8-K

UNITED STATES

 SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

Current Report Pursuant to Section 13 OR 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): February 16, 2012 (February 15, 2012)

REGENCY ENERGY PARTNERS LP

(Exact name of registrant as specified in its charter)

DELAWARE	001-35262	16-1731691
(State or other jurisdiction of  incorporation)	(Commission File Number)	(IRS Employer  Identification No.)

2001 Bryan Street, Suite 3700

 Dallas, Texas 75201

 (Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code (214) 750-1771

(Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 2.02 Results of Operations and Financial Condition.

On February 15, 2012, Regency Energy Partners LP (the “Partnership”) issued a press release announcing its financial and operating results for the fourth quarter and the full year ended December 31, 2011. A copy of this press release is furnished as Exhibit 99.1 to this report and is incorporated herein by reference.

Item 7.01 Regulation FD Disclosure.

In conjunction with the above earnings release, on February 16, 2012, the management of the Partnership expects to present information concerning its business to investors and other interested parties. The materials to be utilized in the presentation are furnished as Exhibit 99.2 hereto and are incorporated herein by reference.

In accordance with General Instruction B.2 of Form 8-K, the information set forth in Items 2.02 and 7.01 and in the attached exhibits shall be deemed to be “furnished” and not be deemed to be “filed” for purposes of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

Item 9.01 Financial Statements and Exhibits.

(d)Exhibits. In accordance with General Instruction B.2 of Form 8-K, the information set forth in the attached Exhibit 99.1 and Exhibit 99.2 are deemed to be “furnished” and shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act.

Exhibit
Number	Description
Exhibit 99.1	Regency Energy Partners LP Press Release dated February 15, 2012 announcing the results of its operations for the fourth quarter and the full year ended December 31, 2011.
Exhibit 99.2	Regency Energy Partners LP presentation to investors dated February 16, 2012.

SIGNATURES

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

REGENCY ENERGY PARTNERS LP  By: Regency GP LP, its general partner  By: Regency GP LLC, its general partner
By:	/s/ Thomas E. Long
	Thomas E. Long
	Executive Vice President and Chief Financial Officer

February 16, 2012

EX-99.1

Exhibit 99.1

Regency Energy Partners Reports Increases In Fourth-Quarter

and Full-Year 2011 Results

Full-Year 2011 Adjusted EBITDA Increased 29% Over 2010

DALLAS, February 15, 2012 – Regency Energy Partners LP (NYSE: RGP), (“Regency” or the “Partnership”), announced today its financial results for the fourth quarter and full year ended December 31, 2011.

For full-year 2011, adjusted EBITDA increased 29% to $422 million, compared to $327 million in 2010. Adjusted EBITDA increased by 13% for the fourth quarter of 2011, compared to the fourth quarter of 2010. These increases were primarily attributable to the acquisition of a 30% interest in the Lone Star Joint Venture in May 2011 and an increase in the adjusted segment margin in the Gathering and Processing segment due to increased volumes in south and west Texas. The full-year increase was also partly due to a full-year contribution from the MEP Joint Venture in 2011, compared to a partial-year contribution in 2010.

For full-year 2011, net income increased to $74 million, compared a net loss of $11 million in 2010. Net income increased to $14 million for the fourth quarter of 2011, compared to a net loss of $9 million for the fourth quarter of 2010.

“Our acquisition of an interest in the Lone Star Joint Venture added a predominantly fee-based natural gas liquids platform to Regency’s portfolio which when combined with increased volumes in south and west Texas, led to solid year-over-year adjusted EBITDA growth,” said Mike Bradley, president and chief executive officer of Regency.

“Looking ahead, our assets are strongly positioned within liquids-rich plays, and I expect us to continue delivering strong results for our unitholders as more than $1 billion of organic growth projects come online in the next 18 months. These expansions will further extend our footprint in the key shales,” continued Bradley.

REVIEW OF SEGMENT PERFORMANCE

Adjusted total segment margin increased 8% to $421 million for full-year 2011, compared to $390 million for full-year 2010.

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

Adjusted segment margin for the Gathering and Processing segment, which excludes non-cash hedging gains and losses, was $234 million for full-year 2011, compared to $226 million for full-year 2010.  The increase was primarily due to volume growth in the Eagle Ford Shale in south Texas and the Permian Delaware Basin in west Texas.

