounts receivable, accrued revenues and related party receivables	—			(8		)	—			(11		)
Other current assets and other current liabilities	10			11			(13		)	25
Trade accounts payable, accrued cost of gas and liquids, related party payables and deferred revenues	18			23			(15		)	9
Distributions received from unconsolidated affiliates	121			119			57			12
Cash flow changes in other assets and liabilities	(9		)	—			(2		)	—
Net cash flows provided by operating activities	324			254			80			89
INVESTING ACTIVITIES
Capital expenditures	(560		)	(406		)	(159		)	(64		)
Capital contributions to unconsolidated affiliates	(356		)	(53		)	(86		)	(20		)
Distributions in excess of earnings of unconsolidated affiliates	83			74			59			—
Acquisition of investment in unconsolidated affiliates, net of cash received	—			(594		)	5			(75		)
Acquisitions, net of cash of $-, $-, $2, and $-	—			—			(192		)	—
Proceeds from asset sales	26			24			76			11
Net cash flows used in investing activities	(807		)	(955		)	(297		)	(148		)
FINANCING ACTIVITIES
Net (repayments) borrowings under revolving credit facility	(140		)	47			(334		)	199
Proceeds from issuance of senior notes	700			500			600			—
Redemption of senior notes	(88		)	—			(358		)	—
Debt issuance costs	(15		)	(10		)	(11		)	(16		)
Partner contributions	—			—			28			—
Partner distributions	(322		)	(274		)	(119		)	(86		)
Acquisition of assets between entities under common control in excess of historical cost	—			—			—			(17		)
Contributions (distributions) from/to noncontrolling interest	42			—			—			(1		)
Contributions from Southern Union	51			—			—			—
Drafts payable	4			2			—			—
Issuance of common units under LTIP, net of forfeitures and tax withholding	(1		)	—			1			(5		)
Common unit offerings, net of issuance costs	312			436			400			—
Distributions to Series A Preferred Units	(8		)	(8		)	(4		)	(2		)
Net cash flows provided by financing activities	535			693			203			72
Net change in cash and cash equivalents	52			(8		)	(14		)	13
Cash and cash equivalents at beginning of period	1			9			23			10
Cash and cash equivalents at end of period	$	53		$	1		$	9		$	23
Supplemental cash flow information:
Non-cash capital expenditures and capital contributions to unconsolidated affiliates	$	159		$	24		$	20		$	18
Issuance of common units for investment in unconsolidated affiliate	—			—			584			—
Deemed contribution from acquisition of assets between entities under common control	—			—			9			—
Release of escrow payable from restricted cash	—			—			1			1
Interest paid, net of amounts capitalized	112			83			58			5
Income taxes paid	—			2			1			—

See accompanying notes to consolidated financial statements

34

Regency Energy Partners LP

Consolidated Statements of Partners’ Capital and Noncontrolling Interest

(in millions except unit data)

	Units
Predecessor	Common	Common Unitholders			General Partner Interest			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total
Balance— December 31, 2009	93,188,353	$	1,212		$	19		$	(2	)	$	14		$	1,243
Issuance of common units under LTIP, net of forfeitures and tax withholding	152,075	(5		)	—			—			—			(5		)
Unit-based compensation expenses	—	12			—			—			—			12
Accrued distributions to phantom units	—	(1		)	—			—			—			(1		)
Acquisition of assets between entities under common control in excess of historical costs	—	—			(17		)	—			—			(17		)
Partner distributions	—	(83		)	(3		)	—			—			(86		)
Distributions to noncontrolling interest	—	—			—			—			(1		)	(1		)
Net (loss) income	—	(6		)	1			—			—			(5		)
Distributions to Series A Preferred Units	—	(2		)	—			—			—			(2		)
Net cash flow hedge amounts reclassified to earnings	—	—			—			2			—			2
Net change in fair value of cash flow hedges	—	—			—			19			—			19
Balance—May 25, 2010	93,340,428	$	1,127		$	—		$	19		$	13		$	1,159

See accompanying notes to consolidated financial statements

35

Regency Energy Partners LP

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

(in millions except unit data)

	Units
Successor	Common	Common Unitholders			General Partner Interest			Predecessor Equity			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest		Total
Balance—May 26, 2010	93,340,428	$	2,074		$	305		$	—		$	—		$	31	$	2,410
Private common unit offerings, net of costs	26,266,791	584			—			—			—			—		584
Public common unit offerings, net of costs	17,537,500	400			—			—			—			—		400
Issuance of common units under LTIP, net of forfeitures and tax withholding	42,417	(1		)	—			—			—			—		(1		)
Proceeds from exercise of common unit options	94,200	2			—			—			—			—		2
Unit-based compensation expenses	—	2			—			—			—			—		2
Acquisition of assets between entities under common control below historical costs	—	—			9			—			—			—		9
Partner contributions	—	7			21			—			—			—		28
Partner distributions	—	(114		)	(5		)	—			—			—		(119		)
Net (loss) income	—	(9		)	3			—			—			—		(6		)
Distributions to Series A Preferred Units	—	(4		)	—			—			—			—		(4		)
Net change in fair value of cash flow hedges	—	—			—			—			(11		)	—		(11		)
Balance—December 31, 2010	137,281,336	2,941			333			—			(11		)	31		3,294
Common unit offerings, net of costs	20,000,001	436			—			—			—			—		436
Issuance of common units under LTIP, net of forfeitures and tax withholding	156,271	—			—			—			—			—		—
Unit-based compensation expenses	—	3			—			—			—			—		3
Partner distributions	—	(264		)	(10		)	—			—			—		(274		)
Net income	—	65			7			—			—			2		74
Distributions to Series A Preferred Units	—	(8		)	—			—			—			—		(8		)
Net cash flow hedge amounts reclassified to earnings	—	—			—			—			19			—		19
Net change in fair value of cash flow hedges	—	—			—			—			(13		)	—		(13		)
Balance—December 31, 2011	157,437,608	3,173			330			—			(5		)	33		3,531
Common unit offerings, net of costs	13,341,129	312			—			—			—			—		312
Issuance of common units under LTIP, net of forfeitures and tax withholding	172,720	(1		)	—			—			—			—		(1		)
Unit-based compensation expenses	—	5			—			—			—			—		5
Partner distributions	—	(309		)	(13		)	—			—			—		(322		)
Net income (loss)	—	37			9			(14		)	—			2		34
Contributions from noncontrolling interest	—	—			—			—			—			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	170,951,457	$	3,207		$	326		$	1,733		$	(3	)	$	77	$	5,340

See accompanying notes to consolidated financial statements

36

Regency Energy Partners LP

Notes to Consolidated Financial Statements

(Tabular dollar amounts, except 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 and the transportation, fractionation and storage of NGLs. Regency GP LP is the Partnership’s general partner and Regency GP LLC (collectively the “General Partner”) is the managing general partner of the Partnership and the general partner of Regency GP LP. SUGS was consolidated in the Partnership beginning March 26, 2012.

In May 2010, GP Seller completed the sale of all of the outstanding membership interests of the General Partner pursuant to a Purchase Agreement (the “Purchase Agreement”) among itself, ETE and ETE GP (the “ETE Acquisition”). Prior to the closing of the Purchase Agreement, GP Seller, an affiliate of GE EFS, owned all of the outstanding limited partner interests in the General Partner and all of the member interests in the general partner of the General Partner and, as a result of that position, controlled the Partnership. As a result of this transaction, the outstanding voting interests of the General Partner and control of the Partnership were transferred from GE EFS to ETE.

In connection with this change in control, the Partnership’s assets and liabilities were adjusted to fair value on the closing date (May 26, 2010) by application of “push-down” accounting (the “Push-down Adjustments”).

The Partnership applied the guidance in FASB ASC 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), in determining the fair value of partners’ capital, which is comprised of the following items:

	May 26, 2010
Fair value of limited partners’ interest, based on the number of outstanding Partnership common units and the trading price on May 26, 2010	$	2,074
Fair value of consideration paid for general partner interest	305
Noncontrolling interest	31
	$	2,410

The Partnership then developed the fair value of its assets and liabilities, with the assistance of third-party valuation experts, using the guidance in FASB ASC 820.

