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 8, 2012 (November 7, 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 November 7, 2012, Regency Energy Partners LP (the “Partnership”) issued a press release announcing its financial and operating results for the third quarter ended September 30, 2012. 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 8, 2012, the management of the Partnership expects to present information concerning its business to investors and other interested parties in a webcast conference call. 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 7, 2012 announcing the results of its operations for the third quarter ended September 30, 2012.
Exhibit 99.2	Regency Energy Partners LP presentation to investors dated November 8, 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

November 8, 2012

EX-99.1

Exhibit 99.1

Regency Energy Partners Reports Third Quarter 2012 Earnings Results

DALLAS, November 7, 2012 – Regency Energy Partners LP (NYSE: RGP), (“Regency” or the “Partnership”), announced today its financial results for the third quarter ended September 30, 2012.

Adjusted EBITDA increased to $114 million in the third quarter of 2012, compared to $112 million in the third quarter of 2011. The increase in adjusted EBITDA was primarily due to an increase in adjusted total segment margin primarily related to volume growth in the gathering and processing segment, partially offset by higher operations and maintenance expenses.

In the third quarter of 2012, Regency generated $68 million in cash available for distribution, compared to $73 million in the third quarter of 2011. This decrease was primarily due to higher maintenance capital expenditures in the third quarter of 2012 compared to the prior period. Regency had a net loss of $2 million for the three months ended September 30, 2012, compared to the net income of $30 million for the three months ended September 30, 2011, primarily due to non-cash valuation adjustments recorded in each respective period.

“Volumes continued to increase in the third quarter, primarily in south and west Texas, as well as in north Louisiana,” said Mike Bradley, president and chief executive officer of Regency. “Results were impacted by temporary operational issues and unplanned outages in our gathering and processing segment and in our Lone Star Joint Venture; however we did see an uptick in our contract services business which has begun to benefit from growth in wet-gas regions.”

“Looking ahead, we remain excited about our portfolio of organic growth projects. We believe the impact of these projects coming online will provide Regency with additional earnings and volume growth throughout 2013,” said Bradley.

REVIEW OF SEGMENT PERFORMANCE

Adjusted total segment margin increased to $116 million for the third quarter of 2012, compared to $111 million for the third quarter of 2011.

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 now includes the Partnership's investment in the Ranch Joint Venture, which processes natural gas delivered from the NGLs-rich Bone Spring and Avalon shale formations in west Texas. In June 2012, the Ranch Joint Venture’s refrigeration processing plant became operational.

Adjusted segment margin for the Gathering and Processing segment, which excludes non-cash gains and losses from commodity derivatives, was $68 million for the third quarter of 2012, compared to $65 million for the third quarter of 2011. The increase was primarily due to volume growth in south and west Texas, and north Louisiana, which was partially offset by temporary operational issues and plant downtime.

Total throughput volumes for the Gathering and Processing segment increased to 1.5 million MMbtu per day of natural gas for the third quarter of 2012, compared to 1.3 million MMbtu per day of natural gas for the third quarter of 2011. Processed NGLs increased to 36,000 barrels per day for the third quarter of 2012, compared to 35,000 barrels per day for the third quarter of 2011.

Joint Ventures – The Joint Ventures 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.

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 $2 million for the third quarter of 2012, compared to $11 million for the third quarter of 2011. This decrease is primarily due to a non-cash asset impairment charge related to surplus equipment of $7 million. Total throughput volumes for the Haynesville Joint Venture averaged 0.8 million MMbtu per day of natural gas for the third quarter of 2012, compared to 1.2 million MMbtu per day for the third quarter of 2011.