Total throughput volumes for the Gathering and Processing segment increased 19% to 1.2 million MMbtu per day of natural gas for full-year 2011, compared to 1.0 million MMbtu per day of natural gas for full-year 2010. Processed NGLs increased to 32,000 barrels per day for full-year 2011, compared to 26,000 barrels per day for full-year 2010.

Joint Ventures – The Joint Ventures segment, formerly called the Transportation segment, consists of a 49.99% interest in the Haynesville Joint Venture, a 50% interest in the MEP Joint Venture, a 30% interest in the Lone Star Joint Venture and a 33.33% interest in the Ranch Joint Venture. Since Regency uses the equity method of accounting for these joint ventures, Regency does not record segment margin for the Joint Ventures segment. Rather, the income attributable to each of the joint ventures is recorded as income from unconsolidated affiliates.

For full-year 2011, Regency reported income from unconsolidated affiliates of $120 million, compared to $69 million for full-year 2010.

The Haynesville Joint Venture consists solely of the Regency Intrastate Gas System and is operated by Regency. Income from unconsolidated affiliates for the Haynesville Joint Venture was $49 million for full-year 2011, compared to $48 million for full-year 2010. Total throughput volumes for the Haynesville Joint Venture averaged 1.3 million MMbtu per day of natural gas for full-year 2011 and 2010.

The MEP Joint Venture consists solely of the Midcontinent Express Pipeline (“MEP”), which is operated by Kinder Morgan Energy Partners, L.P. Income from unconsolidated affiliates for the MEP Joint Venture increased to $43 million for full-year 2011 from $21 million for full-year 2010. The increase was primarily related to reporting a full year of operations as we acquired MEP in May 2010. Total throughput volumes for the MEP Joint Venture averaged 1.4 million MMbtu per day of natural gas for full-year 2011 and 2010.

The Lone Star Joint Venture, which was acquired in May 2011, owns and operates NGL storage, fractionation and transportation assets, and is operated by Energy Transfer Partners, L.P. From June to December 2011, income from unconsolidated affiliates for the Lone Star Joint Venture was $28 million. From May to December 2011, total throughput volumes for the West Texas Pipeline averaged 130,000 barrels per day and NGL Fractionation Throughput volumes averaged 16,000 barrels per day.

The Ranch Joint Venture was created in December 2011 by Regency, Anadarko Pecos Midstream LLC and Chesapeake West Texas Processing, L.L.C., each owning one third of the joint venture interest. As of December 31, 2011, the Ranch Joint Venture was constructing a processing facility in Ward County, Texas, to process natural gas delivered from the liquids-rich Bone Spring and Avalon shale formations, and is expected in service in 2012.

Contract Compression – The Contract Compression segment provides turn-key natural gas compression services for customer-specific systems.

Segment margin for the Contract Compression segment, excluding intercompany segment margin, was $139 million for full-year 2011, compared to $131 million for full-year 2010. As of December 31, 2011, the Contract Compression segment’s revenue generating horsepower was 777,000, compared to 767,000 as of December 31, 2010.

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

Segment margin for the Contract Treating segment was $29 million for full-year 2011, compared to $11 million for the full-year 2010. The Contract Treating segment was acquired in September 2010. As of December 31, 2011, revenue generating gallons per minute (“GPM”) was 3,465, compared to 3,431 as of December 31, 2010.

Corporate and Others – The Corporate and Others segment is primarily comprised of revenues from the operations of a 10-mile interstate pipeline, as well as partial reimbursements of general and administrative costs from the Haynesville Joint Venture.  Segment margin in the Corporate and Others segment was $19 million for full-year 2011, compared to $21 million for full-year 2010.

ORGANIC GROWTH

In the twelve months ended December 31, 2011, Regency invested $407 million in growth capital projects, of which $250 million was related to organic growth projects in the Gathering and Processing segment; $94 million was related to the fabrication of new compressor packages for the Contract Compression segment; $53 million was related to the Lone Star Joint Venture; $6 million was related to the fabrication of new treating plants for the Contract Treating segment; and $4 million in the Corporate and Others segment.