	May 26, 2010
Working capital	$	(3	)
Gathering and transmission systems	471
Compression equipment	746
Gas plants and buildings	117
Other property, plant and equipment	100
Construction-in-progress	114
Other long-term assets	38
Investment in unconsolidated affiliate	739
Intangible assets	666
Goodwill	790
	$	3,778
Less:
Series A Preferred Units	71
Fair value of long-term debt	1,240
Other long-term liabilities	57
Total fair value of partners’ capital	$	2,410

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

SUGS Acquisition. In April 2013, the Partnership and Regency Western acquired SUGS from Southern Union, a wholly owned subsidiary of Holdco, for $1.5 billion (the “SUGS Acquisition”). The Partnership financed the acquisition by issuing to Southern Union 31,372,419 of common units and 6,274,483 recently created Class F common units. The Class F common units are not entitled to participate in the Partnership’s distributions for twenty-four months post-transaction closing. The remaining $600 million, less $107 million of closing adjustments, was paid in cash. In addition, ETE has agreed to forgo IDR payments on the Partnership common units issued with this transaction for the twenty-four months post-transaction closing and to suspend the $10 million annual management fee paid by the Partnership for two years post-transaction close.

The common units and Class F common units related to the SUGS Acquisition were issued in a private placement conducted in accordance with the exemption from registration requirements of the Securities Act of 1933, as amended under Section 4(2) thereof. The Class F common units will convert into common units on a one-for-one basis in May 2015.

The cash portion of the SUGS Acquisition was funded from the proceeds of senior notes issued by the Partnership on April 30, 2013 in a private placement. PEPL Holdings provided a guarantee of collection with respect to the payment of the principal amounts of the senior notes issued by the Partnership.

The Partnership accounted for the acquisition in a manner similar to the pooling of interest method of accounting, as it was a transaction between commonly controlled entities. Under this method of accounting, the Partnership reflected historical balance sheet data for the Partnership and SUGS instead of reflecting the fair market value of SUGS assets and liabilities. The Partnership retrospectively adjusted its financial statements to include the balances and operations of SUGS from March 26, 2012 (the date upon which common control began).

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

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

	Year Ended December 31, 2012
Revenues:
Partnership	$	1,339
SUGS (1)	661
Combined	$	2,000
Net income (loss):
Partnership	$	48
SUGS (1)	(14		)
Combined	$	34

⁽¹⁾  The amounts attributable to SUGS are from the period from March 26, 2012 to December 31, 2012, the period that SUGS and Regency were under common control.

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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.

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 ours at their historical amounts. If any cash consideration transferred in such a transaction exceeds the carrying value of the net assets acquired, the excess is treated as a capital transaction with our general partner, similar to a dividend. If the carrying value of the net assets acquired exceeds any cash consideration transferred and limited partner units are also issued as consideration, then the limited partner units are recorded at an amount equal to the excess of the carrying value of the net assets acquired over any cash consideration transferred. 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.

Other Current Assets and Other Current Liabilities. As of December 31, 2012 and 2011, other current assets included spare parts inventories in the Partnership’s Contract Services segment of $27 million and $21 million, respectively, and other current liabilities included accrued interest of $30 million and $27 million, respectively.

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 capitalized and classified as property, plant and equipment. Financing costs associated with the construction of larger assets requiring ongoing efforts over a period of time are capitalized. For the years ended December 31, 2012 and December 31, 2011 and the periods from May 26, 2010 to December 31, 2010 and January 1, 2010 to May 25, 2010, the Partnership capitalized interest of $1 million, $1 million, $1 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.

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 as of December 31, 2012 were $5 million.

39

Depreciation expense related to property, plant and equipment was $219 million, $138 million, $60 million and $37 million for the years ended December 31, 2012 and December 31, 2011 and the periods from May 26, 2010 to December 31, 2010 and January 1, 2010 to May 25, 2010, 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. The adjustment to depreciation expense related to the year ended December 31, 2011 and the period from May 26, 2010 to December 31, 2010 was $4 million and $3 million, respectively. 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	10 - 50
Compression Equipment	2 - 30
Gas Plants and Buildings	5 - 35
Other property, plant and equipment	3 - 15

Intangible Assets. As of December 31, 2012, 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 20 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 2012, 2011 or 2010.

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, 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. The Partnership did not record any impairment in 2012, 2011 or 2010.

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, 2012 and 2011 were immaterial.

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

40

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 natural gas, ethane, propane, butane, natural gasoline, and condensate swaps as well as ethane put options 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. Derivative financial instruments qualifying for hedge accounting treatment may be designated by the Partnership as cash flow hedges. The Partnership enters into cash flow hedges to hedge the variability in cash flows related to a forecasted transaction. At inception, the Partnership formally documents the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing correlation and hedge effectiveness. The Partnership also assesses, both at the inception of the hedge and on an on-going basis, whether the derivatives are highly effective in offsetting changes in cash flows of the hedged item. If the Partnership determines that a derivative is no longer highly effective as a hedge, it discontinues hedge accounting prospectively by including changes in the fair value of the derivative in current earnings. For cash flow hedges, changes in the derivative fair values, to the extent that the hedges are effective, are recorded as a component of accumulated other comprehensive income (loss) until the hedged transactions occur and are recognized in earnings. Any ineffective portion of a cash flow hedge's change in value is recognized immediately in earnings. In the statement of cash flows, the effects of settlements of derivative instruments are classified consistent with the related hedged transactions.

Benefits. The Partnership previously provided medical, dental, and other healthcare benefits to employees, including providing a matching contribution for employee contributions to their 401(k) accounts, which vested ratably over 3 years. Effective January 1, 2011, the Partnership’s 401(k) plan merged with and into that of ETP. As a result of the merger, the Partnership’s matching contributions that had not yet fully vested became fully vested, effective immediately. All future matching contributions from the Partnership to the employee 401(k) accounts will vest immediately. In addition, SUGS maintained a separate defined contribution plan during March 26, 2012 to December 31, 2012. The total amount of matching contributions for the years ended December 31, 2012 and December 31, 2011 and the period from May 26, 2010 to December 31, 2010 was $4 million, $3 million, and $2 million, respectively, and were recorded in general and administrative expenses. The amount of matching contributions for the period from January 1, 2010 to May 25, 2010 was less than $1 million. The Partnership has no pension obligations or other post-employment benefits.

Beginning January 1, 2013, the Partnership will provide a 3% profit sharing contribution to employee 401(k) accounts for all employees with base compensation of $125,000 or less. 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 two wholly-owned subsidiary that are 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’s deferred tax liabilities of $22 million and $6 million as of December 31, 2012 and 2011, respectively, relate to the difference between the book and tax basis of property, plant and equipment and intangible assets and is included in other long-term liabilities in the accompanying consolidated balance 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, 2012 and 2011. The Partnership recognized current federal income tax expense of $1 million for the period from May 26, 2010 to December 31, 2010 and less than $1 million for the years ended December 31, 2012 and December 31, 2011 and the period from January 1, 2010 to May 25, 2010, respectively. The Partnership also recognized deferred income tax benefit of $1 million for the year ended December 31, 2012 and less than $1 million using a 35% effective rate for the year ended December 31, 2011 and the periods from May 26, 2010 to December 31, 2010 and January 1, 2010 to May 25, 2010, respectively.

Although the SUGS operations were included in the Southern Union consolidated federal income tax return prior to the SUGS Acquisition, following their acquisition by the Partnership, their operations are now treated as a partnership. Therefore, other than one wholly-owned subsidiary, the historical operations exclude income taxes for all periods presented.

The IRS commenced audits of our 2007 and 2008 federal income tax returns on January 27, 2010. The IRS has now completed its audit of these returns and proposed certain adjustments. The Partnership filed a protest with the IRS to initiate the appeals process and appeal certain of these adjustments. 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 IRS is also conducting an audit of the 2007 through 2009 tax returns of one of the Partnership’s wholly-owned subsidiaries and has proposed certain adjustments. The subsidiary has filed a protest with the IRS. The statute of limitations for each of these audits has been extended to December 31, 2014.

41

Equity-Based Compensation. The Partnership accounts for equity-based compensation 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.

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 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 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 restricted units, phantom units, Series A Preferred Units and unit options. For special classes of common units issued with a beneficial conversion feature, the amount of the benefit associated with the period is added back to net income and the unconverted class is added to the denominator.

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.

3. Partners’ Capital and Distributions

Equity Distribution Agreement. In June 2012, the Partnership entered into an Equity Distribution Agreement with Citi under which the Partnership may offer and sell common units, representing limited partner interests, having an aggregate offering price of up to $200 million, from time to time through Citi, as sales agent for the Partnership. Sales of these units, if any, 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 Citi. The Partnership may also sell common units to Citi as principal for its own account at a price agreed upon at the time of sale. Any sale of common units to Citi as principal would be pursuant to the terms of a separate agreement between the Partnership and Citi. The Partnership intends to use the net proceeds from the sale of these units for general partnership purposes. As of December 31, 2012 and June 30, 2013, the Partnership received net proceeds of $15 million and $128 million, respectively, from units issued pursuant to this Equity Distribution Agreement.