The MEP Joint Venture consists solely of the Midcontinent Express Pipeline (“MEP”) and is operated by Kinder Morgan Energy Partners, L.P. Income from unconsolidated affiliates for the MEP Joint Venture was $10 million for the third quarter of 2012 and $11 million for 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 2012 and 1.3 million MMbtu per day 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 2012, income from unconsolidated affiliates for the Lone Star Joint Venture was $9 million, compared to $9 million for the third quarter of 2011. Results for the third quarter of 2012 were impacted by temporary downtime in the refinery services segment due to Hurricane Isaac. For the third quarter of 2012, total throughput volumes for the West Texas Pipeline averaged 132,000 barrels per day, compared to 133,000 barrels per day for the third quarter of 2011 and NGL Fractionation throughput volumes averaged 11,000 barrels per day in the third quarter of 2012, compared to 14,000 barrels per day in the third quarter of 2011.

Contract Compression – The Contract Compression segment provides turn-key natural gas compression services for customer-specific systems. Segment margin for the Contract Compression segment, including both revenues from external customers as well as intersegment revenues, was $39 million for the third quarter of 2012, compared to $38 million for the third quarter of 2011. The increase in segment margin is primarily due to the increase in revenue generating horsepower, inclusive of intersegment revenue generating horsepower. As of September 30, 2012, the Contract Compression segment’s revenue generating horsepower, including intersegment revenue generating horsepower, increased to 873,000, compared to 836,000 as of September 30, 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 external customers.

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 $8 million for the third quarter of 2012, compared to $7 million for the third quarter of 2011. As of September 30, 2012, revenue generating gallons per minute was 3,910, compared to 3,468 as of September 30, 2011.

Corporate and Others – The Corporate and Others segment comprises a small regulated pipeline and the Partnership’s corporate offices. Segment margin in the Corporate and Others segment was $5 million for both the third quarter of 2012 and the third quarter of 2011.

ORGANIC GROWTH

In the nine months ended September 30, 2012, Regency incurred $557 million of growth capital expenditures: $251 million for the Joint Ventures segment, $194 million for the Gathering and Processing segment, $81 million for the Contract Compression segment and $31 million for the Contract Treating segment.

In the nine months ended September 30, 2012, Regency incurred $26 million of maintenance capital expenditures.

In 2012, Regency expects to invest $820 million in growth capital expenditures, of which $380 million is related to the Lone Star Joint Venture; $300 million is related to the Gathering and Processing segment, which includes expenditures related to the Ranch Joint Venture; $100 million related to the Contract Compression segment; and $40 million related to the Contract Treating segment.

In addition, Regency expects to make $32 million in maintenance capital expenditures in 2012, including its proportionate share related to joint ventures.

In 2013, Regency expects to invest approximately $400 million in growth capital expenditures, of which $185 million is related to the Gathering and Processing segment; $120 million related to the Lone Star Joint Venture; $80 million related to the Contract Compression segment; and $15 million related to the Contract Treating segment.

In addition, Regency expects to invest $35 million in maintenance capital expenditures in 2013, including its proportionate share related to joint ventures.

CASH DISTRIBUTIONS

On October 25, 2012, Regency announced a cash distribution of $0.46 per outstanding common unit for the third quarter ended September 30, 2012. This distribution is equivalent to $1.84 per outstanding common unit on an annual basis and will be paid on November 14, 2012, to unitholders of record at the close of business on November 6, 2012.

Based on the terms of the partnership agreement, the Series A Preferred Units will be paid a quarterly distribution of $0.445 per unit for the third quarter ended September 30, 2012, on the same schedule as set forth above.

In the third quarter of 2012, Regency generated $68 million in cash available for distribution, representing 0.83 times the amount required to cover its announced distribution to unitholders. Year-to-date 2012, Regency generated $242 million in cash available for distribution, representing 0.99 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, timing of organic growth projects 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 2012 results Thursday, November 8, 2012 at 10 a.m. Central Time (11 a.m. Eastern Time).

The dial-in number for the call is 1-866-730-5766 in the United States, or +1-857-350-1590 outside the United States, passcode 64826534. 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 40673746. 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. Reconciliations of these non-GAAP financial measures to our GAAP financial statements are included in the Appendix.