In 2012, Regency expects to invest between $720 and $770 million in growth capital expenditures, of which $245 million is expected to be invested in organic growth projects in the Gathering and Processing segment, including a portion for the south Texas gathering system expansion; between $350 and $400 million is expected to be invested in the Lone Star Joint Venture; $70 million is expected to be invested in the fabrication of new compressor packages for the Contract Compression segment; $35 million is expected to be invested in its portion of growth capital expenditures for the Ranch Joint Venture; $15 million is expected to be invested in the fabrication of new treating plants for the Contract Treating segment; and $5 million is expected to be invested in the Corporate and Others segment.

CASH DISTRIBUTIONS

On January 26, 2012, Regency announced a cash distribution of $0.46 per outstanding common unit for the fourth quarter ended December 31, 2011. This distribution is equivalent to $1.84 per outstanding common unit on an annual basis and was paid on February 13, 2012, to unitholders of record at the close of business on February 6, 2012.

Based on the terms of the agreement, the Series A Preferred Units were paid a quarterly distribution of $0.445 per unit for the fourth quarter ended December 31, 2011, on the same schedule as set forth above.

In the fourth quarter of 2011, Regency generated $82 million in cash available for distribution, representing coverage of 1.09 times the amount required to cover its announced distribution to unitholders.

Regency makes distribution determinations based on its cash available for distribution and the perceived sustainability of distribution levels over an extended period. In addition to considering the cash available for distribution generated during the quarter, Regency takes into account cash reserves established with respect to prior distributions, seasonality of results, and its internal forecasts of adjusted EBITDA and cash available for distribution over an extended period. Distributions are set by the Board of Directors and are driven by the long-term sustainability of the business.

TELECONFERENCE

Regency Energy Partners will hold a quarterly conference call to discuss fourth-quarter and full-year 2011 results on Thursday, February 16, 2012 at 10 a.m. Central Time (11 a.m. Eastern Time).

The dial-in number for the call is 1-888-873-4896 in the United States, or +1-617-213-8850 outside the United States, passcode 79449952. A live webcast of the call may be accessed on the investor relations page of Regency’s website at www.regencyenergy.com.  The call will be available for replay for seven days by dialing 1-888-286-8010 (from outside the U.S., +1-617-801-6888) passcode 15995776. A replay of the broadcast will also be available on the Partnership’s website for 30 days.

NON-GAAP FINANCIAL INFORMATION

This press release and the accompanying financial schedules include the non-GAAP financial measures of:

·   EBITDA;

·   adjusted EBITDA;

·   cash available for distribution;

·   segment margin;

·   total segment margin;

·   adjusted segment margin; and

·   adjusted total segment margin.

These financial metrics are key measures of the Partnership’s financial performance.  The accompanying schedules provide reconciliations of these non-GAAP financial measures to their most directly-comparable financial measures calculated and presented in accordance with accounting principles generally accepted in the United States of America ("GAAP"). Our non-GAAP financial measures should not 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 as a measure of operating performance, liquidity or ability to service debt obligations.

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 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 methods 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 is the starting point in determining cash available for distribution, which is an important non-GAAP financial measure for a publicly traded partnership.

We define cash available for distribution as adjusted EBITDA:

·   minus interest expense, excluding capitalized interest;

·   minus maintenance capital expenditures;

·   plus cash proceeds from asset sales, if any; and

·   joint venture adjustments, which mainly include interest expense and maintenance capital expenditures.

Cash available for distribution is used as a supplemental liquidity measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to approximate the amount of operating surplus generated by us during a specific period and to assess our ability to make cash distributions to our unitholders and our general partner. Cash available for distribution is not the same measure as operating surplus or available cash, both of which are defined in our partnership agreement.

We calculate our Gathering and Processing and the Corporate and Others 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 the Joint Ventures segment because we record our ownership percentage of the net income in these joint ventures as income from unconsolidated affiliates.

We calculate our Contract Compression segment margin as our revenues minus the direct costs, primarily compressor unit repairs, associated with those revenues.

We calculate our Contract Treating segment margin as our revenues minus direct costs associated with those revenues.

We calculate total segment margin as the summation of segment margin of our five 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, 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 our revenues and cost of revenues, a key component of our operations.