Public Common Unit Offerings. In April 2013, the Partnership issued 31,372,419 and 6,274,483 common and Class F common units to Southern Union as a part of the SUGS Acquisition. 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.

In October 2011, the Partnership issued 11,500,000 common units representing limited partnership interests in a public offering at a price of $20.92 per common unit, resulting in net proceeds of $232 million which were used to repay outstanding borrowings under the revolving credit facility. In August 2010, the Partnership sold 17,537,500 common units and received $408 million in proceeds, inclusive of the General Partner’s proportionate capital contribution.

Private Common Unit Offerings. In May 2011, the Partnership sold 8,500,001 common units representing limited partnership interests resulting in net proceeds of $204 million, to partially fund its capital contribution to Lone Star. These units were issued in a private placement conducted in accordance with the exemption from the registration requirements of the Securities Act of 1933, as amended, under section 4(2) thereof. These units were subsequently registered with the SEC.

In May 2010, the Partnership issued 26,266,791 common units, valued at $584 million, to ETE, to purchase a 49.9% interest in MEP. These units were issued in a private placement conducted in accordance with the exemption from the registration requirements of the Securities Act of 1933, as amended, under Section 4(2) thereof. Subsequently, ETE contributed $12 million as the General Partner’s proportionate capital.

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

Noncontrolling Interest. The Partnership operates ELG, a gas gathering joint venture in south Texas in which other third party companies own a 40% interest, which is reflected on the 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 Partnership ownership interest as of December 31, 2012 was 1.6%. This General Partner interest is represented by 2,798,872 equivalent units as of December 31, 2012.

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.

Distributions. The Partnership made the following cash distributions per unit during the years ended December 31, 2012 and 2011:

Distribution Date	Cash Distribution (per common unit)
November 14, 2012	$	0.460
August 14, 2012	0.460
May 14, 2012	0.460
February 13, 2012	0.460
November 14, 2011	0.455
August 12, 2011	0.450
May 13, 2011	0.445
February 14, 2011	0.445

Following are distributions declared by the Partnership subsequent to December 31, 2012:

Quarter Ended	Record Date	Payment Date	Cash Distributions (per common unit)
December 31, 2012	February 7, 2013	February 14, 2013	$	0.46
March 31, 2013	May 6, 2013	May 13, 2013	$	0.46
June 30, 2013	August 5, 2013	August 14, 2013	$	0.465

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4. Income per Limited Partner Unit

The following table provides a reconciliation of the numerator and denominator of the basic and diluted earnings per unit computations for the years ended December 31, 2012 and 2011. For the periods from May 26, 2010 to December 31, 2010 and from January 1, 2010 to May 25, 2010, diluted earnings per unit equals basic earnings per unit because all instruments were antidilutive.

	For the Year Ended December 31, 2012						For the Year Ended December 31, 2011
	Income (Numerator)			Units (Denominator)	Per-Unit Amount		Income (Numerator)			Units (Denominator)	Per-Unit Amount
Basic income per unit
Limited Partners’ interest in net income	$	27		167,492,735	$	0.16	$	57		145,490,869	$	0.39
Effect of Dilutive Securities:
Common unit options	—			10,854			—			19,192
Phantom units *	—			223,325			—			148,388
Series A Preferred Units	(5		)	4,658,700			(10		)	4,632,389
Diluted income per unit	$	22		172,385,614	$	0.13	$	47		150,290,838	$	0.32

__________________

* Amount assumes maximum conversion rate for market condition awards.

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

	Successor			Predecessor
	Year Ended December 31, 2012	Year Ended December 31, 2011	Period from  Acquisition (May 26, 2010) to December 31, 2010	Period from January 1, 2010 to May 25, 2010
Restricted (non-vested) common units	—	—	—	396,918
Common unit options	—	—	259,650	298,400
Phantom units *	—	—	366,489	369,346
Series A Preferred Units	—	—	4,584,192	4,584,192

 _______________________

* Amount assumes maximum conversion rate for market condition awards.

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 and Dispositions

2011

Lone Star. On May 2, 2011, the Partnership contributed $593 million in cash to Lone Star, in exchange for its 30% interest. Lone Star, a newly formed joint venture that is owned 70% by ETP and 30% by the Partnership, completed its acquisition of all of the membership interest in LDH, a wholly-owned subsidiary of Louis Dreyfus Highbridge Energy LLC (subsequently renamed Castleton Commodities International, LLC), for $1.98 billion in cash. To fund a portion of this capital contribution, the Partnership issued 8,500,001 common units representing limited partnership interests with net proceeds of $204 million. The remaining portion of the Partnership’s capital contribution was funded by additional borrowings under its revolving credit facility.

MEP. On September 1, 2011, the Partnership purchased an additional 0.1% interest in MEP from ETP for $1 million in cash, bringing its total interest in MEP to 50%.

Ranch JV. On December 2, 2011, Ranch JV was formed by the Partnership, APM and CM, each owning a 33.33% interest in the joint venture. Ranch JV processes natural gas delivered from the NGLs-rich Bone Spring and Avalon shale formations in west Texas.

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2010

HPC. On April 30, 2010, the Partnership purchased an additional 6.99% general partner interest in HPC from EFS Haynesville, bringing its total general partner interest in HPC to 49.99%. The purchase price of $92 million was funded by borrowings under the Partnership’s revolving credit facility. Because this transaction occurred between two entities under common control, partners’ capital was decreased by $17 million, which represented a deemed distribution of the excess purchase price over EFS Haynesville’s carrying amount of $75 million.

MEP. On May 26, 2010, the Partnership purchased a 49.9% interest in MEP from ETE. The Partnership issued 26,266,791 common units to ETE, valued at $584 million, and received a working capital adjustment of $5 million from ETE that was recorded as an adjustment to investment in unconsolidated affiliates. Because this transaction occurred between two entities under common control, partners’ capital was increased by $9 million, which represented a deemed contribution of the excess carrying amount of ETE’s investment of $589 million over the purchase price. MEP owns approximately 500 miles of natural gas pipelines that extend from the southeast corner of Oklahoma, across northeast Texas, northern Louisiana, central Mississippi and into Alabama.

Disposition of East Texas Assets. In July 2010, the Partnership sold its gathering and processing assets located in east Texas for $70 million in cash. The financial results of these assets have been reclassified to discontinued operations in accordance with applicable accounting standards. Revenues for these assets for the period from May 26, 2010 to December 31, 2010, the period from January 1, 2010 to May 25, 2010, and the year ended December 31, 2009 were $10 million, $24 million and $46 million, respectively.

Zephyr. On September 1, 2010, the Partnership completed the Zephyr acquisition for $193 million in cash that was funded by borrowings under the Partnership’s revolving credit facility. Zephyr owns and operates a fleet of equipment used in gas treating. The primary treatment services include carbon dioxide and hydrogen sulfide removal, dehydration, natural gas cooling and BTU management. The acquisition of Zephyr further increased the Partnership’s fee-based revenues. From September 1, 2010 through December 31, 2010, revenues and net income attributable to Zephyr’s operations of $14 million and $6 million, respectively are included in the Partnership’s results of operations. The total purchase price was allocated as follows:

	September 1, 2010
Cash and cash equivalents	$	2
Trade accounts receivable	7
Gas plants and buildings	81
Intangible assets	119
Total assets acquired	$	209
Trade accounts payable	(8		)
Deferred revenues	(7		)
Other current liabilities	(1		)
Net assets acquired	$	193

6. Investment in Unconsolidated Affiliates

As of December 31, 2012, the Partnership has a 49.99% general partner interest in HPC, a 50% membership interest in MEP, a 30% membership interest in Lone Star, a 33.33% membership interest in Ranch JV, and a 50% interest in Grey Ranch. The carrying value of the Partnership’s investment in each of the unconsolidated affiliates as of December 31, 2012 and 2011 is as follows:

	December 31, 2012		December 31, 2011
HPC	$	650	$	682
MEP	581		614
Lone Star	948		629
Ranch JV	35		—
Grey Ranch	—		—
	$	2,214	$	1,925

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The following tables summarize the changes in the Partnership’s investment activities in each of the unconsolidated affiliates for the years ended December 31, 2012, 2011 and 2010:

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

	Year Ended December 31, 2011
	HPC			MEP(2)		Lone Star(3)		Ranch JV		Grey Ranch
Contributions to unconsolidated affiliates	$	—		$	—	$	645	$	—	N/A
Purchase of additional interest in unconsolidated affiliates	—			1		—		—		N/A
Distributions from unconsolidated affiliates	65			83		22		—		N/A
Return of investment received	—			—		23		—		N/A
Share of unconsolidated affiliates’ net income	55			43		28		—		N/A
Amortization of excess fair value of investment (1)	(6		)	—		—		—		N/A

	Period from Acquisition (May 26, 2010) to December 31, 2010
	HPC			MEP		Lone Star	Ranch JV	Grey Ranch
Contributions to unconsolidated affiliates	$	—		$	86	N/A	N/A	N/A
Distributions from unconsolidated affiliates	53			43		N/A	N/A	N/A
Return of investment received	20			—		N/A	N/A	N/A
Share of unconsolidated affiliates’ net income	36			21		N/A	N/A	N/A
Amortization of excess fair value of investment (1)	(3		)	—		N/A	N/A	N/A

	Predecessor
	Period from January 1, 2010 to May 25, 2010
	HPC		MEP	Lone Star	Ranch JV	Grey Ranch
Contributions to unconsolidated affiliates	$	20	N/A	N/A	N/A	N/A
Purchase of additional interest in unconsolidated affiliates	75		N/A	N/A	N/A	N/A
Distributions from unconsolidated affiliates	12		N/A	N/A	N/A	N/A
Share of unconsolidated affiliates’ net income	16		N/A	N/A	N/A	N/A

__________________

(1) As discussed in Note 1, the Partnership’s investment in HPC was adjusted to its fair value on May 26, 2010 and the excess fair value over net book value was comprised of two components: (1) $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) In September 2011, the Partnership purchased an additional 0.1% interest in MEP from ETP for $1 million in cash, bringing the total membership interest to 50%.

(3) For the period from initial contribution, May 2, 2011, to December 31, 2011.

N/A The Partnership acquired a 33.33% membership interest in Ranch JV in December 2011, a 30% interest in Lone Star in May 2011, a 49.9% interest in MEP in May 2010, and a 50% interest in Grey Ranch in March 2012.

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

The Partnership has swap contracts settled against NGLs (propane, butane, and natural gasoline), condensate and natural gas market prices. The Partnership also had put options settled against ethane, which expired in December 2012.

On January 1, 2012, the Partnership de-designated its swap contracts and began accounting for these contracts using the mark-to-market method of accounting. As of December 31, 2012, the Partnership had $3 million in net hedging losses related to these de-designated swaps in AOCI, the majority of which will be amortized to earnings over the next 12 months.

As of December 31, 2012, SUGS had outstanding receive-fixed natural gas price swaps with a total notional amount of 4,562,500 MMBtu for 2013. These natural gas price swaps are accounted for as cash flow hedges, with effective portion of changes in their fair value recorded to AOCI and reclassified into revenues in the same period which the forecasted natural gas sales impact earnings. As of April 30, 2013, in connection with the SUGS Acquisition, these outstanding hedges were terminated.

Interest Rate Risk. The Partnership is exposed to variable interest rate risk as a result of borrowings under its revolving credit facility. The Partnership's $250 million interest rate swaps expired in April 2012. As of December 31, 2012, the Partnership had $192 million 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 creditworthy counterparties and that in appropriate circumstances any such extension of credit is backed by adequate collateral, such as a letter of credit or parental guarantee from a parent company with potentially better credit.

The Partnership is exposed to credit risk from its derivative counterparties. The Partnership does not require collateral from these counterparties. The Partnership deals primarily with financial institutions when entering into financial derivatives, and utilizes master netting agreements that allow for netting of swap contract receivables and payables in the event of default by either party. If the Partnership’s counterparties failed to perform under existing swap contracts, the Partnership’s maximum loss as of December 31, 2012 was $5 million, which would be reduced by $1 million due to the netting feature. The Partnership has elected to present assets and liabilities under master netting agreements gross on the condensed consolidated balance sheets.

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

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The Partnership’s derivative assets and liabilities, including credit risk adjustments, for the years ended December 31, 2012 and 2011 are detailed below:

	Assets				Liabilities
	December 31, 2012		December 31, 2011		December 31, 2012		December 31, 2011
Derivatives designated as cash flow hedges
Current amounts
Commodity contracts	$	—	$	4	$	5	$	10
Total cash flow hedging instruments	—		4		5		10
Derivatives not designated as cash flow hedges
Current amounts
Commodity contracts	4		—		1		—
Interest rate contracts	—		—		—		1
Long-term amounts
Commodity contracts	1		—		—		—
Embedded derivatives in Series A Preferred Units	—		—		25		39
Total derivatives not designated as cash flow hedges	5		—		26		40
Total derivatives	$	5	$	4	$	31	$	50

The Partnership’s statement of operations for the years ended December 31, 2012, 2011 and 2010 was impacted by derivative instruments activities as detailed below:

		Successor									Predecessor
		Year Ended December 31, 2012			Year Ended December 31, 2011			Period from May 26, 2010 to December 31, 2010			Period from January 1, 2010 to May 25, 2010
		Change in Value Recognized in AOCI on Derivatives (Effective Portion)
Derivatives in cash flow hedging relationships:
Commodity derivatives		$	(4	)	$	(13	)	$	(11	)	$	14
	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenue	$	6		$	(19	)	$	—		$	(5	)
Interest rate swap derivatives	Interest expense	—			—			—			(1		)
		$	6		$	(19	)	$	—		$	(6	)
	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Recognized in Income on Ineffective Portion
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenue	$	—		$	—		$	—		$	(1	)

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	Location of Gain/(Loss) Recognized in  Income	Amount of Gain/(Loss) from De-designation Amortized from AOCI into Income
Derivatives not designated in a hedging relationship:
Commodity derivatives	Revenue	$	(5	)	$	—	$	—		$	4
	Location of  Gain/(Loss) Recognized in  Income	Amount of Gain/(Loss) Recognized in Income on Derivatives
Derivatives not designated in a hedging relationship:
Commodity derivatives	Revenue	$	16		$	—	$	(8	)	$	1
Interest rate swap derivatives	Interest expense	—			—		(4		)	(1		)
Embedded derivatives	Other  income & deductions	14			18		(8		)	(4		)
		$	30		$	18	$	(20	)	$	(4	)

8. Long-term Debt

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

	December 31, 2012			December 31, 2011
Senior notes	$	1,965		$	1,355
Revolving loans	192			332
Total	2,157			1,687
Less: current portion	—			—
Long-term debt	$	2,157		$	1,687
Availability under revolving credit facility:
Total credit facility limit	$	1,150		$	900
Revolving loans	(192		)	(332		)
Letters of credit	(12		)	(19		)
Total available	$	946		$	549

Long-term debt maturities as of December 31, 2012 for each of the next five years are as follows:

Year Ended December 31,	Amount
2013	$	—
2014	192
2015	—
2016	162
2017	—
Thereafter	1,800
Total	$	2,154	*

_______________________

* Excludes unamortized premiums of $3 million as of December 31, 2012.

In the year ended December 31, 2012, the Partnership borrowed $1.56 billion under its revolving credit facility; these borrowings were primarily to fund capital expenditures. During the same period, the Partnership repaid $1.7 billion with proceeds from an equity offering and an issuance of senior notes. In the years ended December 31, 2011 and 2010, the Partnership borrowed $940 million and $603 million, respectively; these funds were used primarily to finance capital expenditures and acquisitions. During

49

the same periods, the Partnership repaid $893 million, and $738 million, respectively, of these borrowings with proceeds from equity offerings.

Revolving Credit Facility. In May 2013, RGS entered into the Sixth Amended and Restated 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 and Sixth Amended and Restated 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.

The new credit agreement and the guarantees are senior to the Partnership's and the guarantors' secured obligations, including the Series A Preferred Units, to the extent of the value of the assets securing such obligations. As of June 30, 2013, the Partnership was in compliance with all of the financial covenants contained within the new credit agreement.

The revolving credit facility and the guarantees are senior to the Partnership’s and the guarantors’ unsecured obligations, to the extent of the value of the assets securing such obligations.