We define EBITDA as net income (loss) plus interest expense, net, income tax expense 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 expenses;

·   loss (gain) on asset sales, net;

·   loss on debt refinancing, net;

·   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.

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;

·   minus distributions to Series A Preferred Units,

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

·   other adjustments.

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 segment margin and 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 in accordance with the equity method of accounting.

We calculate our Contract Compression segment margin as our revenues generated from our contract compression operations minus direct costs, primarily compressor unit repairs, associated with those revenues.

We calculate our Contract Treating segment margin as revenues generated from our contract treating operations minus direct costs associated with those revenues.

We calculate total segment margin as the total 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, 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 because they represent the results of product purchases and sales, a key component of our operations.

FORWARD-LOOKING INFORMATION AND OTHER DISCLAIMERS

This release includes “forward-looking” statements. Forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may” or similar expressions help identify forward-looking statements. Although we believe our forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, we cannot give any assurance that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. Additional risks include: volatility in the price of oil, natural gas, and natural gas liquids, declines in the credit markets and the availability of credit for the Partnership as well as for producers connected to the Partnership’s system and its customers, the level of creditworthiness of, and performance by the Partnership’s counterparties and customers, the Partnership's ability to access capital to fund organic growth projects and acquisitions, and the Partnership’s ability to obtain debt and equity financing on satisfactory terms, the Partnership's use of derivative financial instruments to hedge commodity and interest rate risks, the amount of collateral required to be posted from time-to-time in the Partnership's transactions, changes in commodity prices, interest rates, and demand for the Partnership's services, changes in laws and regulations impacting the midstream sector of the natural gas industry, weather and other natural phenomena, industry changes including the impact of consolidations and changes in competition, the Partnership's ability to obtain required approvals for construction or modernization of the Partnership's facilities and the timing of production from such facilities, and the effect of accounting pronouncements issued periodically by accounting standard setting boards. Therefore, actual results and outcomes may differ materially from those expressed in such forward-looking statements.

These and other risks and uncertainties are discussed in more detail in filings made by the Partnership with the Securities and Exchange Commission, which are available to the public. The Partnership undertakes 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, master limited partnership engaged in the gathering and processing, contract compression, contract treating and transportation of natural gas and the transportation, fractionation and storage of natural gas liquids. Regency's general partner is owned by Energy Transfer Equity, L.P. (NYSE: ETE). For more information, please visit Regency’s 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

Regency Energy Partners LP
Condensed Consolidated Statements of Operations
($ in thousands)
(unaudited)
	September 30, 2012		December 31, 2011
Assets
Current assets	$	209,684	$	187,124
Property, plant and equipment, net		2,059,196		1,885,528
Investment in unconsolidated affiliates		2,156,135		1,924,705
Long-term derivative assets		918		474
Other assets, net		33,486		39,353
Intangible assets, net		718,928		740,883
Goodwill		789,789		789,789
Total Assets	$	5,968,136	$	5,567,856
Liabilities and Partners' Capital and Noncontrolling Interest
Current liabilities	$	214,107	$	233,306
Long-term derivative liabilities		29,490		39,112
Other long-term liabilities		5,550		6,071
Long-term debt		1,960,429		1,687,147
Series A Preferred Units		72,549		71,144
Partners' capital		3,627,879		3,498,207
Noncontrolling interest		58,132		32,869
Total Partners' Capital and Noncontrolling Interest		3,686,011		3,531,076
Total Liabilities and Partners' Capital and Noncontrolling Interest	$	5,968,136	$	5,567,856