FORWARD-LOOKING INFORMATION

This release contains “forward-looking” statements, which are any statements that do not relate strictly to historical facts.  The words “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “plan,” “project,” “will” or similar expressions help identify forward-looking statements.  Forward-looking statements are subject to a variety of risks, uncertainties and assumptions, which include, but are not limited to, the risks, uncertainties and assumptions enumerated in our Forms 10-Q and 10-K as filed with the Securities and Exchange Commission.  Although we believe our forward-looking statements are based on reasonable assumptions, current expectations and projections about future events, we cannot give assurances that such assumptions, expectations and projections will prove to be correct.  Therefore, actual results and outcomes may differ materially from those expressed in such forward-looking statements.  We undertake no obligation to update publicly or to revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Regency Energy Partners LP (NYSE: RGP) is a growth-oriented, midstream energy partnership engaged in the gathering and processing, contract compression, treating,  transportation of natural gas, and the fractionation and storage of natural gas liquids. Regency's general partner is owned by Energy Transfer Equity, L.P. (NYSE: ETE). For more information, visit the Regency Energy Partners LP website at www.regencyenergy.com.

CONTACT:

Investor Relations:

Lyndsay Hannah

Regency Energy Partners

Manager, Finance & Investor Relations

214-840-5477

ir@regencygas.com

Media Relations:

Vicki Granado

Granado Communications Group

214-599-8785

vicki@granadopr.com

Consolidated Income Statement

Regency Energy Partners LP
Consolidated Statements of Operations
($ in thousands)
	Three Months Ended
	December 31, 2011			December 31, 2010			December 31, 2009
REVENUES
Gas sales, including related party amounts	$	94,105		$	111,876		$	127,840
NGL sales, including related party amounts		172,343			120,547			81,201
Gathering, transportation and other fees, including related party amounts		95,496			84,014			64,538
Net realized and unrealized (loss) gain from derivatives		(4,578	)		(1,518	)		1,736
Other, including related party amounts		12,515			7,826			7,035
Total revenues		369,881			322,745			282,350
OPERATING COSTS AND EXPENSES
Cost of sales, including related party amounts		257,564			221,121			196,852
Operation and maintenance		42,025			33,100			26,809
General and administrative, including related party amounts		13,510			18,563			14,532
(Gain) loss on asset sales, net		(2,422	)		3			106
Depreciation and amortization		45,989			33,217			26,174
Total operating costs and expenses		356,666			306,004			264,473
OPERATING INCOME		13,215			16,741			17,877
Income from unconsolidated affiliates		32,619			23,618			2,431
Interest expense, net		(28,926	)		(19,791	)		(21,945	)
Loss on debt refinancing, net		-			(15,748	)		-
Other income and deductions, net		(2,796	)		(12,232	)		(1,459	)
INCOME (LOSS) BEFORE INCOME TAXES		14,112			(7,412	)		(3,096	)
Income tax expense (benefit)		484			(143	)		(484	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		13,628			(7,269	)		(2,612	)
DISCONTINUED OPERATIONS
Net loss from operations of east Texas assets		-			(1,654	)		(735	)
NET INCOME (LOSS)	$	13,628		$	(8,923	)	$	(3,347	)
Net income attributable to noncontrolling interest		(104	)		(69	)		(30	)
NET INCOME (LOSS) ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP	$	13,524		$	(8,992	)	$	(3,377	)

Consolidated Income Statement

Regency Energy Partners LP
Consolidated Statements of Operations
($ in thousands)
	Year Ended
	December 31, 2011			December 31, 2010			December 31, 2009
REVENUES
Gas sales, including related party amounts	$	455,746		$	519,344		$	476,077
NGL sales, including related party amounts		603,219			390,879			239,255
Gathering, transportation and other fees, including related party amounts		350,745			293,295			270,071
Net realized and unrealized (loss) gain from derivatives		(19,214	)		(8,582	)		37,712
Other, including related party amounts		43,402			26,727			20,162
Total revenues		1,433,898			1,221,663			1,043,277
OPERATING COSTS AND EXPENSES
Cost of sales, including related party amounts		1,012,826			862,105			674,944
Operation and maintenance		147,643			125,650			117,080
General and administrative, including related party amounts		67,408			80,951			57,863
(Gain) loss on asset sales, net		(2,372	)		516			(133,282	)
Depreciation and amortization		168,684			117,751			100,098
Total operating costs and expenses		1,394,189			1,186,973			816,703
OPERATING INCOME		39,709			34,690			226,574
Income from unconsolidated affiliates		119,540			69,365			7,886
Interest expense, net		(102,474	)		(82,792	)		(77,665	)
Loss on debt refinancing, net		-			(17,528	)		-
Other income and deductions, net		17,309			(12,126	)		(15,132	)
INCOME (LOSS) BEFORE INCOME TAXES		74,084			(8,391	)		141,663
Income tax expense (benefit)		465			956			(1,095	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		73,619			(9,347	)		142,758
DISCONTINUED OPERATIONS
Net loss from operations of east Texas assets		-			(1,571	)		(2,269	)
NET INCOME (LOSS)	$	73,619		$	(10,918	)	$	140,489
Net income attributable to noncontrolling interest		(1,177	)		(562	)		(91	)
NET INCOME (LOSS) ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP	$	72,442		$	(11,480	)	$	140,398