The outstanding balance under the revolving credit facility bears interest at LIBOR plus a margin or alternate base rate (equivalent to the U.S. prime 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 0.625% to 1.50% for base rate loans, 1.625% to 2.50% for Eurodollar loans. The weighted average interest rate on the total amounts outstanding under the Partnership’s revolving credit facility was 2.93% and 3.18% as of December 31, 2012 and 2011, respectively.

RGS must pay (i) a commitment fee ranging from 0.30% to 0.45% 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 1.625% to 2.50% 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 revolving credit facility contains financial covenants requiring RGS and its subsidiaries to maintain a debt to consolidated EBITDA (as defined in the credit agreement) ratio less than 5.00 for the first eight quarters (after March 2015, an increase is allowed in the permitted total leverage ratio for the first two fiscal quarters following any $50 million or greater acquisition), 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, 2012 and 2011, RGS and its subsidiaries were in compliance with these covenants.

The revolving credit facility restricts the ability of RGS to pay dividends and distributions other than reimbursements of the Partnership for expenses and payment of dividends to the Partnership to the amount of available cash (as defined) so long as no default or event of default has occurred or is continuing. The revolving credit facility 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;

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• prepay other indebtedness or amend organizational documents or transaction documents (as defined in the revolving credit facility);

• 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 revolving credit facility or reasonable extensions thereof.

The Partnership treated the May 2013 amendment of the revolving credit facility as a modification of an existing revolving credit agreement and, therefore, wrote off debt issuance costs of $1 million to interest expense, net in the period from January 1, 2013 to June 30, 2013. In addition, the Partnership capitalized $7 million of loan fees which will be amortized over the remaining term.

Senior Notes due 2016. In May 2009, the Partnership and Finance Corp. issued $250 million of senior notes in a private placement that mature on June 1, 2016 (”2016 Notes”). The 2016 Notes bear interest at 9.375% with interest payable semi-annually in arrears on June 1 and December 1. The Partnership received net proceeds of $236 million upon issuance. The net proceeds were used to partially repay revolving loans under the Partnership’s revolving credit facility.

In May 2012, the Partnership redeemed 35%, or $88 million, of the 2016 Notes, bringing the total outstanding principal amount to $162 million. Accordingly, a redemption premium of $8 million was charged to loss on debt refinancing, net in the consolidated statement of operations and accrued interest of $4 million was paid. In addition, the partnership wrote off the unamortized loan fee of $1 million and unamortized bond premium of $2 million to a loss on debt refinancing, net in the consolidated statement of operations.

In June 2013, the Partnership redeemed all of the $163 million outstanding 2016 Notes for $178 million cash, inclusive of accrued and unpaid interest of $7 million and other fees and expenses.

Senior Notes due 2018. In October, 2010, the Partnership and Finance Corp. issued $600 million of senior notes that mature on December 1, 2018 (”2018 Notes”). The 2018 Notes bear interest at 6.875% paid semi-annually in arrears on June 1 and December 1, commencing June 1, 2011. The Partnership capitalized $12 million in debt issuance costs that will be amortized to interest expense, net over the term of the senior notes. The proceeds were used to redeem the senior notes due 2013 and to partially repay outstanding borrowings under the Partnership’s revolving credit facility.

At any time before December 1, 2013, up to 35% of the 2018 Notes may be redeemed at a price of 106.875% plus accrued interest. Beginning December 1 of the years indicated below, the Partnership may redeem all or part of the 2018 Notes at the redemption prices, expressed as percentages of the principal amount, set forth below:

December 1 of year ending:	Percentage of Redemption
2014	103.438%
2015	101.719%
2016 and thereafter	100.000%

At any time prior to December 1, 2014, the Partnership may also redeem all or part of the 2018 Notes at a price equal to 100% of the principal amount redeemed plus accrued interest and the applicable premium, which equals the greater of (1) 1% of the principal amount of the note; or (2) the excess of the present value at such redemption date of (i) the redemption price of the note at December 1, 2014 plus (ii) all required interest payments due on the note through December 1, 2014, computed using a discount rate equal to the treasury rate (as defined) as of such redemption date plus 50 basis points, over the principal amount of the note.

Senior Notes due 2021. In May 2011, the Partnership and Finance Corp. issued $500 million in senior notes that mature on July 15, 2021 (”2021 Notes”). The 2021 Notes bear interest at 6.5% payable semi-annually in arrears on January 15 and July 15, commencing January 15, 2012. The Partnership capitalized $10 million in debt issuance costs that will be amortized to interest expense, net over the term of the 2021 Notes. The proceeds were used to repay borrowings outstanding under the Partnership’s revolving credit facility.

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

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

At any time prior to July 15, 2016, the Partnership may also redeem all or part of the 2021 Notes at a price equal to 100% of the principal amount redeemed plus accrued interest and the applicable premium, which equals the greater of (1) 1% of the principal amount of the note; or (2) the excess of the present value at such redemption date of (i) the redemption price of the note at July 15, 2016 plus (ii) all required interest payments due on the note through July 15, 2016, computed using a discount rate equal to the treasury rate (as defined) as of such redemption date plus 50 basis points, over the principal amount of the note.

Senior Notes due 2023. In October 2012, the Partnership and Finance Corp. issued $700 million in senior notes that mature on April 15, 2023 (”2023 Notes”). The 2023 Notes bear interest at 5.5% payable semi-annually in arrears on April 15 and October 15, commencing April 15, 2013. The Partnership capitalized $13 million in debt issuance costs that will be amortized to interest expense, net over the term of the 2023 Notes. The proceeds were used to repay borrowings outstanding under the Partnership’s revolving credit facility.

At any time prior to October 15, 2015, up to 35% of the 2023 Notes may be redeemed at a price of 105.5% plus accrued interest. Beginning on October 15 of the years indicated below, the Partnership may redeem all or part of the 2023 Notes at the redemption prices, expressed as percentages of the principal amount, set forth below:

October 15 of year ending:	Percentage of Redemption
2017	102.750%
2018	101.833%
2019	100.917%
2020 and thereafter	100.000%

At any time prior to October 15, 2017, the Partnership may also redeem all or part of the 2023 Notes at a price equal to 100% of the principal amount redeemed plus accrued interest and the applicable premium, which equals the greater of (1) 1% of the principal amount of the note; or (2) the excess of the present value at such redemption date of (i) the redemption price of the note at October 15, 2017 plus (ii) all required interest payments due on the note through October 15, 2017, computed using a discount rate equal to the treasury rate (as defined) as of such redemption date plus 50 basis points, over the principal amount of the note.

Private Placement of Senior Notes due 2023. In April 2013, in conjunction with the closing of the SUGS Acquisition, the Partnership and Finance Corp. issued $600 million senior notes in a private placement (the “2023 4.5% Notes”) pursuant to Section 4(2) of the Securities Act. The 2023 4.5% Notes bear interest at 4.5% payable semi-annually in arrears on May 1 and November 1, commencing November 1, 2013 and the 2023 4.5% Notes mature on November 1, 2023.

At any time prior to August 1, 2023, we may redeem some or all of the 2023 4.5% Notes at a price equal to 100% of the principal amount plus a make-whole premium and accrued interest. On or after August 1, 2023, we may redeem some or all of the 2023 4.5% Notes at a price equal to 100% plus accrued interest.

Upon a change of control, as defined in the indenture, followed by a ratings decline within 90 days, each holder of the 2023 4.5% Notes will be entitled to require us to purchase all or a portion of its notes at a purchase price of 101% of the principal amount plus accrued interest and liquidated damages, if any. Our ability to purchase the notes upon a change of control will be limited by the terms of our debt agreements, including our revolving credit facility.

The 2023 4.5% Notes contain various covenants that limit, among other things, our ability, and the ability of certain of our subsidiaries, to:

• incur additional indebtedness;

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

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• make certain investments;

• incur liens;

• enter into certain types of transactions with affiliates; and

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

If the 2023 4.5% Notes achieve investment grade ratings by both Moody’s and S&P and no default or event or default has occurred and is continuing, we will no longer be subject to many of the foregoing covenants.

The 2023 4.5% Notes are jointly and severally guaranteed by all of our consolidated subsidiaries, other than Finance Corp. and a minor subsidiary. PEPL Holdings provided a guarantee of collection with respect to the payment of the principal amounts of the senior notes issued by us. The senior notes and the guarantees are unsecured and rank equally with all of our and the guarantors’ existing and future unsecured obligations. The senior notes and the guarantees will be senior in right of payment to any of our and the guarantor’s future obligations that are, by their terms, expressly subordinated in right of payment to the notes and the guarantees. The senior notes and the guarantees will be effectively subordinated to our and the guarantors’ secured obligations, including our revolving credit facility, to the extent of the value of the assets securing such obligations.

