Attached files
Exhibit 99.1
Regency Energy Partners Reports Second-Quarter 2011 Results
Adjusted EBITDA Increased 40% Over Second Quarter of 2010
DALLAS, August 3, 2011 – Regency Energy Partners LP (Nasdaq: RGNC), (“Regency” or the “Partnership”), announced today its financial results for the second quarter ended June 30, 2011.
Regency’s adjusted EBITDA increased by approximately 40% to $103 million in the second quarter of 2011, compared to $74 million in the second quarter of 2010. This increase was primarily attributable to the acquisitions of an interest in the Midcontinent Express Pipeline (“MEP”), Zephyr Gas Services, and an interest in the Lone Star Joint Venture, which was partially offset by lower hedge pricing in 2011 compared to 2010.
“Regency delivered strong results in the second quarter of 2011, fueled by our acquisition activity over the last year and volume growth in south and west Texas in our Gathering and Processing segment,” said Mike Bradley, president and chief executive officer of Regency.
“In addition, during the quarter we announced three organic growth projects; a significant expansion of our gathering system in south Texas, as well as the construction of a new fractionation facility and the construction of a natural gas liquids pipeline through the Lone Star Joint Venture, which will strengthen our positions in the Eagle Ford Shale and Permian Basin,” continued Bradley.
REVIEW OF SEGMENT PERFORMANCE
Adjusted total segment margin increased approximately 8% to $99 million for the second quarter of 2011, compared to $92 million for the second quarter of 2010.
Gathering and Processing – The Gathering and Processing segment provides wellhead-to-market services to producers of natural gas, which includes gathering raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate NGLs from the raw natural gas and selling or delivering pipeline-quality natural gas and NGLs to various markets and pipeline systems.
Adjusted segment margin for the Gathering and Processing segment, which excludes non-cash hedging gains and losses related to the Gathering and Processing segment, was $53 million for the second quarter of 2011, compared to $55 million for the second quarter of 2010. The decrease was primarily due to lower realized commodity prices.
Total throughput volumes for the Gathering and Processing segment increased 6% to 1.1 million MMbtu per day of natural gas in the second quarter of 2011, compared to 1.0 million MMbtu per day in the second quarter of 2010. Processed NGLs increased to 28,000 barrels per day for the second quarter of 2011, compared to 25,000 barrels per day for the second quarter of 2010.
Joint Ventures – The Joint Ventures segment, formerly called the Transportation segment, consists of Regency’s 49.99% interest in the Haynesville Joint Venture, its 49.9% interest in the MEP Joint Venture and a 30% interest in the Lone Star Joint Venture. Since Regency uses the equity method of accounting for these joint ventures, Regency does not record segment margin for the Joint Ventures segment. Rather, the income attributable to each of the joint ventures is recorded as income from unconsolidated affiliates.
For the second quarter of 2011, Regency reported income from unconsolidated affiliates of $32 million, of which $14 million was related to the Haynesville Joint Venture, $10 million was related to the MEP Joint Venture and $8 million was related to the Lone Star Joint Venture. For the second quarter of 2010, Regency reported income from unconsolidated affiliates of $16 million. The increase from 2010 to 2011 was primarily due to the acquisition of an interest in the MEP Joint Venture in May 2010 and the acquisition of an interest in the Lone Star Joint Venture in May 2011.
For comparison purposes only, Regency is providing operating data and segment information assuming 100% ownership of each of the joint ventures.
The Haynesville Joint Venture consists solely of the Regency Intrastate Gas System (“RIGS”) and is operated by Regency. The Haynesville Joint Venture’s segment margin increased to $48 million for the second quarter of 2011, compared to $44 million for the second quarter of 2010. This increase was primarily driven by an increase in throughput which is further explained below.
Total throughput volumes for the Haynesville Joint Venture averaged 1.5 million MMbtu per day of natural gas for the second quarter of 2011, compared to an average of 1.2 million MMbtu per day of natural gas for the second quarter of 2010.