Segment Financial and Operating Data

	Three Months Ended December 31,						Year Ended December 31,
	2011		2010		2009		2011		2010		2009
	($ in thousands)
Gathering and Processing Segment
Financial data:
Segment margin	$	64,452	$	52,915	$	50,982	$	233,463	$	196,008	$	213,920
Adjusted segment margin		63,901		59,731		52,139		233,518		226,191		206,769
Operating data:
Throughput (MMbtu/d)		1,349,592		1,029,597		1,000,748		1,187,149		996,800		975,963
NGL gross production (Bbls/d)		36,382		29,327		22,725		31,902		26,155		21,104

	Three Months Ended December 31,									Year Ended December 31,
	2011			2010			2009			2011			2010			2009
	($ in thousands)
Contract Compression Segment
Financial data:
Segment margin	$	39,203		$	40,855		$	34,163		$	155,573		$	154,209		$	141,028
Less: Inter-segment elimination		(3,902	)		(6,212	)		(1,611	)		(16,704	)		(23,205	)		(4,604	)
Segment margin, net of inter-segment elimination	$	35,301		$	34,643		$	32,552		$	138,869		$	131,004		$	136,424
Operating data:
Revenue generating horsepower		776,799			766,882			716,120			776,799			766,882			716,120

	Three Months Ended December 31,				Year Ended December 31,
	2011		2010		2011		2010
	($ in thousands)
Contract Treating Segment
Financial data:
Segment margin	$	7,862	$	8,725	$	29,456	$	11,454
Operating data:
Revenue generating gallons per minute		3,465		3,431		3,465		3,431

	Three Month Ended December 31,			Year Ended December 31,
	2011	2010	2009	2011	2010	2009
	($ in thousands)
Corporate & Others
Financial data:
Segment margin	$                  4,702	$                  5,341	$                  1,964	$                19,284	$                21,092	$                  6,275

The following provides key performance measures for 100% of the Haynesville Joint Venture, the MEP Joint Venture and the Lone Star Joint Venture

	Three Months Ended December 31,						Year Ended December 31,
	2011		2010		2009		2011		2010		2009
	($ in thousands)
Haynesville Joint Venture
Financial data:
Segment margin	$	43,901	$	47,450	$	12,157	$	183,309	$	174,347	$	52,051
Operating data:
Throughput (MMbtu/d)		1,054,392		1,543,570		640,166		1,321,266		1,277,881		738,654

	Three Months Ended December 31,				Year Ended December 31,
	2011		2010		2011		2010
	($ in thousands)
MEP Joint Venture
Financial data:
Segment margin	$	62,815	$	57,799	$	246,758	$	212,345
Operating data:
Throughput (MMbtu/d)		1,380,010		1,541,533		1,360,658		1,408,778

	Three Months Ended December 31, 2011		From May 2, 2011 (Initial Acquisition date) through December 31, 2011
	($ in thousands)
Lone Star Joint Venture
Financial data:
Segment margin	$	66,931	$	178,718
Operating data:
West Texas Pipeline Throughput (Bbls/d)		128,681		130,246
NGL Fractionation Throughput (Bbls/d)		18,464		15,676

The following provides a reconciliation of segment margin to net income for 100% of the Haynesville Joint Venture, the MEP Joint Venture and the Lone Star Joint Venture

