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): November 3, 2011 (November 2, 2011)

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 November 2, 2011, Regency Energy Partners LP (the “Partnership”) issued a press release announcing its financial and operating results for the third quarter ended September 30, 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 November 3, 2011, 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 November 2, 2011 announcing the results of its operations for the third quarter ended September 30, 2011.
Exhibit 99.2	Regency Energy Partners LP presentation to investors dated November 3, 2011.

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/ Paul M. Jolas
	Paul M. Jolas
	Executive Vice President, Chief Legal Officer and Secretary

November 3, 2011

EX-99.1

Exhibit 99.1

Regency Energy Partners Reports Third-Quarter 2011 Results

Adjusted EBITDA Increased 25% Over Third Quarter of 2010

DALLAS, Nov. 2, 2011 – Regency Energy Partners LP (NYSE: RGP), (“Regency” or the “Partnership”), announced today its financial results for the third quarter ended September 30, 2011.

Regency’s adjusted EBITDA increased 25% to $112 million in the third quarter of 2011, compared to $90 million in the third quarter of 2010. This increase was 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.

“We delivered solid year-over-year adjusted EBITDA growth for the third quarter of 2011, due mostly to increased volumes from our Eagle Ford expansion project and a full quarter’s contribution from the Lone Star Joint Venture,” said Mike Bradley, president and chief executive officer of Regency. “We have a strong foundation of assets and have announced significant organic growth projects that position Regency to deliver long-term accretion.”

REVIEW OF SEGMENT PERFORMANCE

Adjusted total segment margin increased 13% to $111 million for the third quarter of 2011, compared to $98 million for the third quarter of 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 $65 million for the third quarter of 2011, compared to $57 million for the third quarter of 2010.  The increase was primarily due to volume growth in the Eagle Ford Shale and Permian Basin.

Total throughput volumes for the Gathering and Processing segment increased 36% to 1.3 million MMbtu per day of natural gas in the third quarter of 2011, compared to 1.0 million MMbtu per day of natural gas in the third quarter of 2010. Processed NGLs increased to 35,000 barrels per day for the third quarter of 2011, compared to 27,000 barrels per day for the third quarter of 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 and a 30% interest in the Lone Star 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 the third quarter of 2011, Regency reported income from unconsolidated affiliates of $31 million, compared to $22 million for the third quarter of 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 decreased from $14 million in the third quarter of 2010 to $11 million in the third quarter of 2011. Total throughput volumes for the Haynesville Joint Venture averaged 1.5 million MMbtu per day of natural gas for the third quarter of 2010, compared to an average of 1.2 million MMbtu per day of natural gas for the third quarter of 2011.

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 from $8 million in the third quarter of 2010 to $11 million in the third quarter of 2011. Total throughput volumes for the MEP Joint Venture averaged 1.4 million MMbtu per day of natural gas for the third quarter of 2010, compared to an average of 1.3 million MMbtu per day of natural gas for the third quarter of 2011.

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. For the third quarter of 2011, income from unconsolidated affiliates for the Lone Star Joint Venture was $9 million. For the third quarter of 2011, total throughput volumes for the West Texas Pipeline averaged 133,000 barrels per day and NGL Fractionation Throughput volumes averaged 14,000 barrels per day.

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

Regency will now be presenting segment margin excluding margin from intercompany horsepower, which is eliminated upon consolidation.  Segment margin for the Contract Compression segment, excluding intercompany segment margin, was $35 million for the third quarter of 2011, compared to $33 million for the third quarter of 2010. As of September 30, 2011, our Contract Compression segment’s revenue generating horsepower was 769,000 compared to 754,000 as of September 30, 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, which was acquired in September 2010, was $7 million for the third quarter of 2011. As of September 30, 2011, revenue generating gallons per minute (“GPM”) was 3,468, compared to 3,093 as of September 30, 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 $5 million for the third quarter of 2011 compared to $6 million for the third quarter of 2010.

ORGANIC GROWTH

In the nine months ended September 30, 2011, Regency invested $258 million in growth capital projects, of which $172 million was related to organic growth projects in the Gathering and Processing segment; $68 million was related to the fabrication of new compressor packages for the Contract Compression segment; $10 million was related to the Lone Star Joint Venture; $5 million was related to the fabrication of new treating plants for the Contract Treating segment; and $3 million for vehicle fleet purchases in the Corporate and Others segment.