Regency Energy Partners LP
Condensed Consolidated Statements of Operations
($ in thousands)
(unaudited)
	Three Months Ended September 30,
	2012			2011
REVENUES	$	313,882		$	390,267
OPERATING COSTS AND EXPENSES
Cost of sales, including related party amounts		206,881			279,526
Operation and maintenance		41,275			37,950
General and administrative, including related party amounts		14,935			17,350
Gain on asset sales, net		(42	)		(131	)
Depreciation and amortization		45,881			41,956
Total operating costs and expenses		308,930			376,651
OPERATING INCOME		4,952			13,616
Income from unconsolidated affiliates		21,055			30,946
Interest expense, net		(28,567	)		(28,852	)
Other income and deductions, net		1,106			15,050
(LOSS) INCOME BEFORE INCOME TAXES		(1,454	)		30,760
Income tax expense (benefit)		-			(89	)
NET (LOSS) INCOME	$	(1,454	)	$	30,849
Net income attributable to noncontrolling interest		(379	)		(549	)
NET (LOSS) INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP	$	(1,833	)	$	30,300
Limited partners' interest in net (loss) income	$	(5,977	)	$	26,243
Weighted average number of common units outstanding		170,264,621			145,842,735
Basic (loss) income per common unit	$	(0.04	)	$	0.18
Diluted (loss) income per common unit	$	(0.04	)	$	0.09

Segment Financial and Operating Data

	Three Months Ended September 30,
	2012		2011
	($ in thousands)
Gathering and Processing Segment
Financial data:
Segment margin	$	59,392	$	64,716
Adjusted segment margin		68,269		64,890
Operating data:
Throughput (MMbtu/d)		1,461,122		1,292,766
NGL gross production (Bbls/d)		36,338		34,847

	Three Months Ended September 30,
	2012		2011
	($ in thousands)
Contract Compression Segment
Financial data:
Segment margin	$	39,380	$	37,957
Operating data:
Revenue generating horsepower, including intercompany revenue generating horsepower		872,776		836,094

	Three Months Ended September 30,
	2012		2011
	($ in thousands)
Contract Treating Segment
Financial data:
Segment margin	$	8,115	$	6,642
Operating data:
Revenue generating gallons per minute		3,910		3,468

	Three Months Ended September 30,
	2012		2011
	($ in thousands)
Corporate & Others
Financial data:
Segment margin	$	5,459	$	4,767

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,
	2012		2011
	($ in thousands)
Haynesville Joint Venture
Financial data:
Segment margin	$	42,187	$	43,583
Operating data:
Throughput (MMbtu/d)		826,974		1,192,203

	Three Months Ended September 30,
	2012		2011
	($ in thousands)
MEP Joint Venture
Financial data:
Segment margin	$	61,126	$	61,925
Operating data:
Throughput (MMbtu/d)		1,391,605		1,320,480

	Three Months Ended September 30,
	2012		2011
	($ in thousands)
Lone Star Joint Venture
Financial data:
Segment margin	$	63,709	$	65,372
Operating data:
West Texas Pipeline Throughput (Bbls/d)		132,297		133,149
NGL Fractionation Throughput (Bbls/d)		11,073		13,833

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,
	2012		2011
Haynesville Joint Venture	($ in thousands)
Net income	$	6,520	$	24,282
Add:
Operation and maintenance		5,482		5,509
General and administrative		5,177		4,348
Depreciation and amortization		9,152		9,100
Interest expense, net		457		395
Impairment of property, plant and equipment		14,114		-
Other income and deductions, net		1,285		(51	)
Total Segment Margin	$	42,187	$	43,583

	Three Months Ended September 30,
	2012			2011
MEP Joint Venture	($ in thousands)
Net income	$	20,735		$	21,998
Add:
Operating expenses		10,225			9,672
Depreciation and amortization		17,354			17,401
Interest expense, net		12,816			12,849
Other income and deductions, net		(4	)		5
Total Segment Margin	$	61,126		$	61,925

	Three Months Ended September 30,
	2012			2011
Lone Star Joint Venture	($ in thousands)
Net income	$	30,611		$	30,952
Add:
Operation and maintenance		14,788			16,575
General and administrative		4,960			4,958
Depreciation and amortization		12,833			12,904
Tax expense		641			11
Other income and deductions, net		(124	)		(28	)
Total Segment Margin	$	63,709		$	65,372