Senior Notes Covenants. Upon a change of control, as defined in the indenture, followed by a rating decline within 90 days, each holder of the 2018 Notes, 2021 Notes, 2023 Notes, and 2023 4.5% Notes (collectively the “Senior Notes”) will be entitled to require the Partnership to purchase all or a portion of its notes at a purchase price of 101% plus accrued interest and liquidated damages, if any. The Partnership’s ability to purchase the notes upon a change of control will be limited by the terms of our debt agreements, including the Partnership’s revolving credit facility.

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

• incur additional indebtedness;

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

• make certain investments;

• incur liens;

• enter into certain types of transactions with affiliates; and

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

If the Senior Notes achieve investment grade ratings by both Moody’s and S&P and no default or event of default has occurred and is continuing, the Partnership will no longer be subject to many of the foregoing covenants. At December 31, 2012, the Partnership was in compliance with these covenants.

The Senior Notes are jointly and severally guaranteed by all of the Partnership’s current consolidated subsidiaries, other than Finance Corp. and several minor subsidiaries, and by certain of its future subsidiaries. The Senior Notes and the guarantees are unsecured and rank equally with all of the Partnership’s and the guarantors’ existing and future unsecured obligations. The Senior Notes and the guarantees will be senior in right of payment to any of the Partnership’s and the guarantors’ future obligations that are, by their terms, expressly subordinated in right of payment to the notes and the guarantees. The Senior Notes and the guarantees will be effectively subordinated to the Partnership’s and the guarantors’ secured obligations, including the Partnership’s revolving credit facility, to the extent of the value of the assets securing such obligations.

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

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9. Intangible Assets

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

	Customer Relations			Trade Names			Total
Balance at January 1, 2011	$	707		$	63		$	770
Amortization	(26		)	(3		)	(29		)
Balance at December 31, 2011	681			60			741
Amortization	(26		)	(3		)	(29		)
Balance at December 31, 2012	$	655		$	57		$	712

The average remaining amortization periods for customer relations and trade names are 25 and 17 years, respectively. The expected amortization of the intangible assets for each of the five succeeding years is $29 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, ethane put options, interest rate swaps, and embedded derivatives in the Series A Preferred Units. Derivatives related to commodity swaps, interest rate swaps, and ethane put options are valued using discounted cash flow techniques. These techniques incorporate Level 1 and Level 2 inputs such as future interest rates and commodity prices. These market inputs are utilized in the discounted cash flow calculation considering the instrument's term, notional amount, discount rate and credit risk and are classified as Level 2 in the hierarchy. Embedded derivatives related to the Series A Preferred Units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected volatility, and are classified as Level 3 in the hierarchy.

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

	Fair Value Measurement at December 31, 2012						Fair Value Measurement at December 31, 2011
	Fair Value Total		Level 2		Level 3		Fair Value Total		Level 2		Level 3
Assets
Commodity Derivatives:
Natural Gas	$	2	$	2	$	—	$	4	$	4	$	—
Natural Gas Liquids	1		1		—		—		—		—
Condensate	2		2		—		—		—		—
Total Assets	$	5	$	5	$	—	$	4	$	4	$	—
Liabilities
Commodity Derivatives:
Natural Gas	5		5		—		—		—		—
Natural Gas Liquids	1		1		—		9		9		—
Condensate	—		—		—		2		2		—
Embedded Derivatives in Series A Preferred Units	25		—		25		39		—		39
Total Liabilities	$	31	$	6	$	25	$	50	$	11	$	39

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, 2012
Credit Spread	6.49	%
Volatility	21.38	%

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. Changes in the Partnership's historical unit price volatility would cause a change in the volatility 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, 2012 and 2011. There were no transfers between Level 2 and Level 3 derivatives for the years ended December 31, 2012 and 2011.

	Embedded Derivatives in Series A Preferred Units
Balance at January, 2011	$	57
Change in fair value	(18		)
Balance at December 31, 2011	39
Change in fair value	(14		)
Balance at December 31, 2012	$	25

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 our senior notes at December 31, 2012 was $2.13 billion and $1.96 billion, respectively. As of December 31, 2011, the aggregate fair value and carrying amount of our senior notes was $1.44 billion and $1.35 billion, respectively. The fair value of our 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 noncancelable lease terms in excess of one year as of December 31, 2012:

For the year ending December 31,	Operating
2013	$	6
2014	3
2015	3
2016	2
2017	2
Thereafter	34
Total minimum lease payments	$	50

Total rent expense for operating leases, including those leases with terms of less than one year, was $11 million, $3 million, $3 million and $2 million, during the years ended December 31, 2012 and 2011 and the periods from May 26, 2010 to December 31, 2010 and January 1, 2010 to May 25, 2010, 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.

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.

The table below reflects the environmental liabilities recorded in the consolidated balance sheet at December 31, 2012 and 2011 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, 2012		December 31, 2011
Current	$	5	$	—
Noncurrent	7		—
Total environmental liabilities	$	12	$	—

The Partnership recorded expenditures related to environmental remediation of $1 million for the year ended December 31, 2012.

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 SUGS recovery units in Texas. It is unclear at this time how the NMED will address the sulfur dioxide standard.

Compliance Orders from the NMED. SUGS 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. The NMED has issued amended compliance orders (COs) and proposed penalties for alleged violations at Jal #4 in the amount of $1 million and at Jal #3 in the amount of $7 million. Hearings on the COs were delayed until September 2013 to allow the parties to pursue substantive settlement discussions. SUGS has meritorious defenses to the NMED claims and can offer significant mitigating factors to the claimed violations. The Partnership has recorded a liability related to the claims and will continue to assess its potential exposure to the allegations as the matter progresses.

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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.

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 at a price of $18.30 per unit, less issuance costs and a 4% discount of $3 million for net proceeds of $77 million, exclusive of the General Partner’s contribution of $2 million. The Series A Preferred Units are convertible to common units under terms described below, and if outstanding, are mandatorily redeemable on September 2, 2029 for $80 million plus all accrued but unpaid distributions thereon (the “Series A Liquidation Value”) and accrued interest. The Series A Preferred Units receive fixed quarterly cash distributions of $0.445 per unit which began with the quarter ending March 31, 2010.

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.

Commencing on September 2, 2014, 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 will be 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.

Also commencing on September 2, 2014, the Partnership will have 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

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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 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.

Holders may elect to convert Series A Preferred Units to common units at any time. As of December 31, 2012, the Series A Preferred Units were convertible to 4,658,700 common units.

The following table provides a reconciliation of the beginning and ending balances of the Series A Preferred Units for all income statement periods presented. The amount includes the accretion to redemption value of $80 million plus any accrued and unpaid distributions and accrued interest by deducting amounts from partners’ capital over the remaining periods until the mandatory redemption date of September 2, 2029.

	Units	Amount
Balance at January 1, 2011	4,371,586	$	71
Accretion to redemption value	—	—
Balance at December 31, 2011	4,371,586	71
Accretion to redemption value	—	2
Balance at December 31, 2012	4,371,586	$	73

In July 2013, the Partnership was notified by two of the Series A Preferred Units holders of their election to convert their Series A Preferred Units to common units; these holders owned 2.4 million Series A Preferred Units. The total number of common units they will receive is 2.6 million.

14. Related Party Transactions

As of December 31, 2012 and 2011, details of the Partnership’s related party receivables and related party payables were as follows:

	December 31, 2012		December 31, 2011
Related party receivables
ETE and its subsidiaries	$	5	$	1
HPC	1		1
EPD	N/A		42
Ranch JV	2		—
Other	—		1
Total related party receivables	$	8	$	45
Related party payables
ETE and its subsidiaries	$	94	$	11
HPC	1		—
Other	—		2
Total related party payables	$	95	$	13

__________________

N/A In January 2012, as described below, EPD sold a significant portion of its ownership in ETE’s common units and currently owns less than 5% of ETE’s outstanding common units. During 2012, EPD was not considered a related party.