	Three Months Ended December 31,								Year Ended December 31,
	2011		2010			2009			2011			2010			2009
	($ in thousands)
Net income - Haynesville Joint Venture	$	24,483	$	32,097		$	5,770		$	109,186		$	106,737		$	26,867
Add:
Operation and maintenance		5,747		2,296			1,853			20,803			17,518			9,697
General and administrative		4,124		4,436			2,013			17,161			17,759			5,702
Loss on asset sales, net		-		-			116			-			105			-
Depreciation and amortization		9,084		8,474			2,669			34,930			31,797			10,962
Interest expense, net		463		171			93			1,245			526			158
Other income and deductions, net		-		(24	)		(357	)		(16	)		(95	)		(1,335	)
Total Segment Margin	$	43,901	$	47,450		$	12,157		$	183,309		$	174,347		$	52,051

	Three Months Ended December 31,						Year Ended December 31,
	2011			2010			2011		2010
	($ in thousands)
Net income - MEP Joint Venture	$	22,655		$	18,110		$	85,339	$	60,173
Add:
Operation and maintenance		3,585			8,650			13,585		21,815
General and administrative		6,328			864			26,780		16,440
Depreciation and amortization		17,362			17,402			69,538		66,929
Interest expense, net		12,889			12,774			51,515		48,751
Other income and deductions, net		(4	)		(1	)		1		(1,763	)
Total Segment Margin	$	62,815		$	57,799		$	246,758	$	212,345

	Three Months Ended December 31, 2011			From May 2, 2011 (Initial Acquisition date) through December 31, 2011
	($ in thousands)
Net income - Lone Star Joint Venture	$	35,049		$	93,959
Add:
Operation and maintenance		16,194			39,254
General and administrative		3,719			13,326
Depreciation and amortization		12,205			32,248
Tax expense		630			833
Other income and deductions, net		(866	)		(902	)
Total Segment Margin	$	66,931		$	178,718

Reconciliation of Non-GAAP Measures to GAAP Measures

	Three Months Ended December 31,
	2011			2010			2009
	($ in thousands)
Net income (loss)	$	13,628		$	(8,923	)	$	(3,347	)
Add (deduct):
Interest expense, net		28,926			19,791			22,028
Depreciation and amortization		45,989			33,217			28,759
Income tax expense (benefit)		484			(143	)		(484	)
EBITDA (1)	$	89,027		$	43,942		$	46,956
Add (deduct):
Non-cash loss from commodity and embedded derivatives		2,230			18,922			2,124
Non-cash unit based compensation		923			1,386			1,613
(Gain) loss on asset sales, net		(2,422	)		78			106
Income from unconsolidated affiliates		(32,619	)		(23,618	)		(2,431	)
Partnership's ownership interest in Haynesville Joint Venture's adjusted EBITDA (2)		17,012			20,374			3,621
Partnership's ownership interest in MEP Joint Venture's adjusted EBITDA (3)		26,455			24,095			-
Partnership's ownership interest in Lone Star Joint Venture's adjusted EBITDA (4)		14,105			-			-
Loss on debt refinancing, net		-			15,748			-
Other expense, net		189			831			698
Adjusted EBITDA	$	114,900		$	101,758		$	52,687
(1) Earnings before interest, taxes, depreciation and amortization.
(2) 100% of Haynesville Joint Venture's Adjusted EBITDA is calculated as follows:
Net income Haynesville Joint Venture	$	24,483		$	32,097		$	5,655
Add (deduct):
Depreciation and amortization		9,084			8,474			2,669
Interest expense		463			171			93
Gain on insurance settlement		-			7			-
Gain on sale of asset, net		-			(1	)		-
Other expense, net		-			9			5
Haynesville Joint Venture's Adjusted EBITDA	$	34,030		$	40,757		$	8,422
Net income MEP Joint Venture	$	22,655		$	18,110		$	-
Add:
Depreciation and amortization		17,362			17,402			-
Other expense		12,892			12,774			-
MEP Joint Venture's Adjusted EBITDA	$	52,909		$	48,286		$	-
(4) 100% of Lone Star Joint Venture's Adjusted EBITDA is calculated as follows:
Net income Lone Star Joint Venture	$	35,049		$	-		$	-
Add (deduct):
Depreciation and amortization		12,205			-			-
Other income, net		(237	)		-			-
Lone Star Joint Venture's Adjusted EBITDA	$	47,017		$	-		$	-

