 Exhibit 99.2 Regency Energy Partners Fourth Quarter Earnings Release February 17, 2011 |
 Forward-Looking Statements 2 Certain matters discussed in this report include “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 assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. These risks and uncertainties 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 information. In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than the Partnership has described. 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. |
 3 2010 Highlights ?Key Highlights Partnership Energy Transfer Equity acquired 100% of Regency’s general partner Introduced new senior leadership team with extensive experience in the midstream industry Acquisitions Acquired 49.9% interest in MEP Joint Venture Completed $193-million 1 Zephyr acquisition Acquired additional 6.99% interest in Haynesville Joint Venture Operational Completed construction of the Haynesville and Red River Expansion projects on time and under budget Completed sale of east Texas assets Added 485 MMcf/d of incremental gathering capacity in north Louisiana Announced expansions to our south Texas gathering system Financial Raised approximately $408 million of equity² Completed a $600 million debt refinancing and extended maturity date of revolving credit facility Maintained quarterly distribution of 44.5 cents per common unit per quarter Achieved $327 million of adjusted EBITDA for full-year 2010 1 Final price paid, as reported in Regency’s Form 10-Q dated September 30, 2010 2 Net of underwriting discounts and commissions, inclusive of general partner’s proportionate capital contribution |
 Fundamentals Review |
 Total U.S. land rig count increased 4% from Q3 2010 to Q4 2010 Largest increases occurred in the liquids-rich south Texas and Texas Gulf areas Rich gas and crude plays with associated gas are seeing greatest levels of drilling activity 1 Tudor Pickering Holt & Company, TPH Weekly Rig Roundup, January 3, 2011, and Regency internal analysis 2 Includes injection, geothermal and unclassified rigs 5 Fundamentals: Drilling Activity Total US Land Rig Count Q4 09 Q1 10 Q2 10 Q3 10 Q4 10 1,188 1,419 1,624 1,786 1,858 Total Regency Operating Area Rig Count Q4 09 Q1 10 Q2 10 Q3 10 Q4 10 889 1,065 1,225 1,315 1,382 0 100 200 300 400 500 600 700 800 900 Q4 2009 Q1 2010 Q2 2010 Q3 2010 Q4 2010 U.S. Drilling Rig Trends¹ Gas Gas/Oil Oil 0 50 100 150 200 250 300 350 400 Q4 2009 Q1 2010 Q2 2010 Q3 2010 Q4 2010 Rig Count Trends - Regency Operated Area¹ Mid-Con West TX South Tx North LA / East TX Fayetteville TX Gulf Non-TX Gulf Barnett Shale Appalachian Other 2 |
 February NYMEX contract settled at $4.32 per MMbtu 1 , which represents an 18% decrease year-over-year WTI crude has broken out of its $70-$85/Bbl range and has reached the low $90s in recent weeks Forward curves for natural gas and crude oil pricing suggest that natural gas will trade at approximately $4.49/MMbtu and crude will trade at approximately $95/Bbl for full year 2011 ¹ Fundamentals: Commodity Prices 1 Forward curve pricing as of February 4, 2011 Gas Price Trends Crude/NGL Price Trends $2.00 $3.00 $4.00 $5.00 $6.00 Dec-09 Jan-10 Feb-10 Mar-10 Apr-10 May-10 Jun-10 Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10 Jan-11 NYMEX HSC Panhandle Waha $0.00 $20.00 $40.00 $60.00 $80.00 $100.00 Dec-09 Jan-10 Feb-10 Mar-10 Apr-10 May-10 Jun-10 Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10 Jan-11 Ethane Propane C4+ WTI |
 2011 Growth Strategy |
 8 2011 Growth Strategy |
 Business Review |