The MEP Joint Venture consists solely of MEP, which is operated by Kinder Morgan Energy Partners, L.P. The MEP Joint Venture’s segment margin increased to $61 million for the second quarter of 2011 compared to $51 million for the second quarter of 2010. This increase was primarily attributable to the expansion project completed in June 2010, which increased total pipeline capacity from 1.5 Bcf/d to 1.8 Bcf/d.
Total throughput volumes for the MEP Joint Venture averaged 1.2 million MMbtu per day of natural gas for the second quarter of 2011, compared to an average of 1.3 million MMbtu per day of natural gas for the second quarter of 2010.
The Lone Star Joint Venture, which was acquired on May 2, 2011, owns and operates NGL storage, fractionation and transportation assets, and is operated by Energy Transfer Partners, L.P. For the period from May 2, 2011 to June 30, 2011, the Lone Star Joint Venture’s segment margin was $46 million.
Since the acquisition on May 2, 2011, total throughput volumes for the West Texas Pipeline averaged 128,000 Bbls/d and NGL throughput volumes for Refinery Services were 15,000 Bbls/d.
Contract Compression – The Contract Compression segment provides turn-key natural gas compression services for customer-specific systems.
Segment margin for the Contract Compression segment was $37 million for the second quarter of 2011, compared to $38 million for the second quarter of 2010. The slight decrease in segment margin was primarily due to the decrease in inter-segment transactions as a result of the transfer of certain compression units from the Contract Compression segment to the Gathering and Processing segment in the second quarter of 2011. The decrease was partially offset by an increase in revenue generating horsepower, which was 758,000 at the end of the second quarter of 2011, compared to 727,000 at the end of the second quarter of 2010.
Contract Treating – The Contract Treating segment owns and operates a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management to natural gas producers and midstream pipeline companies.
Segment margin for the Contract Treating segment, which was acquired in September 2010, was $8 million for the second quarter of 2011. As of June 30, 2011, revenue generating gallons per minute (“GPM”) was 3,368.
Corporate and Others – The Corporate and Others segment is primarily comprised of revenues from the operations of a 10-mile interstate pipeline, as well as partial reimbursements of general and administrative costs from the Haynesville Joint Venture. Segment margin in the Corporate and Others segment was $5 million for the second quarter of 2011 and 2010.
ORGANIC GROWTH
In the six months ended June 30, 2011, Regency invested $124 million in growth capital projects, of which $73 million was related to organic growth projects in the Gathering and Processing segment; $45 million was related to the fabrication of new compressor packages for the Contract Compression segment; and $5 million was related to the fabrication of new treating plants for the Contract Treating segment.
Regency’s $345 million of projected 2011 organic growth capital expenditures includes $168 million for the Gathering and Processing segment, which is inclusive of 2011 expenditures related to the south Texas gathering system expansion, $95 million for the Contract Compression segment, $65 million to fund Regency’s proportionate share of growth associated with the Lone Star Joint Venture, $12 million for the Contract Treating segment and $5 million related to the Corporate and Others segment.
CASH DISTRIBUTIONS
On July 26, 2011, Regency announced its cash distribution increased to $0.45 per outstanding common unit for the second quarter ended June 30, 2011. This distribution is equivalent to $1.80 per outstanding common unit on an annual basis and will be paid on August 12, 2011, to unitholders of record at the close of business on August 5, 2011.
Based on the terms of the agreement, the Series A Preferred Units will be paid a quarterly distribution of 44.5 cents per unit for the second quarter ended June 30, 2011, on the same schedule as set forth above.
In the second quarter of 2011, Regency generated $71 million in cash available for distribution, representing coverage of 1.03 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, 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 2011 results on Thursday, August 4, 2011, at 10 a.m. Central Time (11 a.m. Eastern Time).
The dial-in number for the call is 1-866-383-8009 in the United States, or +1-617-597-5342 outside the United States, pass code 69932215. A live webcast of the call may be accessed on the investor information page of Regency Energy Partners’ website at www.regencyenergy.com. The call will be available for replay for seven days by dialing 1-888-286-8010 (from outside the U.S., +1-617-801-6888) pass code 77664707. A replay of the webcast will also be available on the Partnership’s website for 7 days.