Reconciliation of Non-GAAP Measures to GAAP Measures

	Three Months Ended September 30,
	2012			2011
	($ in thousands)
Net (loss) income	$	(1,454	)	$	30,849
Add (deduct):
Interest expense, net		28,567			28,852
Depreciation and amortization		45,881			41,956
Income tax benefit		-			(89	)
EBITDA (1)	$	72,994		$	101,568
Add (deduct):
Non-cash loss (gain) from commodity and embedded derivatives		7,327			(15,056	)
Unit-based compensation expenses		1,176			891
Loss on asset sales, net		(42	)		(131	)
Income from unconsolidated affiliates		(21,055	)		(30,946	)
Partnership's interest in unconsolidated affiliates' adjusted EBITDA (2)(3)(4)(5)		54,201			56,128
Other income, net		(379	)		(178	)
Adjusted EBITDA	$	114,222		$	112,276
(1) Earnings before interest, taxes, depreciation and amortization.
(2) 100% of Haynesville Joint Venture's Adjusted EBITDA and the Partnership's interest are calculated as follows:
Net income Haynesville Joint Venture	$	6,520		$	24,282
Add (deduct):
Depreciation and amortization		9,152			9,100
Interest expense, net		457			395
Impairment of property, plant and equipment		14,114			-
Other expense, net		1,285			5
Haynesville Joint Venture's Adjusted EBITDA	$	31,528		$	33,782
Ownership interest		49.99	%		49.99	%
Partnership's interest in Haynesville Joint Venture's Adjusted EBITDA	$	15,761		$	16,885
(3) 100% of MEP Joint Venture's Adjusted EBITDA and the Partnership's interest are calculated as follows:
Net income MEP Joint Venture	$	20,735		$	21,998
Add:
Depreciation and amortization		17,354			17,401
Interest expense, net		12,816			12,855
Other income		(4	)		-
MEP Joint Venture's Adjusted EBITDA	$	50,901		$	52,254
Ownership interest		50	%		49.90	%
Partnership's interest in MEP Joint Venture's Adjusted EBITDA	$	25,450		$	26,091
(4) 100% of Lone Star Joint Venture's Adjusted EBITDA and the Partnership's interest are  calculated as follows:
Net income Lone Star Joint Venture	$	30,611		$	30,952
Add (deduct):
Depreciation and amortization		12,832			12,904
Other expenses, net		36			(16	)
Lone Star Joint Venture's Adjusted EBITDA	$	43,479		$	43,840
Ownership interest		30	%		30	%
Partnership's interest in Lone Star Joint Venture's Adjusted EBITDA	$	13,045		$	13,152
(5) 100% of Ranch Joint Venture's Adjusted EBITDA and the Partnership's interest are  calculated as follows:
Net loss Ranch Star Joint Venture	$	(880	)		N/A
Add (deduct):
Depreciation and amortization		713			N/A
Ranch Joint Venture's Adjusted EBITDA	$	(167	)		N/A
Ownership interest		33	%		N/A
Partnership's interest in Ranch Joint Venture's Adjusted EBITDA	$	(55	)		N/A
We acquired a 33.33% interest in the Ranch Joint Venture in December 2011.