 10 2010 Performance Regency produced strong fourth-quarter and full-year 2010 financial results Comparing full-year 2010 to full-year 2009, adjusted EBITDA increased 55% year-over-year 1 Adjusted EBITDA varies from previously disclosed amounts as a result of the inclusion of non-cash unit based compensation as a reconciling item to adjusted EBITDA Pro Rata Adjusted EBITDA 1 $55 $53 $51 $53 $62 $74 $90 $102 $0 $20 $40 $60 $80 $100 $120 Q1 2009 Q2 2009 Q3 2009 Q4 2009 Q1 2010 Q2 2010 Q3 2010 Q4 2010 |
 Gathering and Processing Segment 11 1 Inter-segment volumes reflect volumes moved through both Regency’s Gathering and Processing and Transportation segments 2 Amounts differ from previously disclosed amounts due to the presentation as discontinued operations for the disposition of east Texas assets Margins continued to increase in the fourth quarter primarily due to increased Eagle Ford volumes in our south Texas region Gathering and Processing Throughput and Adjusted Segment Margin 1,2 1,012 959 $45 $47 $49 $51 $53 $55 $57 $59 $61 $63 $65 0 200 400 600 800 1,000 1,200 Q1 2009 Q2 2009 Q3 2009 Q4 2009 Q1 2010 Q2 2010 Q3 2010 Q4 2010 Throughput Intersegment Volumes Adjusted Segment Margin 933 1,001 1,002 1,005 951 1,030 |
 Transportation Segment 12 Regency’s share of Adjusted EBITDA increased to $123 million for full-year 2010 from $11 million for full-year 2009 1 Includes Regency’s proportionate share of adjusted EBITDA Transportation Segment Adjusted EBITDA 1 $1 $3 $4 $4 $25 - - - - $11 $43 $44 $0 $5 $10 $15 $20 $25 $30 $35 $40 $45 $50 Q1 2009 Q2 2009 Q3 2009 Q4 2009 Q1 2010 Q2 2010 Q3 2010 Q4 2010 $ in millions Haynesville JV MEP JV |
 Contract Compression & Contract Treating Segments 13 Revenue Generating Horsepower Despite challenging market conditions, Regency’s revenue generating horsepower has increased for five consecutive quarters and increased 12% from year end 2009 to year end 2010 The acquisition of Zephyr Gas Services extends Regency’s contract services capabilities from wellhead to market 789,494 767,060 743,289 753,328 759,704 790,494 823,369 844,800 680,000 700,000 720,000 740,000 760,000 780,000 800,000 820,000 840,000 860,000 Q1 2009 Q2 2009 Q3 2009 Q4 2009 Q1 2010 Q2 2010 Q3 2010 Q4 2010 |
 Financial Review |
 15 88% of NGLs, 84% of condensate, and 76% of natural gas are hedged for 2011 47% of NGLs, 55% of condensate, and 25% of natural gas are hedged for 2012 Commodity Price Risk Management 1 Percentages as February 4, 2011 90% 79% 61% 58% 68% 78% 79% 81% 51% 51% - 2,000 4,000 6,000 8,000 10,000 12,000 Q1 2010 Q2 2010 Q3 2010 Q4 2010 Q1 2011 Q2 2011 Q3 2011 Q4 2011 Q1 2012 Q2 2012 Natural Gas Production vs. Hedged Equity Production Hedge 80% 92% 104% 88% 89% 86% 87% 89% 75% 63% 38% 12% - 1,000 2,000 3,000 4,000 5,000 Q1 2010 Q2 2010 Q3 2010 Q4 2010 Q1 2011 Q2 2011 Q3 2011 Q4 2011 Q1 2012 Q2 2012 Q3 2012 Q4 2012 NGL Equity Production vs. Hedged Equity Production Hedge 90% 79% 83% 89% 79% 85% 85% 86% 75% 74% 48% 23% - 200 400 600 800 1,000 Q1 2010 Q2 2010 Q3 2010 Q4 2010 Q1 2011 Q2 2011 Q3 2011 Q4 2011 Q1 2012 Q2 2012 Q3 2012 Q4 2012 Condensate Equity Production vs. Hedged Equity Production Hedge 1 1 |
 Executed Hedges by Product 2011 Q1 2012 Q2 2012 Q3 2012 Q4 2012 Bbl/d Price ($/gal) Bbl/d Price ($/gal) Bbl/d Price ($/gal) Bbl/d Price ($/gal) Bbl/d Price ($/gal) Ethane 1,639 $0.50 1,530 $0.47 1,020 $0.46 510 $0.47 - - Propane 855 $1.00 730 $1.01 730 $1.05 490 $1.10 250 $1.18 Iso Butane - - - - - - - - - - Normal Butane 536 $1.34 440 $1.36 440 $1.45 300 $1.53 150 $1.62 Natural Gasoline 295 $1.71 230 $1.75 270 $1.94 160 $2.05 80 $2.19 Bbl/d Price ($/Bbl) Bbl/d Price ($/Bbl) Bbl/d Price ($/Bbl) Bbl/d Price ($/Bbl) Bbl/d Price ($/Bbl) WTI 704 $83.24 640 $84.46 630 $90.36 410 $93.66 200 $98.95 MMbtu/d Price ($/MMbtu) MMbtu/d Price ($/MMbtu) MMbtu/d Price ($/MMbtu) MMbtu/d Price ($/MMbtu) MMbtu/d Price ($/MMbtu) Natural Gas 8,000 $5.40 5,000 $5.04 5,000 $4.79 - - - - C 3 + is hedged for 2012 at higher prices than 2011 (8-15%), while natural gas and ethane are both hedged at lower prices (6-8%) 16 Commodity Price Risk Management |