Regency’s $373 million of projected 2011 organic growth capital expenditures includes $200 million for the Gathering and Processing segment, which is inclusive of 2011 expenditures related to the south Texas gathering system expansion, $95 million for the Contract Compression segment, $65 million to fund Regency’s proportionate share of growth projects associated with the Lone Star Joint Venture, $9 million for the Contract Treating segment and $4 million related to the Corporate and Others segment.

In 2012, Regency expects to invest between $630 and $680 million in growth capital expenditures, of which $290 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 $250 and $300 million is expected to be invested in its portion of growth capital expenditures for the Lone Star Joint Venture; $70 million is expected to be invested in the fabrication of new compressor packages for the Contract Compression segment; $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 October 25, 2011, Regency announced a cash distribution increase to $0.455 per outstanding common unit for the third quarter ended September 30, 2011. This distribution is equivalent to $1.82 per outstanding common unit on an annual basis and will be paid on November 14, 2011, to unitholders of record at the close of business on November 7, 2011.

Based on the terms of the agreement, the Series A Preferred Units will be paid a quarterly distribution of $0.445 per unit for the third quarter ended September 30, 2011, on the same schedule as set forth above.

In the third quarter of 2011, Regency generated $73 million in cash available for distribution, representing coverage of 0.98 times the amount required to cover its announced distribution to unitholders. Excluding the 11.5 million common units issued in October 2011, the coverage ratio would have been 1.06 times.

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 third quarter 2011 results on Thursday, November 3, 2011, at 10 a.m. Central Time (11 a.m. Eastern Time).

The dial-in number for the call is 1-866-713-8310 in the United States, or +1-617-597-5308 outside the United States, passcode 27975225.  A live webcast of the call may be accessed on the investor information page of Regency Energy Partners’ 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 60456168. A replay of the webcast will also be available on the Partnership’s website for seven 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 (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 the Partnership’s interest in adjusted EBITDA from unconsolidated affiliates less income from unconsolidated affiliates.

Adjusted EBITDA is used as a supplemental performance measure by our management and by external users of our financial statements such as investors, commercial 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.

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 define segment margin for the Gathering and Processing and the Corporate and Others segments, as revenues generated from operations minus 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 percentages of the net income in the Haynesville Joint Venture, MEP Joint Venture and the Lone Star Joint Venture 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, fractionation and storage of natural gas and 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:

Elizabeth Cornelius

HCK2 Partners

972-716-0500 x26

elizabeth.cornelius@hck2.com

Consolidated Income Statement

Regency Energy Partners LP
Consolidated Income Statements
Unaudited
($ in thousands)
	Three Months Ended September 30,
	2011			2010
REVENUES
Gas sales, including related party amounts of $3,840 and $1,680	$	118,754		$	132,130
NGL sales, including related party amounts of $103,892 and $51,062		174,537			91,489
Gathering, transportation and other fees, including related party amounts of $6,141 and $5,680		91,596			72,184
Net realized and unrealized loss from derivatives		(5,380	)		(6,218	)
Other, including related party amounts of $2,665 and $1,111		10,760			7,303
Total revenues		390,267			296,888
OPERATING COSTS AND EXPENSES
Cost of sales, including related party amounts of $5,049 and $4,768		279,526			213,032
Operation and maintenance		37,950			34,306
General and administrative, including related party amounts of $4,225 and $2,500		17,350			18,072
(Gain) loss on asset sales, net		(131	)		200
Depreciation and amortization		41,956			32,205
Total operating costs and expenses		376,651			297,815
OPERATING INCOME (LOSS)		13,616			(927	)
Income from unconsolidated affiliates		30,946			21,754
Interest expense, net		(28,852	)		(20,379	)
Other income and deductions, net		15,050			7,524
INCOME BEFORE INCOME TAXES		30,760			7,972
Income tax (benefit) expense		(89	)		450
INCOME FROM CONTINUING OPERATIONS		30,849			7,522
DISCONTINUED OPERATIONS
Net income from operations of east Texas assets, including gain on disposal of $20 in 2010		-			324
NET INCOME	$	30,849		$	7,846
Net income attributable to noncontrolling interest		(549	)		(58	)
NET INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP	$	30,300		$	7,788