NON-GAAP FINANCIAL INFORMATION
This press release and the accompanying financial schedules include the non-GAAP financial measures of:
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EBITDA;
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adjusted EBITDA;
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cash available for distribution;
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segment margin;
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total segment margin;
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adjusted segment margin; and
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adjusted total segment margin.
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These financial metrics are key measures of the Partnership’s financial performance. The accompanying schedules provide reconciliations of these non-GAAP financial measures to their most directly-comparable financial measures calculated and presented in accordance with accounting principles generally accepted in the United States of America ("GAAP"). Our non-GAAP financial measures should not be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as a measure of operating performance, liquidity or ability to service debt obligations.
We define EBITDA as net income (loss) plus interest expense, provision for income taxes and depreciation and amortization expense.
We define adjusted EBITDA as EBITDA plus (minus) non-cash loss (gain) from commodity and embedded derivatives, non-cash unit-based compensation, loss (gain) on asset sales, net, loss on debt refinancing, other non-cash (income) expense, net; net income attributable to noncontrolling interest; and the Partnership’s interest in adjusted EBITDA from unconsolidated affiliates less income from unconsolidated affiliates.
Adjusted EBITDA is used as a supplemental performance measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:
-- financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
-- the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our unitholders and general partner;
-- our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing methods or capital structure; and
-- the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.
Our EBITDA and adjusted EBITDA may not be comparable to a similarly titled measure of another company because other entities may not calculate EBITDA or adjusted EBITDA in the same manner.
We define cash available for distribution as adjusted EBITDA:
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minus interest expense, excluding capitalized interest;
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minus maintenance capital expenditures;
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plus cash proceeds from asset sales, if any; and
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joint venture adjustments, which mainly include interest expense and maintenance capital expenditures.
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Cash available for distribution is used as a supplemental liquidity measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to approximate the amount of operating surplus generated by us during a specific period and to assess our ability to make cash distributions to our unitholders and our general partner. Cash available for distribution is not the same measure as operating surplus or available cash, both of which are defined in our partnership agreement.
We define segment margin, generally, as revenues minus cost of sales. We calculate our Gathering and Processing segment margin and Corporate and Others segment margin as our revenues generated from operations minus the cost of natural gas and NGLs purchased and other cost of sales, including third-party transportation and processing fees.
We do not record segment margin for the Joint Ventures segment because we record our ownership percentages of the net income in the Haynesville Joint Venture, MEP Joint Venture and the Lone Star Joint Venture as income from unconsolidated affiliates.
We calculate our Contract Compression segment margin as our revenues minus the direct costs, primarily compressor unit repairs, associated with those revenues.
We calculate our Contract Treating segment margin as our revenues minus direct costs associated with those revenues.
We calculate total segment margin as the summation of segment margin of our five segments, less intersegment eliminations.
We define adjusted segment margin as segment margin adjusted for non-cash (gains) losses from commodity derivatives. We define adjusted total segment margin as total segment margin adjusted for non-cash (gains) losses from commodity derivatives. Our adjusted total segment margin equals the sum of our operating segments’ adjusted segment margins or segment margins, including intersegment eliminations. Adjusted segment margin and adjusted total segment margin are included as supplemental disclosures because they are primary performance measures used by management as they represent the results of our revenues and cost of revenues, a key component of our operations.
Our total segment margin and adjusted total segment margin may not be comparable to a similarly titled measure of another company because other entities may not calculate these amounts in the same manner.
For quarterly comparison purposes only, we have also used the following non-GAAP financial measures related to the Haynesville Joint Venture, the MEP Joint Venture, and the Lone Star Joint Venture:
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Haynesville Joint Venture segment margin;
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MEP Joint Venture segment margin;
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Lone Star Joint Venture segment margin.
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Segment margin is calculated as each joint venture’s revenue minus cost of sales.