 Regency has length in natural gas due to a concerted effort to minimize “keep-whole” exposure A $10.00 per Bbl movement in crude along with the same percentage change in NGL pricing would result in a $1.2 million change in Regency’s forecasted 2011 DCF A $1.00 per MMbtu movement in natural gas pricing would result in a $0.5 million change in Regency’s forecasted 2011 DCF DCF Sensitivity to Commodity Price Changes – 2011 1 ($ in millions) Decrease $10.00 Flat Increase $10.00 Decrease $1.00 $ (1.7) $ (0.5) $ 0.7 Flat $ (1.2) $ 0 $ 1.2 Increase $1.00 $ (0.7) $0.5 $ 1.7 Change in WTI Price ($/Bbl) 17 Commodity Price Risk Management 1 Based on Regency’s 2011 projections |
 Raised approximately $408 million of equity in August 2010 Completed a $600 million debt restructuring/maturity extension in October 2010 18 Strong Liquidity Position Capitalization ($ in millions) 12/31/2009 12/31/2010 Cash $10 $9 Long-Term Debt Revolving Credit Facility Senior Notes Due 2013 Senior Notes Due 2016 Senior Notes Due 2018 $420 358 236 - $285 - 256 600 Total Long-Term Debt $1,014 $1,141 Series A Convertible Redeemable Preferred Units $52 $71 Partners’ Capital¹ Noncontrolling Interest $1,229 14 $3,261 32 Total Capitalization $2,309 $4,505 1 Includes common units, general partner interest and accumulated other comprehensive loss Regency’s debt maturity profile has been extended from 4.4 years to 6.2 years Of the $285 million drawn on the revolving credit facility at year end, $250 million of floating interest rate exposure is hedged via swaps at 1.325% through April 2012 Regency currently has over $500 million of available liquidity on our revolving credit facility |
 Q&A |
 Appendix |
 Consolidated Operating Results 21 December 31, 2010 December 31, 2009 (1) REVENUES Gas sales, including related party amounts 519,344 $ 476,077 $ NGL sales, including related party amounts 390,879 239,255 Gathering, transportation and other fees, including related party amounts 293,295 270,071 Net realized and unrealized gain from derivatives (8,582) 37,712 Other, including related party amounts 26,727 20,162 Total revenues 1,221,663 1,043,277 OPERATING COSTS AND EXPENSES Cost of sales, including related party amounts 862,105 674,944 Operation and maintenance 125,650 117,080 General and administrative, including related party amounts 80,951 57,863 Loss (gain) on asset sales, net 516 (133,282) Depreciation and amortization 117,751 100,098 Total operating costs and expenses 1,186,973 816,703 OPERATING INCOME 34,690 226,574 Income from unconsolidated subsidiaries 69,365 7,886 Interest expense, net (82,792) (77,665) Loss on debt refinancing, net (17,528) - Other income and deductions, net (12,126) (15,132) (LOSS) INCOME BEFORE INCOME TAXES (8,391) 141,663 Income tax (benefit) expense 956 (1,095) (LOSS) INCOME FROM CONTINUING OPERATIONS (9,347) 142,758 DISCONTINUED OPERATIONS Net loss from operations of east Texas assets (1,571) (2,269) NET (LOSS) INCOME (10,918) $ 140,489 $ Net income attributable to noncontrolling interest (562) (91) NET (LOSS) INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP (11,480) $ 140,398 $ (1) Amounts differ from previously disclosed amounts due to the presentation as discontinued operations for the disposition of east Texas assets. Year Ended Regency Energy Partners LP Consolidated Statements of Operations ($ in thousands) |
