Regency Energy Partners Reports Second Quarter 2012 Earnings Results

Regency Energy Partners LP (NYSE: RGP), (“Regency” or the “Partnership”), announced today its financial results for the second quarter ended June 30, 2012.

Adjusted EBITDA increased 12% to $115 million in the second quarter of 2012, compared to $103 million in the second quarter of 2011. The increase in adjusted EBITDA was primarily due to a $13 million increase in gathering and processing adjusted segment margin related to volume growth in south and west Texas and north Louisiana; and $5 million primarily related to the Lone Star Joint Venture that was acquired in May 2011; partially offset by a $5 million increase in operation and maintenance expense primarily due to increased volumes across the business segments.

In the second quarter of 2012, Regency generated $71 million in cash available for distribution, compared to $71 million in the second quarter of 2011. Also in the second quarter of 2012, net income increased to $29 million, compared to $15 million in the second quarter of 2011.

“Regency had a solid second quarter, largely due to increased volumes in south and west Texas and in north Louisiana associated with additional Cotton Valley drilling, as well as continued benefits from our acquisition of an interest in the Lone Star Joint Venture,” said Mike Bradley, president and chief executive officer of Regency.

“Drilling activity in liquids-rich plays remains our primary growth driver and construction of our primarily fee-based projects in these areas is progressing as planned. We expect this organic growth to generate new opportunities as it begins coming online in 2013,” said Bradley.

REVIEW OF SEGMENT PERFORMANCE

Adjusted total segment margin increased 12% to $111 million for the second quarter of 2012, compared to $99 million for second 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 Ranch JV, which processes natural gas delivered from the NGLs-rich Bone Spring and Avalon shale formations in west Texas. In June 2012, the Ranch JV’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 $65 million for second quarter of 2012, compared to $53 million for the second quarter of 2011. The increase was primarily due to volume growth in south and west Texas and north Louisiana.

Total throughput volumes for the Gathering and Processing segment increased to 1.4 million MMbtu per day of natural gas for the second quarter of 2012, compared to 1.1 million MMbtu per day of natural gas for the second quarter of 2011. Processed NGLs increased to 37,000 barrels per day for the second quarter of 2012, compared to 28,000 barrels per day for the second 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 $12 million for the second quarter of 2012, compared to $14 million for the second quarter of 2011. Total throughput volumes for the Haynesville Joint Venture averaged 0.9 million MMbtu per day of natural gas for the second quarter of 2012, compared to 1.5 million MMbtu per day for the second 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 second quarter of 2012 and 2011. Total throughput volumes for the MEP Joint Venture averaged 1.4 million MMbtu per day of natural gas for the second quarter of 2012 and 1.2 million MMbtu per day for the second 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 second quarter of 2012, income from unconsolidated affiliates for the Lone Star Joint Venture was $12 million, compared to $8 million for the period from May 2, 2011 to June 30, 2011. For the second quarter of 2012, total throughput volumes for the West Texas Pipeline averaged 133,000 barrels per day, compared to 128,000 barrels per day for the period from May 2, 2011 to June 30, 2011, and NGL Fractionation throughput volumes averaged 21,000 barrels per day, compared to 15,000 barrels per day.

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 $38 million for the second quarter of 2012, compared to $37 million for the second quarter of 2011. As of June 30, 2012, the Contract Compression segment’s revenue generating horsepower, including intersegment revenue generating horsepower, increased to 825,000, compared to 811,000 as of June 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 $7 million for the second quarter of 2012, compared to $8 million for the second quarter of 2011. As of June 30, 2012, revenue generating gallons per minute was 3,773, compared to 3,368 as of June 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 second quarter of 2012 and second quarter of 2011.

ORGANIC GROWTH

In the six months ended June 30, 2012, Regency incurred $373 million of growth capital expenditures: $163 million for the Joint Ventures segment, $136 million for the Gathering and Processing segment, $55 million for the Contract Compression segment and $19 million for the Contract Treating segment.

In the six months ended June 30, 2012, Regency incurred $15 million of maintenance capital expenditures.

In 2012, Regency expects to invest between $775 and $825 million in growth capital expenditures, of which $310 million is related to the Gathering and Processing segment, which includes expenditures related to the Ranch Joint Venture; between $350 and $400 million related to the Lone Star Joint Venture; $70 million related to the Contract Compression segment; $40 million related to the Contract Treating segment; and $5 million related to the Corporate and Others segment.