Reconciliation of Non-GAAP Measures to GAAP Measures

	Nine Months Ended September 30,
	2012			2011
	($ in thousands)
Net income	$	56,773		$	59,991
Add (deduct):
Interest expense, net		86,058			73,548
Depreciation and amortization		142,519			122,695
Income tax expense (benefit)		89			(19	)
EBITDA (1)	$	285,439		$	256,215
Add (deduct):
Non-cash gain from commodity and embedded derivatives		(16,650	)		(20,149	)
Unit-based compensation expenses		3,470			2,687
Loss on asset sales, net		1,542			50
Loss on debt refinancing, net		7,820			-
Income from unconsolidated affiliates		(87,198	)		(86,921	)
Partnership's interest in unconsolidated affiliates' adjusted EBITDA (2)(3)(4)(5)		170,582			156,000
Other income, net		(1,462	)		(413	)
Adjusted EBITDA	$	363,543		$	307,469
(1) Earnings before interest, taxes, depreciation and amortization.
(2) 100% of Haynesville Joint Venture's Adjusted EBITDA and the Partnership's interest are calculated as follows:
Net income Haynesville Joint Venture	$	55,364		$	84,703
Add (deduct):
Depreciation and amortization		27,354			25,846
Interest expense, net		1,397			782
Impairment of property, plant and equipment		14,114			-
Other expense, net		1,285			16
Haynesville Joint Venture's Adjusted EBITDA	$	99,514		$	111,347
Ownership interest		49.99	%		49.99	%
Partnership's interest in Haynesville Joint Venture's Adjusted EBITDA	$	49,747			55,660
(3) 100% of MEP Joint Venture's Adjusted EBITDA and the Partnership's interest are calculated as follows:
Net income MEP Joint Venture	$	62,606		$	62,684
Add:
Depreciation and amortization		52,075			52,176
Interest expense, net		38,609			38,623
Other income		(4	)		-
MEP Joint Venture's Adjusted EBITDA	$	153,286		$	153,483
Ownership interest		50	%		49.90	%
Partnership's interest in MEP Joint Venture's Adjusted EBITDA	$	76,643			76,604
(4) 100% of Lone Star Joint Venture's Adjusted EBITDA and the Partnership's interest are  calculated as follows:
Net income Lone Star Joint Venture	$	109,712		$	58,910
Add (deduct):
Depreciation and amortization		37,737			20,043
Other expenses, net		36			169
Lone Star Joint Venture's Adjusted EBITDA	$	147,485		$	79,122
Ownership interest		30	%		30	%
Partnership's interest in Lone Star Joint Venture's Adjusted EBITDA	$	44,246			23,736
We acquired a 30% interest in the Lone Star Joint Venture in May 2011.
(5) 100% of Ranch Joint Venture's Adjusted EBITDA and the Partnership's interest are  calculated as follows:
Net loss Ranch Joint Venture	$	(931	)	$	-
Add (deduct):
Depreciation and amortization		768			-
Ranch Joint Venture's Adjusted EBITDA	$	(163	)	$	-
Ownership interest		33	%		0	%
Partnership's interest in Ranch Joint Venture's Adjusted EBITDA	$	(54	)	$	-
We acquired a 33.33% interest in the Ranch Joint Venture in December 2011.

Non-GAAP Adjusted Total Segment Margin to GAAP Net Income

	Three Months Ended September 30,
	2012			2011
	($ in thousands)
Net income	$	(1,454	)	$	30,849
Add (deduct):
Operation and maintenance		41,275			37,950
General and administrative		14,935			17,350
Loss on asset sales, net		(42	)		(131	)
Depreciation and amortization		45,881			41,956
Income from unconsolidated affiliates		(21,055	)		(30,946	)
Interest expense, net		28,567			28,852
Other income and deductions, net		(1,106	)		(15,050	)
Income tax expense (benefit)		-			(89	)
Total Segment Margin		107,001			110,741
Non-cash loss from commodity derivatives		8,877			174
Adjusted Total Segment Margin	$	115,878		$	110,915
Gathering & Processing Segment Margin	$	59,392		$	64,716
Non-cash loss from commodity derivatives		8,877			174
Adjusted Gathering and Processing Segment Margin		68,269			64,890
Contract Compression Segment Margin		39,380			37,957
Contract Treating Segment Margin		8,115			6,642
Corporate & Others Segment Margin		5,459			4,767
Inter-segment Eliminations		(5,345	)		(3,341	)
Adjusted Total Segment Margin	$	115,878		$	110,915