 Gathering and Processing Segment 22 December 31, 2010 September 30, 2010 June 30, 2010 March 31, 2010 Gathering and Processing Segment Financial data: Segment margin (1) 52,915 $ 42,723 $ 49,568 $ 50,802 $ Adjusted segment margin (1) 59,731 56,690 55,162 54,608 Operating data: Throughput (MMbtu/d) (1) 1,029,597 950,583 1,002,089 1,005,172 NGL gross production (Bbls/d) 29,327 26,930 25,168 23,118 ($ in thousands) Three Months Ended December 31, 2009 September 30, 2009 June 30, 2009 March 31, 2009 Gathering and Processing Segment Financial data: Segment margin (1) 50,982 $ 54,718 $ 54,321 $ 53,899 $ Adjusted segment margin (1) 52,139 50,984 52,458 51,188 Operating data: Throughput (MMbtu/d) (1) 1,000,748 932,830 959,280 1,011,588 NGL gross production (Bbls/d) 22,725 20,334 21,185 20,151 Three Months Ended ($ in thousands) (1) Segment margin and adjusted segment margin vary from previously disclosed amounts due to the presentation of discontinued operations for the disposition of east Texas assets, as well as a functional reorganization of our operating segments. (1) Segment margin and adjusted segment margin vary from previously disclosed amounts due to the presentation of discontinued operations for the disposition of east Texas assets, as well as a functional reorganization of our operating segments. |
 Contract Compression Segment 23 December 31, 2010 September 30, 2010 June 30, 2010 March 31, 2010 Contract Compression Segment (1) Financial data: Segment margin 40,855 $ 38,510 $ 37,814 $ 37,030 $ �� Operating data: Revenue generating horsepower 844,800 823,369 790,494 759,704 Average horsepower per revenue generating 832 861 853 858 compression unit (1) Segment margin varies from previously disclosed amounts due to a functional reorganization of our operating segments. Three Months Ended ($ in thousands) December 31, 2009 September 30, 2009 June 30, 2009 March 31, 2009 Contract Compression Segment (1) Financial data: Segment margin 34,163 $ 34,085 $ 35,800 $ 36,980 $ Operating data: Revenue generating horsepower 753,328 743,289 767,060 789,494 Average horsepower per revenue generating 849 836 846 858 compression unit (1) Segment margin varies from previously disclosed amounts due to a functional reorganization of our operating segments. Three Months Ended ($ in thousands) |
 Contract Treating Segment 24 December 31, 2010 September 30, 2010 June 30, 2010 March 31, 2010 Contract Treating Segment Financial data: Segment margin 8,725 $ 2,729 $ - $ - $ Operating data: Revenue generating gallons per minute 3,431 3,093 - - Three Months Ended ($ in thousands) December 31, 2009 September 30, 2009 June 30, 2009 March 31, 2009 Contract Treating Segment Financial data: Segment margin - $ - $ - $ - $ Operating data: Revenue generating gallons per minute - - - - Three Months Ended ($ in thousands) |
 Corporate and Others Segment 25 December 31, 2010 September 30, 2010 June 30, 2010 March 31, 2010 Corporate & Others (1) Financial data: Segment margin 5,341 $ 5,763 $ 4,974 $ 5,014 $ (1) Segment margin varies from previously disclosed amounts due to a functional reorganization of our operating segments. Three Months Ended ($ in thousands) December 31, 2009 September 30, 2009 June 30, 2009 March 31, 2009 Corporate & Others (1) Financial data: Segment margin 1,964 $ 1,901 $ 1,754 $ 656 $ (1) Segment margin varies from previously disclosed amounts due to a functional reorganization of our operating segments. Three Months Ended ($ in thousands) |
 Transportation Segment – Haynesville Joint Venture 26 The following provides key performance measures for 100% of the Haynesville Joint Venture December 31, 2010 September 30, 2010 June 30, 2010 March 31, 2010 Transportation Segment - Haynesville Joint Venture Financial data: Segment margin 47,450 $ 49,121 $ 43,897 $ 33,879 $ Operating data: Throughput (MMbtu/d) 1,543,570 1,519,716 1,155,692 882,626 Three Months Ended ($ in thousands) December 31, 2009 September 30, 2009 June 30, 2009 March 31, 2009 Transportation Segment - Haynesville Joint Venture Financial data: Segment margin 12,157 $ 13,535 $ 12,803 $ 13,556 $ Operating data: Throughput (MMbtu/d) 640,166 735,565 745,178 810,848 Three Months Ended ($ in thousands) |