In addition, Regency expects to make $28 million in maintenance capital expenditures in 2012, including its proportionate share related to joint ventures.

CASH DISTRIBUTIONS

On July 26, 2012, Regency announced a cash distribution of $0.46 per outstanding common unit for the second quarter ended June 30, 2012. This distribution is equivalent to $1.84 per outstanding common unit on an annual basis and will be paid on August 14, 2012, to unitholders of record at the close of business on August 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 second quarter ended June 30, 2012, on the same schedule as set forth above.

In the second quarter of 2012, Regency generated $71 million in cash available for distribution, representing 0.87 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 second-quarter 2012 results Wednesday, August 8, 2012 at 10 a.m. Central Time (11 a.m. Eastern Time).

The dial-in number for the call is 1-800-299-6183 in the United States, or +1-617-801-9713 outside the United States, passcode 55203815. 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 60462094. 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 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.

Consolidated Balance Sheet
 
Regency Energy Partners LP
Condensed Consolidated Balance Sheets
($ in thousands)
     
 
June 30, 2012 December 31, 2011
Assets
Current assets $ 184,934 $ 187,124
 
Property, plant and equipment, net 1,992,448 1,885,528
 
Investment in unconsolidated affiliates 2,102,503 1,924,705
Long-term derivative assets 1,872 474
Other assets, net 34,770 39,353
Intangible assets, net 726,246 740,883
Goodwill   789,789   789,789
Total Assets $ 5,832,562 $ 5,567,856
 
Liabilities and Partners' Capital and Noncontrolling Interest
Current liabilities $ 202,676 $ 233,306
 
Long-term derivative liabilities 30,644 39,112
Other long-term liabilities 5,721 6,071
Long-term debt 1,780,558 1,687,147
 
Series A Preferred Units 72,370 71,144
 
Partners' capital 3,696,842 3,498,207
Noncontrolling interest   43,751   32,869
Total Partners' Capital and Noncontrolling Interest   3,740,593   3,531,076
Total Liabilities and Partners' Capital and Noncontrolling Interest $ 5,832,562 $ 5,567,856
 
 

Consolidated Statements of Operations
 
Regency Energy Partners LP
Condensed Consolidated Statements of Operations
($ in thousands)
   
Three Months Ended June 30,
2012 2011
 
REVENUES $ 311,976 $ 356,498
 
OPERATING COSTS AND EXPENSES
Cost of sales, including related party amounts 186,815 259,475
Operation and maintenance 38,992 33,996
General and administrative, including related party amounts 16,476 17,551
Loss on asset sales, net 1,548 153
Depreciation and amortization   45,132     40,503  

Total operating costs and expenses
288,963 351,678
 
OPERATING INCOME 23,013 4,820
 
Income from unconsolidated affiliates 34,185 32,167
Interest expense, net (27,934 ) (24,689 )
Loss on debt refinancing, net (7,820 ) -
Other income and deductions, net   7,921     2,641  
INCOME BEFORE INCOME TAXES 29,365 14,939
Income tax expense   38     102  
NET INCOME $ 29,327 $ 14,837
Net income attributable to noncontrolling interest   (649 )   (293 )
NET INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP $ 28,678   $ 14,544  
 
Limited partners' interest in net income $ 24,053 $ 10,999
Weighted average number of common units outstanding 170,107,060 142,937,163
Basic income per common unit $ 0.14 $ 0.08
Diluted income per common unit $ 0.10 $ 0.07
 
 

Segment Financial and Operating Data
     
Three Months Ended June 30,
2012 2011
($ in thousands)
Gathering and Processing Segment
Financial data:
Segment margin $ 79,416 $ 50,495
Adjusted segment margin 65,463 52,642
Operating data:
Throughput (MMbtu/d) 1,380,000 1,063,000
NGL gross production (Bbls/d) 37,200 28,000
 
 
Three Months Ended June 30,
2012 2011
($ in thousands)
Contract Compression Segment
Financial data:
Segment margin $ 38,015 $ 36,973
Operating data:
Revenue generating horsepower, including intercompany revenue generating horsepower 825,000 811,000
 