Reconciliation of Non-GAAP Measures to GAAP Measures

	Year Ended December 31,
	2011			2010			2009
	($ in thousands)
Net income (loss)	$	73,619		$	(10,918	)	$	140,489
Add (deduct):
Interest expense, net		102,474			82,971			77,996
Depreciation and amortization		168,684			122,725			109,893
Income tax expense (benefit)		465			956			(1,095	)
EBITDA (1)	$	345,242		$	195,734		$	327,283
Add (deduct):
Non-cash (gain) loss from derivatives		(17,919	)		42,613			5,163
Non-cash unit based compensation		3,610			13,727			5,834
(Gain) loss on asset sales, net		(2,372	)		591			(133,284	)
Income from unconsolidated affiliates		(119,540	)		(69,365	)		(7,886	)
Partnership's ownership interest in Haynesville Joint Venture's adjusted EBITDA (2)		72,672			67,014			11,398
Partnership's ownership interest in MEP Joint Venture's adjusted EBITDA (3)		103,059			55,682			-
Partnership's ownership interest in Lone Star Joint Venture's adjusted EBITDA (4)		37,841			-			-
Loss on debt refinancing, net		-			17,528			-
Other (income) expense, net		(224	)		3,432			2,486
Adjusted EBITDA	$	422,369		$	326,956		$	210,994
(1) Earnings before interest, taxes, depreciation and amortization.
(2) 100% of Haynesville Joint Venture's Adjusted EBITDA is calculated as follows:
Net income Haynesville Joint Venture	$	109,186		$	106,737		$	19,734
Add (deduct):
Depreciation and amortization		34,930			31,797			8,514
Interest expense		1,245			526			158
Gain on insurance settlement		-			(242	)		-
Loss on sale of asset, net		-			105			-
Other expense, net		16			14			50
Haynesville Joint Venture's Adjusted EBITDA	$	145,377		$	138,937		$	28,456
(3) 100% of MEP Joint Venture's Adjusted EBITDA is calculated as follows:
Net income MEP Joint Venture	$	85,339		$	42,528		$	-
Add:
Depreciation and amortization		69,538			40,103			-
Interest expense, net		51,515			28,959			-
MEP Joint Venture's Adjusted EBITDA	$	206,392		$	111,590		$	-
(4) 100% of Lone Star Joint Venture's Adjusted EBITDA is calculated as follows and represents the period from May 2, 2011 to December 31, 2011. The Partnership acquired its 30% ownership interest on May 2, 2011:
Net income Lone Star Joint Venture	$	93,959		$	-		$	-
Add (deduct):
Depreciation and amortization		32,248			-			-
Other income, net		(68	)		-			-
Lone Star Joint Venture's Adjusted EBITDA	$	126,139		$	-		$	-

Non-GAAP Adjusted Total Segment Margin to GAAP Net Income

	Three Months Ended December 31,
	2011			2010			2009
	($ in thousands)
Net income (loss)	$	13,628		$	(8,923	)	$	(3,347	)
Add (Deduct):
Operation and maintenance		42,025			33,100			26,809
General and administrative		13,510			18,563			14,532
(Gain) loss on asset sales, net		(2,422	)		3			106
Depreciation and amortization		45,989			33,217			26,174
Income from unconsolidated affiliates		(32,619	)		(23,618	)		(2,431	)
Interest expense, net		28,926			19,791			21,945
Loss on debt refinancing, net		-			15,748			-
Other income and deductions, net		2,796			12,232			1,459
Income tax expense (benefit)		484			(143	)		(484	)
Discontinued operations		-			1,654			735
Total Segment Margin		112,317			101,624			85,498
Non-cash (gain) loss from derivatives		(551	)		6,816			1,157
Adjusted Total Segment Margin	$	111,766		$	108,440		$	86,655
Gathering & Processing Segment Margin	$	64,452		$	52,915		$	50,982
Non-cash (gain) loss from derivatives		(551	)		6,816			1,157
Adjusted Gathering and Processing Segment Margin		63,901			59,731			52,139
Contract Compression Segment Margin		39,203			40,855			34,163
Contract Treating Segment Margin		7,862			8,725			-
Corporate & Others Segment Margin		4,702			5,341			1,964
Inter-segment Elimination		(3,902	)		(6,212	)		(1,611	)
Adjusted Total Segment Margin	$	111,766		$	108,440		$	86,655

