Regency Energy Partners Reports Third Quarter 2012 Earnings Results

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.
 
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  

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