 Transportation Segment – MEP Joint Venture 27 The following provides key performance measures for 100% of the MEP Joint Venture December 31, 2010 September 30, 2010 June 30, 2010 March 31, 2010 Transportation Segment - MEP Joint Venture (1) Financial data: Segment margin 57,799 $ 56,197 $ 51,033 $ 47,316 $ Operating data: Throughput (MMbtu/d) (2) 1,541,533 1,432,783 1,310,363 1,348,044 (2) Due to pooling of interest corrections the MEP volume data has been revised for the quarters ended March 31, 2010 and September 30, 2010. ($ in thousands) Three Months Ended (1) On May 26, 2010, the Partnership purchased a 49.9 percent interest in MEP Joint Venture from ETE. The financial and operating data are presented at 100 percent of MEP Joint Venture. December 31, 2009 September 30, 2009 June 30, 2009 March 31, 2009 Transportation Segment - MEP Joint Venture (1) Financial data: Segment margin 46,199 $ 34,220 $ 8,614 $ 421 $ Operating data: Throughput (MMbtu/d) 1,236,620 994,924 463,802 - Three Months Ended ($ in thousands) (1) On May 26, 2010, the Partnership purchased a 49.9 percent interest in MEP Joint Venture from ETE. The financial and operating data are presented at 100 percent of MEP Joint Venture. |
 Non-GAAP Reconciliation 28 2010 2009 2008 Net (loss) income (10,918) $ 140,489 $ 101,328 $ Add (deduct): Interest expense, net 82,971 77,996 63,243 Depreciation and amortization 122,725 109,893 102,566 Income tax expense (benefit) 956 (1,095) (266) EBITDA (1) (2) 195,734 $ 327,283 $ 266,871 $ Add (deduct): Non-cash loss (gain) from derivatives 42,613 5,163 (14,708) Non-cash unit based compensation (3) 13,727 5,834 4,318 Loss (gain) on asset sales, net 591 (133,284) 472 Income from unconsolidated subsidiaries (69,365) (7,886) - Partnership's ownership interest in Haynesville Joint Venture's adjusted EBITDA (4) 67,014 11,398 - Partnership's ownership interest in MEP Joint Venture's adjusted EBITDA (5) 55,682 - - Loss on debt refinancing, net 17,528 - - Other expense, net 3,432 2,486 2,374 Adjusted EBITDA (6) 326,956 $ 210,994 $ 259,327 $ (1) Earnings before interest, taxes, depreciation and amortization. (4) 100% of Haynesville Joint Venture's Adjusted EBITDA is calculated as follows: Net income Haynesville Joint Venture 106,737 $ 19,734 $ - $ Add: Depreciation and amortization 31,797 8,514 - Interest expense 526 158 - Gain on insurance settlement (242) - - Loss on sale of asset, net 105 - - Other expense, net 14 50 - Haynesville Joint Venture's Adjusted EBITDA 138,937 $ 28,456 $ - $ Net income MEP Joint Venture 42,529 $ - $ - $ Add: Depreciation and amortization 40,104 - - Total other income (expense) 28,954 - - MEP Joint Venture's Adjusted EBITDA 111,587 $ - $ - $ Year Ended December 31, ($ in thousands) (3) The Partnership added non-cash unit based compensation as a reconciling item from EBITDA to adjusted EBITDA. Previous comparative periods have been restated. (5) 100% of MEP Joint Venture's Adjusted EBITDA is calculated as followsand represents the period from May 26, 2010 to December 31, 2010, as the Partnership acquired its 49.9 percent ownership interest on May 26, 2010: (6) Adjusted EBITDA and Combined Adjusted EBITDA differs from previously disclosed amounts as a result of the inclusion of income from unconsolidated subsidiary to account for Regency's income from the Haynesville Joint Venture and the inclusion of non-cash unit based compensation as a reconciling item to Adjusted EBITDA. (2) EBITDA varies from previously disclosed amounts as a result of new accounting pronouncement that requires disclosing non-controlling interest in income separately on the face of the income statement. |