FORWARD-LOOKING INFORMATION
This release contains “forward-looking” statements, which are any statements that do not relate strictly to historical facts. The words “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “plan,” “project,” “will” or similar expressions help identify forward-looking statements. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions, which include, but are not limited to, the risks, uncertainties and assumptions enumerated in our Forms 10-Q and 10-K as filed with the Securities and Exchange Commission. Although we believe our forward-looking statements are based on reasonable assumptions, current expectations and projections about future events, we cannot give assurances that such assumptions, expectations and projections will prove to be correct. Therefore, actual results and outcomes may differ materially from those expressed in such forward-looking statements. We undertake no obligation to update publicly or to revise any forward-looking statements, whether as a result of new information, future events or otherwise.
Regency Energy Partners LP (Nasdaq: RGNC) is a growth-oriented, midstream energy partnership engaged in the gathering and processing, contract compression, treating, transportation, fractionation and storage of natural gas and natural gas liquids. Regency's general partner is owned by Energy Transfer Equity, L.P. (NYSE: ETE). For more information, visit the Regency Energy Partners LP website at www.regencyenergy.com.
On July 29, 2011, Regency announced that it has been authorized to list its common units representing limited partner interests on the New York Stock Exchange (“NYSE”). Regency anticipates that its common units will begin trading on the NYSE under the symbol “RGP” on August 9, 2011. Until that time, Regency’s common units will continue to be traded on NASDAQ under the symbol “RGNC.”
CONTACT:
Investor Relations:
Lyndsay Hannah
Regency Energy Partners
Manager, Finance & Investor Relations
214-840-5477
ir@regencygas.com
Media Relations:
Elizabeth Cornelius
HCK2 Partners
972-716-0500 x26
elizabeth.cornelius@hck2.com
Consolidated Income Statements
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Regency Energy Partners LP
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Consolidated Statements of Operations
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Unaudited
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($ in thousands)
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Successor
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Predecessor
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Three Months Ended June 30, 2011
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Period from Acquisition May 26, 2010 to June 30, 2010 (1)
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Period from April 1, 2010 to May 25, 2010 (1)
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REVENUES
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Gas sales, including related party amounts of $6,161, $447 and $0
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$ | 132,800 | $ | 47,241 | $ | 87,193 | |||
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NGL sales, including related party amounts of $77,048, $18,054 and $0
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138,088 | 26,040 | 62,997 | ||||||
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Gathering, transportation and other fees, including related party amounts of $5,254, $2,086 and $3,680
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81,817 | 22,571 | 45,041 | ||||||
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Net realized and unrealized loss from derivatives
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(7,542 | ) | (130 | ) | 223 | ||||
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Other, including related party amounts of $2,924, $0 and $0
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11,335 | 1,258 | 4,811 | ||||||
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Total revenues
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356,498 | 96,980 | 200,265 | ||||||
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OPERATING COSTS AND EXPENSES
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Cost of sales, including related party amounts of $7,807, $2,281 and $3,198
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259,475 | 70,174 | 140,507 | ||||||
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Operation and maintenance
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33,996 | 10,402 | 19,315 | ||||||
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General and administrative, including related party amounts of $4,224 and $833 and $0
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17,551 | 7,104 | 21,809 | ||||||
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Loss on asset sales, net
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153 | 10 | 19 | ||||||
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Depreciation and amortization
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40,503 | 10,545 | 16,889 | ||||||
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Total operating costs and expenses
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351,678 | 98,235 | 198,539 | ||||||
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OPERATING INCOME (LOSS)
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4,820 | (1,255 | ) | 1,726 | |||||
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Income from unconsolidated affiliates
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32,167 | 8,121 | 7,959 | ||||||
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Interest expense, net
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(24,689 | ) | (8,081 | ) | (14,059 | ) | |||
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Other income and deductions, net
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2,641 | (3,521 | ) | (624 | ) | ||||
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INCOME (LOSS) BEFORE INCOME TAXES
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14,939 | (4,736 | ) | (4,998 | ) | ||||
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Income tax expense
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102 | 245 | 83 | ||||||
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INCOME (LOSS) FROM CONTINUING OPERATIONS
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14,837 | (4,981 | ) | (5,081 | ) | ||||
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DISCONTINUED OPERATIONS
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Net Income from operations of east Texas assets
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- | 86 | 585 | ||||||
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NET INCOME (LOSS)
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$ | 14,837 | $ | (4,895 | ) | $ | (4,496 | ) | |
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Net income attributable to noncontrolling interest
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(293 | ) | (29 | ) | (244 | ) | |||
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NET INCOME (LOSS) ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP
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$ | 14,544 | $ | (4,924 | ) | $ | (4,740 | ) | |
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(1) Amounts differ from previously disclosed amounts due to the presentation of discontinued operations for the disposition of east Texas assets.