Segment Financial and Operating Data

	Three Months Ended September 30,
	2011		2010
	($ in thousands)
Gathering and Processing Segment
Financial data:
Segment margin	$	64,716	$	42,723
Adjusted segment margin		64,890		56,690
Operating data:
Throughput (MMbtu/d)		1,292,766		950,583
NGL gross production (Bbls/d)		34,847		26,930

	Three Months Ended September 30,
	2011			2010
	($ in thousands)
Contract Compression Segment
Financial data:
Segment margin - Gross	$	37,957		$	38,509
Less: Inter-segment elimination		(3,341	)		(5,869	)
Segment margin, net of inter-segment elimination		34,616			32,640
Operating data:
Revenue generating horsepower		769,000			754,000

	Three Months Ended September 30,
	2011		2010 (1)
	($ in thousands)
Contract Treating Segment
Financial data:
Segment margin	$	6,642	$	2,730
Operating data:
Revenue generating GPM		3,468		3,093
(1) The Partnership acquired Contract Treating segment in September 2010.

	Three Months Ended September 30,
	2011		2010
	($ in thousands)
Corporate & Others
Financial data:
Segment margin	$	4,767	$	5,763

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 September 30,
	2011		2010
	($ in thousands)
Haynesville Joint Venture
Financial data:
Segment margin	$	43,583	$	49,121
Operating data:
Throughput (MMbtu/d)		1,192,203		1,519,716

	Three Months Ended September 30,
	2011		2010
	($ in thousands)
MEP Joint Venture
Financial data:
Segment margin	$	61,925	$	56,197
Operating data:
Throughput (MMbtu/d)		1,320,480		1,365,674

	Three Months Ended September 30,
	2011
	($ in thousands)
Lone Star Joint Venture
Financial data:
Segment margin	$	65,372
Operating data:
West Texas Pipeline- Throughput (Bbls/d)		133,149
NGL Fractionation Throughput (Bbls/d)		13,833
Note: The Partnership acquired 30% interest in the Lone Star Joint Venture in May 2011.

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 September 30,
	2011			2010
Haynesville Joint Venture	($ in thousands)
Net income	$	24,282		$	30,366
Add (Deduct):
Operation and maintenance		5,509			5,259
General and administrative		4,348			4,347
Loss on asset sales, net		-			106
Depreciation and amortization		9,100			8,902
Interest expense, net		395			154
Other income and deductions, net		(51	)		(13	)
Total Segment Margin	$	43,583		$	49,121
Note: Calculation represents 100% of Haynesville Joint Venture's Segment Margin.

	Three Months Ended September 30,
	2011		2010
MEP Joint Venture	($ in thousands)
Net income	$	21,998	$	16,351
Add:
Operation and maintenance		6,691		8,894
General and administrative		2,981		884
Depreciation and amortization		17,401		17,319
Interest expense, net		12,849		12,749
Other income and deductions, net		5		-
Total Segment Margin	$	61,925	$	56,197
Note: Calculation represents 100% of MEP Joint Venture's Segment Margin.

	Three Months Ended September 30,
	2011
Lone Star Joint Venture	($ in thousands)
Net income	$	30,952
Add:
Operation and maintenance		16,575
General and administrative		4,958
Depreciation and amortization		12,904
Tax expense		11
Other income and deductions, net		(28	)
Total Segment Margin	$	65,372
Note: Calculation represents 100% of Lone Star Joint Venture's Segment Margin. The Partnership acquired 30% interest in the joint venture in May 2011.