Non-GAAP Adjusted Total Segment Margin to GAAP Net Income

	Year Ended December 31,
	2011			2010			2009
	($ in thousands)
Net income (loss)	$	73,619		$	(10,918	)	$	140,489
Add (Deduct):
Operation and maintenance		147,643			125,650			117,080
General and administrative		67,408			80,951			57,863
(Gain) loss on asset sales, net		(2,372	)		516			(133,282	)
Depreciation and amortization		168,684			117,751			100,098
Income from unconsolidated subsidiaries		(119,540	)		(69,365	)		(7,886	)
Interest expense, net		102,474			82,792			77,665
Loss on debt refinancing, net		-			17,528			-
Other income and deductions, net		(17,309	)		12,126			15,132
Income tax expense (benefit)		465			956			(1,095	)
Discontinued operations		-			1,571			2,269
Total Segment Margin		421,072			359,558			368,333
Non-cash loss (gain) from derivatives		55			30,183			(7,151	)
Adjusted Total Segment Margin	$	421,127		$	389,741		$	361,182
Gathering & Processing Segment Margin	$	233,463		$	196,008		$	213,920
Non-cash loss (gain) from derivatives		55			30,183			(7,151	)
Adjusted Gathering & Processing Segment Margin		233,518			226,191			206,769
Joint Venture Segment Margin (1)		-			-			11,714
Contract Compression Segment Margin		155,573			154,209			141,028
Contract Treating Segment Margin		29,456			11,454			-
Corporate & Others Segment Margin		19,284			21,092			6,275
Inter-segment Elimination		(16,704	)		(23,205	)		(4,604	)
Adjusted Total Segment Margin	$	421,127		$	389,741		$	361,182
(1) We contributed RIGS to the Haynesville Joint Venture in March 2009, and subsequently renamed Transportation segment to Joint Ventures segment in 2011. Since March 2009, we have not recorded segment margin in this segment because we recorded our ownership percentage of the net income in unconsolidated affiliates as income from unconsolidated affiliates in accordance with the equity method of accounting.

Reconciliation of “cash available for distribution” to net cash flows provided by operating activities and to net income

	Three Months Ended
	December 31, 2011
	($ in thousands)
Net cash flows provided by operating activities		49,339
Add (deduct):
Depreciation and amortization, including debt issuance cost amortization		(47,551	)
Amortization of excess fair value of unconsolidated subsidiaries		(1,462	)
Income from unconsolidated affiliates		34,081
Derivative valuation change		(1,174	)
Gain on asset sales, net		2,422
Unit based compensation expenses		(1,166	)
Cash flow changes in trade accounts receivables, accrued revenues, and related party receivables		(4,970	)
Cash flow changes in other current assets		(548	)
Cash flow changes in trade accounts payable, accrued cost of gas and liquids, related party payables and deferred revenues		(2,754	)
Cash flow changes in other current liabilities		15,243
Distributions received from unconsolidated affiliates		(27,930	)
Cash flow changes in other assets and liabilities		98
Net Income	$	13,628
Add:
Interest expense, net		28,926
Depreciation and amortization		45,989
Income tax expense		484
EBITDA	$	89,027
Add (deduct):
Non-cash loss from commodity and embedded derivatives		2,230
Non-cash unit based compensation		923
Gain on asset sales, net		(2,422	)
Income from unconsolidated affiliates		(32,619	)
Partnership's ownership interest in Haynesville Joint Venture's adjusted EBITDA		17,012
Partnership's ownership interest in MEP Joint Venture's adjusted EBITDA		26,455
Partnership's ownership interest in Lone Star Joint Venture's adjusted EBITDA		14,105
Other expense, net		189
Adjusted EBITDA	$	114,900
Add (deduct):
Interest expense, excluding capitalized interest		(34,853	)
Maintenance capital expenditures		(7,809	)
Distribution to Series A Preferred Units		(1,945	)
Other adjustments		12,026
Cash available for distribution	$	82,319

EX-99.2

Exhibit 99.2