 
Three Months Ended June 30,
2012 2011
($ in thousands)
Contract Treating Segment
Financial data:
Segment margin $ 7,241 $ 7,701
Operating data:
Revenue generating gallons per minute 3,773 3,368
 
 
Three Months Ended June 30,
2012 2011
($ in thousands)
Corporate & Others
Financial data:
Segment margin $ 5,497 $ 4,762
 
 

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 June 30,
2012   2011
($ in thousands)
Haynesville Joint Venture
Financial data:
Segment margin $ 46,311 $ 48,353
Operating data:
Throughput (MMbtu/d) 903,344 1,528,333
 
 
Three Months Ended June 30,
2012 2011
($ in thousands)
MEP Joint Venture
Financial data:
Segment margin $ 61,090 $ 61,049
Operating data:
Throughput (MMbtu/d) 1,418,206 1,197,520
 
 

Three MonthsEnded June 30,

From May 2, 2011(initial Acquisitiondate) to June 30,
2012

2011
($ in thousands)
Lone Star Joint Venture
Financial data:
Segment margin $ 72,250 $ 46,415
Operating data:
West Texas Pipeline Throughput (Bbls/d) 133,429 128,127
NGL Fractionation Throughput (Bbls/d) 20,575 14,806
 
We acquired a 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 June 30,
2012     2011
Haynesville Joint Venture ($ in thousands)
Net income $ 26,222 $ 30,265
Add:
Operation and maintenance 5,367 4,828
General and administrative 5,156 4,345
Depreciation and amortization 9,108 8,664
Interest expense, net 460 251
Other income and deductions, net   (2 )   -  
Total Segment Margin $ 46,311   $ 48,353  
 
 
Three Months Ended June 30,
2012 2011
MEP Joint Venture ($ in thousands)
Net income $ 20,377 $ 20,276
Add:
Operation and maintenance 3,535 3,143
General and administrative 6,922 7,310
Depreciation and amortization 17,357 17,398
Interest expense, net   12,899     12,922  
Total Segment Margin $ 61,090   $ 61,049  
 
 
Three Months Ended June 30,
2012 2011
Lone Star Joint Venture ($ in thousands)
Net income $ 41,220 $ 27,958
Add:
Operation and maintenance 15,054 6,485
General and administrative 4,496 4,649
Depreciation and amortization 12,635 7,139
Tax expense 402 192
Other income and deductions, net   (1,557 )   (8 )
Total Segment Margin $ 72,250   $ 46,415  
 
We acquired a 30% interest in Lone Star Joint Venture in May 2011.
 

Reconciliation of Non-GAAP Measures to GAAP Measures
 
Three Months Ended June 30,
2012     2011
($ in thousands)
Net income $ 29,327 $ 14,837
Add (deduct):
Interest expense, net 27,934 24,689
Depreciation and amortization 45,132 40,503
Income tax expense   38     102  
EBITDA (1) $ 102,431 $ 80,131
Add (deduct):
Non-cash gain from commodity and embedded derivatives (21,862 ) (803 )
Unit-based compensation expenses 1,005 875
Loss on asset sales, net 1,548 153
Loss on debt refinancing, net 7,820 -
Income from unconsolidated affiliates (34,185 ) (32,167 )
Partnership's interest in unconsolidated affiliates' adjusted EBITDA (2)(3)(4)(5) 59,163 55,413
Other income, net   (649 )   (146 )
Adjusted EBITDA $ 115,271   $ 103,456  
 
(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 $ 26,222 $ 30,265
Add (deduct):
Depreciation and amortization 9,108 8,664
Interest expense, net 460 251
Other expense, net   -     -  
Haynesville Joint Venture's Adjusted EBITDA $ 35,790 $ 39,180
Ownership interest   49.99 %   49.99 %
Partnership's interest in Haynesville Joint Venture's Adjusted EBITDA $ 17,891   $ 19,586  
 
(3) 100% of MEP Joint Venture's Adjusted EBITDA and the Partnership's interest are calculated as follows:
Net income MEP Joint Venture $ 20,377 $ 20,276
Add:
Depreciation and amortization 17,357 17,398
Interest expense, net   12,899     12,913  
MEP Joint Venture's Adjusted EBITDA $ 50,633 $ 50,587
Ownership interest   50 %   49.90 %
Partnership's interest in MEP Joint Venture's Adjusted EBITDA $ 25,317   $ 25,243  
 