Transactions with ETE and its subsidiaries.Under a May 26, 2010 service agreement with Services Co., Services Co. performs certain services for the Partnership. The Partnership pays Services Co.’s direct expenses for these services, plus an annual fee of $10 million, and receives the benefit of any cost savings recognized for these services. The services agreement has a five year term from May 26, 2010 to May 26, 2015, subject to earlier termination rights in the event of a change in control, the failure to achieve certain cost savings for the Partnership or upon an event of default. Also, the Partnership, together with the General Partner

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and RGS entered into an operation and service agreement (the “Operations Agreement”) with ETC. Under the Operations Agreement, ETC will perform certain operations, maintenance and related services reasonably required to operate and maintain certain facilities owned by the Partnership. Pursuant to the Operations Agreement, the Partnership will reimburse ETC for actual costs and expenses incurred in connection with the provision of these services based on an annual budget agreed-upon by both parties. The Operations Agreement has an initial term of one year and automatically renews on a year-to-year basis upon expiration of the initial term. The Partnership incurred total service fees of $17 million, $17 million and $6 million for the years ended December 31, 2012 and 2011 and during the period from May 26, 2010 to December 31, 2010, respectively.

In conjunction with distributions made by the Partnership to the limited and general partner interests, ETE received cash distributions of $62 million, $57 million and $28 million for the years ended December 31, 2012 and 2011 and during the period from May 26, 2010 to December 31, 2010, respectively. During the period from May 26, 2010 to December 31, 2010, the Partnership received cash of $7 million from ETE, which represents the portion of the amount of the Partnership’s common unit distribution to be paid to ETE for the period of time that those units were not outstanding (April 1, 2010 to May 25, 2010).

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. ETE made capital contributions aggregating to $21 million, to maintain the General Partner’s 2% interest in the Partnership for the period from May 26, 2010 to December 31, 2010. No capital contributions were contributed during the years ended December 31, 2012 and 2011, respectively.

In September 2011, the Partnership purchased a 0.1% interest in MEP from ETP for $1 million in cash.

The Partnership’s Gathering and Processing segment, in the ordinary course of business, sells natural gas to subsidiaries of ETE and records the revenue in gas sales. The Partnership’s NGL Services segment, in the ordinary course of business, sells NGLs to subsidiaries of ETE and records the revenue in NGL sales. The Partnership’s Contract Services segment provides contract compression services to ETP and records revenue in gathering, transportation and other fees on the statement of operations. The Partnership’s Contract Services segment sold compression equipment to a subsidiary of ETP for $1 million and $8 million for the years ended December 31, 2012 and 2011, respectively. 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 Contract Services segment purchased compression equipment from a subsidiary of ETP for $29 million and $33 million during the years ended December 31, 2012 and 2011, 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 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, 2012 and 2011 and during the periods from May 26, 2010 to December 31, 2010, from January 1, 2010 to May 25, 2010, the related party general and administrative expenses reimbursed to the Partnership were $20 million, $17 million, $10 million and $7 million, respectively, which is recorded in gathering, transportation and other fees on the statements of operations.

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

Transactions with EPD and its subsidiaries. In January 2012, EPD sold a significant portion of its ownership in ETE’s common units, and subsequent to that transaction, owns less than 5% of ETE’s outstanding common units. As such, EPD is no longer considered a related party. During 2011, EPD owned a portion of ETE’s outstanding common units and therefore was considered a related party along with any of its subsidiaries. The Partnership, in the ordinary course of business, sells natural gas and NGLs to subsidiaries of EPD and records the revenue in gas sales and NGL sales. The Partnership also incurs NGL processing fees and transportation fees with subsidiaries of EPD and records these fees as cost of sales.

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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 reporting segment.

		Successor						Predecessor
	Reportable Segment	Year Ended December 31, 2012		Year Ended December 31, 2011		Period from  May 26, 2010 to December 31, 2010		Period from January 1, 2010 to May 25, 2010
Customer
Customer A	Gathering and  Processing	$	367	$	366	$	132	$	88
Customer B	Gathering and Processing	—		—		*		52
Customer C	Gathering and Processing	451		—		—		—
Supplier
Supplier A	Gathering and Processing	171		133		—		—

_______________________

* Amounts are less than 10% of the total revenue or cost of sales.

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

16. Segment Information

During the fourth quarter of 2012, the Partnership realigned the composition of its segments and updated the segment names to reflect the realignment. Accordingly, the Partnership has restated the items of segment information for earlier periods to reflect this new segment alignment.

The Partnership has five reportable segments: Gathering and Processing, Natural Gas Transportation, NGL Services, Contract Services, 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. This segment also includes the Partnership's 33.33% membership interest in Ranch JV, which processes natural gas delivered from the NGLs-rich Bone Spring and Avalon shale formations in west Texas. The Partnership completed the SUGS Acquisition on April 30, 2013; therefore, the Gathering and Processing segment amounts have been retrospectively adjusted to reflect the SUGS Acquisition beginning March 26, 2012.

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, a 50% membership interest in MEP, which owns an interstate natural gas pipeline with approximately 500 miles 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 pipelines, storage, fractionation and processing facilities located in the states of Texas, 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.

Corporate. The Corporate segment comprises the Partnership’s corporate offices.

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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.

Management believes segment margin is an important measure because it directly relates to volume, commodity price changes, revenue generating horsepower and revenue generating gallons per minute. Operation and maintenance expenses are a separate measure used by management to evaluate performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of operation and maintenance expenses. These expenses fluctuate depending on the activities performed during a specific period. The Partnership does not deduct operation and maintenance expenses from total revenues in calculating segment margin because management separately evaluates commodity volume and price changes in segment margin. The Partnership does not record segment margin for its investments in unconsolidated affiliates (HPC, MEP, Lone Star, Ranch JV and Grey Ranch) 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:

	Successor									Predecessor
	Year Ended December 31, 2012			Year Ended December 31, 2011			Period from Acquisition (May 26, 2010) to December 31, 2010			Period from  January 1, 2010 to May 25, 2010
External Revenue
Gathering and Processing	$	1,797		$	1,226		$	607		$	439
Natural Gas Transportation	1			1			—			—
NGL Services	—			—			—			—
Contract Services	183			190			99			59
Corporate	19			17			10			7
Eliminations	—			—			—			—
Total	$	2,000		$	1,434		$	716		$	505
Intersegment Revenue
Gathering and Processing	$	—		$	—		$	—		$	—
Natural Gas Transportation	—			—			—			—
NGL Services	—			—			—			—
Contract Services	21			17			14			9
Corporate	—			—			—			—
Eliminations	(21		)	(17		)	(14		)	(9		)
Total	$	—		$	—		$	—		$	—
Cost of Sales
Gathering and Processing	$	1,373		$	993		$	497		$	353
Natural Gas Transportation	(1		)	(2		)	(3		)	(1		)
NGL Services	—			—			—			—
Contract Services	15			22			10			6
Corporate	—			—			—			—
Eliminations	—			—			—			—
Total	$	1,387		$	1,013		$	504		$	358
Segment Margin
Gathering and Processing	$	423		$	233		$	110		$	86
Natural Gas Transportation	2			3			3			1
NGL Services	—			—			—			—
Contract Services	189			185			103			62
Corporate	20			17			10			7
Eliminations	(21		)	(17		)	(14		)	(9		)
Total	$	613		$	421		$	212		$	147
Operation and Maintenance
Gathering and Processing	$	183		$	98		$	54		$	33
Natural Gas Transportation	—			—			—			—
NGL Services	—			—			1			—
Contract Services	66			66			37			24
Corporate	—			—			—			—
Eliminations	(21		)	(17		)	(14		)	(9		)
Total	$	228		$	147		$	78		$	48
Depreciation and Amortization
Gathering and Processing	$	159		$	87		$	46		$	25
Natural Gas Transportation	—			—			—			—
NGL Services	—			—			—			—
Contract Services	86			78			29			16
Corporate	7			4			1			1
Eliminations	—			—			—			—
Total	$	252		$	169		$	76		$	42

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	Successor							Predecessor
	Year Ended December 31, 2012			Year Ended December 31, 2011		Period from Acquisition (May 26, 2010) to December 31, 2010		Period from  January 1, 2010 to May 25, 2010
Income from Unconsolidated Affiliates
Gathering and Processing	$	(10	)	$	—	$	—	$	—
Natural Gas Transportation	71			92		54		16
NGL Services	44			28		—		—
Contract Services	—			—		—		—
Corporate	—			—		—		—
Eliminations	—			—		—		—
Total	$	105		$	120	$	54	$	16
Expenditures for Long-Lived Assets
Gathering and Processing	$	395		$	282	$	93	$	44
Natural Gas Transportation	—			—		—		—
NGL Services	—			—		—		—
Contract Services	164			120		62		18
Corporate	1			4		4		2
Eliminations	—			—		—		—
Total	$	560		$	406	$	159	$	64
						December 31, 2012		December 31, 2011
Assets
Gathering and Processing						$	4,210	$	1,960
Natural Gas Transportation						1,232		1,297
NGL Services						948		629
Contract Services						1,672		1,621
Corporate						61		61
Eliminations						—		—
Total						$	8,123	$	5,568
Investment in Unconsolidated Affiliates
Gathering and Processing						$	35	$	—
Natural Gas Transportation						1,231		1,296
NGL Services						948		629
Contract Services						—		—
Corporate						—		—
Eliminations						—		—
Total						$	2,214	$	1,925
Goodwill
Gathering and Processing						$	651	$	313
Natural Gas Transportation						—		—
NGL Services						—		—
Contract Services						477		477
Corporate						—		—
Eliminations						—		—
Total						$	1,128	$	790