Reconciliation of Non-GAAP Measures to GAAP Measures

	Three Months Ended September 30,
	2011			2010
	($ in thousands)
Net income	$	30,849		$	7,846
Add (deduct):
Interest expense, net		28,852			20,393
Depreciation and amortization		41,956			32,429
Income tax (benefit) expense		(89	)		450
EBITDA (1)	$	101,568		$	61,118
Add (deduct):
Non-cash (gain) loss from commodity and embedded derivatives		(15,056	)		6,646
Non-cash unit-based compensation		891			303
(Gain) loss on asset sales, net		(131	)		200
Income from unconsolidated affiliates		(30,946	)		(21,754	)
Partnership's interest in Haynesville Joint Venture's adjusted EBITDA (2)		16,885			19,632
Partnership's interest in MEP Joint Venture's adjusted EBITDA (3)		26,091			23,163
Partnership's interest in Lone Star Joint Venture's adjusted EBITDA (4)		13,152			-
Other (income) expense, net		(178	)		346
Adjusted EBITDA	$	112,276		$	89,654
(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	$	24,282		$	30,366
Add:
Depreciation and amortization		9,100			8,902
Interest expense, net		395			154
Other expense (income), net		5			(149	)
Haynesville Joint Venture's Adjusted EBITDA	$	33,782		$	39,273
(3) 100% of MEP Joint Venture's Adjusted EBITDA is calculated as follows:
Net income MEP Joint Venture	$	21,998		$	16,351
Add:
Depreciation and amortization		17,401			17,319
Interest expense, net		12,855			12,749
MEP Joint Venture's Adjusted EBITDA	$	52,254		$	46,419
(4) 100% of Lone Star Joint Venture's Adjusted EBITDA is calculated as follows:
Net income Lone Star Joint Venture	$	30,952		$	-
Add:
Depreciation and amortization		12,904			-
Other expenses, net		(16	)		-
Lone Star Joint Venture's Adjusted EBITDA	$	43,840		$	-

Non-GAAP Adjusted Total Segment Margin to GAAP Net Income

	Three Months Ended
	September 30, 2011			September 30, 2010
	($ in thousands)
Net income	$	30,849		$	7,846
Add (Deduct):
Operation and maintenance		37,950			34,306
General and administrative		17,350			18,072
(Gain) loss on asset sales, net		(131	)		200
Depreciation and amortization		41,956			32,205
Income from unconsolidated affiliates		(30,946	)		(21,754	)
Interest expense, net		28,852			20,379
Other income and deductions, net		(15,050	)		(7,524	)
Income tax (benefit) expense		(89	)		450
Discontinued operations		-			(324	)
Total Segment Margin		110,741			83,856
Non-cash loss from commodity derivatives		174			13,967
Adjusted Total Segment Margin	$	110,915		$	97,823
Gathering and Processing Segment Margin	$	64,716		$	42,723
Non-cash loss from commodity derivatives		174			13,967
Adjusted Gathering and Processing Segment Margin		64,890			56,690
Contract Compression Segment Margin		37,957			38,509
Contract Treating Segment Margin		6,642			2,730
Corporate and Others Segment Margin		4,767			5,763
Inter-segment Elimination		(3,341	)		(5,869	)
Adjusted Total Segment Margin	$	110,915		$	97,823

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

	Three Months Ended
	September 30, 2011
	($ in thousands)
Net cash flows provided by operating activities	$	83,302
Add (deduct):
Depreciation and amortization, including debt issuance cost amortization and bond premium amortization		(43,492	)
Amortization of excess fair value of unconsolidated affiliates		(1,462	)
Income from unconsolidated affiliates		32,408
Derivative valuation change		15,834
Gain on asset sales, net		131
Unit-based compensation expenses		(697	)
Trade accounts receivables, accrued revenues, and related party receivables		4,451
Other current assets		778
Trade accounts payable, accrued cost of gas and liquids, related party payables and deferred revenues		8,110
Other current liabilities		(27,597	)
Distributions received from unconsolidated affiliates		(40,796	)
Other assets and liabilities		(121	)
Net income	$	30,849
Add (deduct):
Interest expense, net		28,852
Depreciation and amortization		41,956
Income tax benefit		(89	)
EBITDA	$	101,568
Add (deduct):
Non-cash gain from commodity and embedded derivatives		(15,056	)
Non-cash unit-based compensation		891
Gain on asset sales, net		(131	)
Income from unconsolidated affiliates		(30,946	)
Partnership's interest in Haynesville Joint Venture's adjusted EBITDA		16,885
Partnership's interest in MEP Joint Venture's adjusted EBITDA		26,091
Partnership's interest in Lone Star Joint Venture's adjusted EBITDA		13,152
Other expense, net		(178	)
Adjusted EBITDA	$	112,276
Add (deduct):
Interest expense, excluding capitalized interest		(35,092	)
Maintenance capital expenditures		(7,002	)
Proceeds from asset disposal		6,258
Distributions to Series A Preferred Units		(1,945	)
Other adjustments, net		(1,249	)
Cash available for distribution	$	73,246

EX-99.2

Exhibit 99.2