(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 $ 41,220 $ 27,958
Add (deduct):
Depreciation and amortization

$
12,635 $ 7,139
Other expenses, net

$
(673 ) $ 185  
Lone Star Joint Venture's Adjusted EBITDA $ 53,182 $ 35,282
Ownership interest   30 %   30 %
Partnership's interest in Lone Star Joint Venture's Adjusted EBITDA $ 15,954   $ 10,584  
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 Star Joint Venture $ (51 ) $ -
Add (deduct):
Depreciation and amortization

$
55   $ -  
Ranch Joint Venture's Adjusted EBITDA $ 4 $ -
Ownership interest   33 %   0 %
Partnership's interest in Ranch Joint Venture's Adjusted EBITDA $ 1   $ -  
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 June 30,
2012     2011
($ in thousands)
Net income $ 29,327 $ 14,837
Add (deduct):
Operation and maintenance 38,992 33,996
General and administrative 16,476 17,551
Loss on asset sales, net 1,548 153
Depreciation and amortization 45,132 40,503
Income from unconsolidated affiliates (34,185 ) (32,167 )
Interest expense, net 27,934 24,689
Loss on debt refinancing, net 7,820 -
Other income and deductions, net (7,921 ) (2,641 )
Income tax expense   38     102  
Total Segment Margin 125,161 97,023
Non-cash (gain) loss from commodity derivatives   (13,953 )   2,147  
Adjusted Total Segment Margin $ 111,208   $ 99,170  
 
Gathering & Processing Segment Margin $ 79,416 $ 50,495
Non-cash (gain) loss from commodity derivatives   (13,953 )   2,147  
Adjusted Gathering and Processing Segment Margin 65,463 52,642
 
Contract Compression Segment Margin 38,015 36,973
 
Contract Treating Segment Margin 7,241 7,701
 
Corporate & Others Segment Margin 5,497 4,762
 
Inter-segment Eliminations (5,008 ) (2,908 )
   
Adjusted Total Segment Margin $ 111,208   $ 99,170  
 
 

Reconciliation of “cash available for distribution” to net cash flows provided by operating activities and to net income
 
Three Months Ended June 30,
2012     2011
($ in thousands)
Net cash flows provided by operating activities $ 46,129 $ 72,136
Add (deduct):
Depreciation and amortization, including debt issuance cost and bond premium amortization (44,868 ) (43,399 )
Income from unconsolidated affiliates 32,723 33,628
Derivative valuation changes 21,862 1,140
Loss on asset sales, net (1,548 ) (153 )
Unit-based compensation expenses (1,005 ) (826 )
Cash flow changes in current assets and liabilities:
Trade accounts receivables, accrued revenues, and related party receivables (13,704 ) 16,147
Other current assets (902 ) (3,060 )
Trade accounts payable, accrued cost of gas and liquids, related party payables and deferred revenues 18,357 (40,722 )
Other current liabilities 6,360 13,377
Distributions received from unconsolidated affiliates (34,084 ) (33,628 )
Other assets and liabilities   7     197  
Net Income $ 29,327   $ 14,837  
Add:
Interest expense, net 27,934 24,689
Depreciation and amortization 45,132 40,503
Income tax expense   38     102  
EBITDA $ 102,431   $ 80,131  
Add (deduct):
Non-cash gain from commodity and embedded derivatives (21,862 ) (803 )
Unit-based compensation expenses 1,005 875
Loss on asset sales, net 1,548 153
Loss on debt refinancing, net 7,820 -
Income from unconsolidated affiliates (34,185 ) (32,167 )
Partnership's interest in unconsolidated affiliates' adjusted EBITDA 59,163 55,413
Other income, net   (649 )   (146 )
Adjusted EBITDA $ 115,271   $ 103,456  
Add (deduct):
Interest expense, excluding capitalized interest (40,971 ) (30,307 )
Maintenance capital expenditures (7,274 ) (3,190 )
Proceeds from asset sales 7,352 3,978
Distributions to Series A Preferred Units (1,945 ) (1,945 )
Other adjustments   (1,522 )   (1,417 )
Cash Available For Distribution $ 70,911   $ 70,575  

Copyright Business Wire 2010

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