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

	Three Months Ended September 30,
	2012			2011
	($ in thousands)
Net cash flows provided by operating activities	$	78,729		$	83,302
Add (deduct):
Depreciation and amortization, including debt issuance cost, bond premium and excess fair value of unconsolidated affiliates amortization		(47,554	)		(43,492	)
Income from unconsolidated affiliates		21,055			30,946
Derivative valuation change		(7,326	)		15,834
(Loss) gain on asset sales, net		42			131
Unit-based compensation expenses		(1,176	)		(697	)
Cash flow changes in current assets and liabilities:
Trade accounts receivables, accrued revenues, and related party receivables		10,273			4,451
Other current assets		1,608			778
Trade accounts payable, accrued cost of gas and liquids, related party payables and deferred revenues		(20,228	)		8,110
Other current liabilities		(8,135	)		(27,597	)
Distributions received from unconsolidated affiliates		(28,797	)		(40,796	)
Other assets and liabilities		55			(121	)
Net (Loss) Income	$	(1,454	)	$	30,849
Add:
Interest expense, net		28,567			28,852
Depreciation and amortization		45,881			41,956
Income tax benefit		-			(89	)
EBITDA	$	72,994		$	101,568
Add (deduct):
Non-cash gain (loss) from commodity and embedded derivatives		7,327			(15,056	)
Unit-based compensation expenses		1,176			891
Loss on asset sales, net		(42	)		(131	)
Income from unconsolidated affiliates		(21,055	)		(30,946	)
Partnership's interest in unconsolidated affiliates' adjusted EBITDA		54,201			56,128
Other income, net		(379	)		(178	)
Adjusted EBITDA	$	114,222		$	112,276
Add (deduct):
Interest expense, excluding capitalized interest		(33,962	)		(35,092	)
Maintenance capital expenditures		(11,170	)		(7,002	)
Proceeds from asset sales		2,118			6,258
Distribution to Series A Preferred Units		(1,946	)		(1,945	)
Other adjustments		(1,578	)		(1,249	)
Cash available for distribution	$	67,684		$	73,246

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

	Nine Months Ended September 30,
	2012			2011
	($ in thousands)
Net cash flows provided by operating activities	$	180,925		$	204,416
Add (deduct):
Depreciation and amortization, including debt issuance cost and bond premium		(146,913	)		(127,079	)
Income from unconsolidated affiliates		87,198			86,921
Derivative valuation change		17,124			21,660
Loss on asset sales, net		(1,542	)		(50	)
Unit-based compensation expenses		(3,470	)		(2,444	)
Cash flow changes in current assets and liabilities:
Trade accounts receivables, accrued revenues, and related party receivables		(10,779	)		13,298
Other current assets		1,429			(186	)
Trade accounts payable, accrued cost of gas and liquids, related party payables and deferred revenues		31,675			(20,467	)
Other current liabilities		(7,159	)		(24,833	)
Distributions received from unconsolidated affiliates		(91,893	)		(91,306	)
Other assets and liabilities		178			61
Net Income	$	56,773		$	59,991
Add:
Interest expense, net		86,058			73,548
Depreciation and amortization		142,519			122,695
Income tax expense (benefit)		89			(19	)
EBITDA	$	285,439		$	256,215
Add (deduct):
Non-cash gain from commodity and embedded derivatives		(16,650	)		(20,149	)
Unit-based compensation expenses		3,470			2,687
Loss on asset sales, net		1,542			50
Loss on debt refinancing, net		7,820			-
Income from unconsolidated affiliates		(87,198	)		(86,921	)
Partnership's interest in unconsolidated affiliates' adjusted EBITDA		170,582			156,000
Other income, net		(1,462	)		(413	)
Adjusted EBITDA	$	363,543		$	307,469
Add (deduct):
Interest expense, excluding capitalized interest		(110,165	)		(91,367	)
Maintenance capital expenditures		(25,625	)		(13,776	)
Proceeds from asset sales		22,528			10,242
Distribution to Series A Preferred Units		(5,836	)		(5,835	)
Other adjustments		(2,810	)		(3,961	)
Cash available for distribution	$	241,635		$	202,772

EX-99.2

Exhibit 99.2