 Non-GAAP Reconciliation 29 2010 2009 2008 Net (loss) income (10,918) $ 140,489 $ 101,328 $ Add (Deduct): Operation and maintenance 125,650 117,080 119,715 General and administrative 80,951 57,863 51,323 Loss (gain) loss on asset sales, net 516 (133,282) 457 Management services termination fee - - 3,888 Transaction expenses - - 1,620 Depreciation and amortization 117,751 100,098 93,393 Income from unconsolidated subsidiaries (69,365) (7,886) - Interest expense, net 82,792 77,665 62,940 Loss on debt refinancing, net 17,528 - - Other income and deductions, net 12,126 15,132 (328) Income tax expense (benefit) 956 (1,095) (266) Discontinued operations 1,571 2,269 (13,931) Total Segment Margin (1) 359,558 368,333 420,139 Non-cash loss (gain) from derivatives 30,183 (7,151) (17,996) Adjusted Total Segment Margin (1) 389,741 361,182 402,143 Transportation Segment Margin (1) (2) - 11,714 66,888 Contract Compression Segment Margin (1) 154,209 141,028 125,503 Contract Treating Segment Margin (1) 11,454 - - Corporate & Others Segment Margin (1) 21,092 6,275 815 Inter-segment Elimination (23,205) (4,604) (4,573) Adjusted Gathering and Processing Segment Margin (1) 226,191 $ 206,769 $ 213,510 $ Year Ended December 31, ($ in thousands) (1) Segment margin and adjusted segment margin vary from previously disclosed amounts due to the presentation of discontinued operations for the disposition of east Texas assets, a functional reorganization of our operating segments, as well as inter-segment eliminations. (2) Transportation segment margin and adjusted transportation segment margin represent Regency's 100% ownership in RIGS prior to contribution of RIGS to the Haynesville Joint Venture. |
 Non-GAAP Reconciliation 30 Three Months Ended December 31, 2010 ($ in thousands) Net cash flows provided by operating activities 41,304 $ Add (deduct): Depreciation and amortization, including debt issuance cost amortization (34,556) Write-off of debt issuance costs 1,422 Amortization of excess fair value of unconsolidated subsidiaries (3,410) Income from unconsolidated subsidiaries 27,028 Derivative valuation change (18,352) Loss on asset sales, net (78) Unit based compensation expenses (1,387) Trade accounts receivables, accrued revenues, and related party receivables 13,708 Other current assets 1,010 Trade accounts payable, accrued cost of gas and liquids, related party payables and deferred revenues (14,724) Other current liabilities 4,667 Distributions received from unconsolidated subsidiaries (27,028) Other assets and liabilities 1,473 Net loss (8,923) $ Add: Interest expense, net 19,791 Depreciation and amortization 33,217 Income tax benefit (143) EBITDA 43,942 $ Add (deduct): Non-cash loss from derivatives 18,922 Non-cash unit based compensation 1,386 Loss on asset sales, net 78 Income from unconsolidated subsidiaries (23,618) Partnership's ownership interest in Haynesville Joint Venture's adjusted EBITDA 20,374 Partnership's ownership interest in MEP Joint Venture’s adjusted EBITDA 24,095 Loss on debt refinancing, net 15,748 Other expense, net 831 Adjusted EBITDA 101,758 $ Add (deduct): Interest expense, excluding capitalized interest (19,552) Maintenance capital expenditures (4,164) Proceeds from asset disposal 128 Convertible preferred distribution (1,945) Joint venture adjustments (1) (7,844) Others 304 Cash available for distribution 68,685 $ (1) Adjustments for the Partnership's share of the Haynesville Joint Venture's and MEP Joint Venture's adjustments between their respective adjusted EBITDA and cash available for distribution. Adjustments include interest expense, maintenance capital expenditures and the Haynesville Joint Venture's non-cash portion of the general and administrative management fee. |