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

	Successor										Predecessor
	Year Ended December 31, 2012				Year Ended December 31, 2011			Period from  Acquisition (May 26, 2010) to December 31, 2010			Period from  January 1, 2010 to May 25, 2010
Total segment margin	$	613			$	421		$	212		$	147
Operation and maintenance	(228		)		(147		)	(78		)	(48		)
General and administrative	(100		)		(67		)	(44		)	(37		)
(Loss) gain on assets sales, net	(3		)		2			—			—
Depreciation and amortization	(252		)		(169		)	(76		)	(42		)
Income from unconsolidated affiliates	105				120			54			16
Interest expense, net	(122		)		(103		)	(48		)	(35		)
Loss on debt refinancing, net	(8		)		—			(16		)	(2		)
Other income and deductions, net	29			*	17			(8		)	(4		)
Income (loss) from continuing operations before income taxes	$	34			$	74		$	(4	)	$	(5	)

__________________

* 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.

LTIP compensation expense of $5 million, $3 million, $2 million and $12 million is recorded in general and administrative expense in the statement of operations for the years ended December 31, 2012, December 31, 2011 and for the periods from May 26, 2010 to December 31, 2010 and from January 1, 2010 to May 25, 2010, respectively. In 2010, upon the change of control from GE EFS to ETE, all then non-vested restricted and phantom units, exclusive of the May 7, 2010 phantom unit grants described below, vested during the predecessor period and the Partnership recorded a one-time general and administrative charge of $10 million as a result of such unit vesting.

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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 years ended December 31, 2012, 2011, and 2010 is as follows:

2012
Common Unit Options	Units		Weighted Average Exercise Price
Outstanding at the beginning of period	156,850		$	21.99
Forfeited or expired	(300	)	23.73
Outstanding at end of period	156,550		21.96
Exercisable at the end of the period	156,550
2011
Common Unit Options	Units		Weighted Average Exercise Price
Outstanding at the beginning of period	201,950		$	21.93
Exercised	(38,300	)	20.84
Forfeited or expired	(6,800	)	26.72
Outstanding at end of period	156,850		21.99
Exercisable at the end of the period	156,850
2010
Common Unit Options	Units		Weighted Average Exercise Price
Outstanding at the beginning of period	306,651		$	21.50
Exercised	(100,200	)	20.60
Forfeited or expired	(4,501	)	23.73
Outstanding at end of period	201,950		21.93
Exercisable at the end of the period	201,950

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 3.4 years. Intrinsic value is the closing market price of a unit less the option strike price, multiplied by the number of unit options outstanding as of the end of the period presented. Unit options with an exercise price greater than the end of the period closing market price are excluded.

Restricted (Non-Vested) Units. The fair value of each restricted (non-vested) unit is determined using the grant date closing price of the Partnership’s common units. All outstanding restricted units vested on May 25, 2010, and the Partnership did not issue any additional restricted units during the remainder of 2010, 2011 or 2012. Restricted (non-vested) common unit activity for the year ended December 31, 2010 is as follows:

2010
Restricted (Non-Vested) Common Units	Units		Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period	464,009		$	28.36
Granted	—		—
Vested	(444,759	)	28.19
Forfeited or expired	(19,250	)	32.35
Outstanding at the end of period	—		—

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Phantom Units. All phantom units granted prior to November 2010 were in substance two grants composed of (1) service condition grants with graded vesting over three years; and (2) market condition grants with cliff vesting based upon the Partnership’s relative ranking in total unitholder return among 20 peer companies. Upon the change in control from GE EFS to ETE, all then-outstanding phantom units, exclusive of the May 7, 2010 grant described below, vested. The service condition grants vested at a rate of 100% and the market condition grants vested at a rate of 150% pursuant to the terms of the awards. Subsequent to November 2010, all phantom units granted are service condition grants that vest at a rate of 100%.

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 over the next five years on a cliff basis; by vesting 60% at the end of the third year of service and vesting the remaining 40% at the end of the fifth year of service. 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 the next five years. Distributions on the phantom units (including non-vested units) will be paid concurrent with the Partnership’s distribution for common units.

During 2011, the Partnership awarded 596,320 phantom units to senior management and certain key employees. These awards are service condition (time-based) grants that generally vest ratably over the next five years. Distributions on the phantom units (including non-vested units) will be paid concurrent with the Partnership’s distribution for common units.

In November and December 2010, the Partnership awarded 574,700 phantom units to senior management and certain key employees. These awards are service condition (time-based) grants that generally vest ratably over the next five years. Distributions on the phantom units (including non-vested units) will be paid concurrent with the Partnership’s distribution for common units.

On November 21, 2010, Mr. Byron R. Kelley, the Partnership’s former President and Chief Executive Officer, retired. The Partnership entered into a consulting agreement with Mr. Kelley, pursuant to which Mr. Kelley will provide consulting services to the Partnership for a term of three years and received a grant of 33,000 service condition (time-based) phantom units. Distributions on the phantom units (including non-vested units) will be paid concurrent with the Partnership’s distribution for common units.

On May 7, 2010, the Partnership awarded 247,500 phantom units to senior management and certain key employees. These phantom units include a provision that will accelerate vesting (1) upon a change in control and (2) within 12 months of a change in control, if the grantee’s employment is terminated by the Partnership without “Cause” (as defined in the Form of Grant of Phantom Units) or the grantee resigns for “Good Reason” (as defined in the Form of Grant of Phantom Units). Distributions related to these unvested phantom units will be accrued and paid upon vesting.

The following table presents phantom unit activity for the years ended December 31, 2012, 2011 and 2010:

2012
Phantom Units	Units		Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period	1,086,393		$	24.51
Service condition grants	503,625		21.39
Vested service condition	(223,258	)	24.71
Vested market condition	(10,200	)	19.52
Forfeited service condition	(120,868	)	24.85
Forfeited market condition	(4,350	)	19.52
Total outstanding at end of period	1,231,342		23.22
2011
Phantom Units	Units		Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period	742,517		$	23.61
Service condition grants	596,320		24.55
Vested service condition	(142,520	)	24.73
Vested market condition	(8,550	)	19.52
Forfeited service condition	(88,474	)	24.99
Forfeited market condition	(12,900	)	19.52
Total outstanding at end of period	1,086,393		24.51

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2010
Phantom Units	Units		Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period	301,700		$	8.63
Service condition grants	716,200		24.72
Market condition grants	148,500		11.89
Vested service condition	(166,173	)	11.63
Vested market condition	(200,610	)	5.85
Forfeited service condition	(18,787	)	20.18
Forfeited market condition	(38,313	)	11.43
Total outstanding at end of period	742,517		23.61

The Partnership expects to recognize $25 million of compensation expense related to non-vested phantom units over a period of 5 years.

18. Quarterly Financial Data (Unaudited)

2012	Quarter Ended December 31			Quarter Ended September 30			Quarter Ended June 30		Quarter Ended March 31
Operating revenues	$	587		$	527		$	511	$	375
Operating (loss) income	8			5			22		(5		)
Net (loss) income attributable to Regency Energy Partners LP	(7		)	(1		)	27		15
Earnings per common units:
Basic net (loss) income per common unit	(0.08		)	(0.04		)	0.14		0.15
Diluted net (loss) income per common unit	(0.08		)	(0.04		)	0.10		0.14
2011	Quarter Ended December 31			Quarter Ended September 30			Quarter Ended June 30		Quarter Ended March 31
Operating revenues	$	370		$	390		$	357	$	317
Operating income	13			14			5		8
Net income attributable to Regency Energy Partners LP	13			30			15		14
Earnings per common units:
Basic net income per common unit	0.06			0.18			0.08		0.08
Diluted net income per common unit	0.06			0.09			0.07		0.07

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