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Segment Financial and Operating Data
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Three Month Ended June 30,
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2011
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2010 (1)
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($ in thousands)
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Gathering and Processing Segment
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Financial data:
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Segment margin (1)
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$ | 50,495 | $ | 49,568 | ||
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Adjusted segment margin (1)
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52,642 | 55,162 | ||||
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Operating data:
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Throughput (MMbtu/d)
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1,063,499 | 1,002,089 | ||||
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NGL gross production (Bbls/d)
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28,100 | 25,168 | ||||
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(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.
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Three Months Ended June 30,
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2011
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2010
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($ in thousands)
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Contract Compression Segment
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Financial data:
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Segment margin
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$ | 36,973 | $ | 37,814 | ||
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Operating data:
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Revenue generating horsepower
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757,572 | 727,296 | ||||
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Three Month Ended June 30,
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2011
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2010 (1)
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($ in thousands)
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Contract Treating Segment
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Financial data:
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Segment margin
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$ | 7,701 | $ | - | ||
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Operating data:
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Revenue generating GPM
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3,368 | - | ||||
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(1) The Partnership acquired Contract Treating segment in September 2010.
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Three Months Ended June 30,
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2011
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2010 (1)
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($ in thousands)
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Corporate & Others
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Financial data:
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Segment margin (1)
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$ | 4,762 | $ | 4,974 | ||
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(1) Segment margin varies from previously disclosed amounts due to a functional reorganization of our operating segments.
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The following provides key performance measures for 100% of the Haynesville Joint Venture, the MEP Joint Venture and the Lone Star Joint Venture
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Three Months Ended June 30,
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2011
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2010
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($ in thousands)
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Joint Ventures Segment - Haynesville Joint Venture
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Financial data:
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Segment margin
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$ | 48,353 | $ | 43,897 | ||
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Operating data:
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Throughput (MMbtu/d)
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1,528,333 | 1,155,692 | ||||
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Three Months Ended June 30,
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2011
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2010 (1)
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Joint Ventures Segment - MEP Joint Venture
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Financial data:
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Segment margin
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$ | 61,049 | $ | 51,033 | ||
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Operating data:
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Throughput (MMbtu/d)
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1,197,520 | 1,310,363 | ||||
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(1) On May 26, 2010, the Partnership acquired 49.9% interest in MEP. The financial and operating data are presented for the three months ended June 30, 2010.
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From May 2, 2011 (Initial Acquisition Date) to June 30, 2011
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Joint Ventures Segment - Lone Star Joint Venture
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Financial data:
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Segment margin
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$ | 46,415 | |
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Operating data:
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West Texas Pipeline- Throughput (Bbls/d)
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128,127 | ||
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Refinery Service- NGL Throughput (Bbls/d)
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14,806 | ||
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
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Three Months Ended
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June 30, 2011
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June 30, 2010
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($ in thousands)
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Net income
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$ | 30,265 | $ | 25,871 | ||
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Add:
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Operation and maintenance
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4,828 | 5,189 | ||||
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General and administrative
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4,345 | 4,658 | ||||
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Depreciation and amortization
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8,664 | 8,100 | ||||
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Interest expense, net
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251 | 99 | ||||
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Other income and deductions, net
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- | (20 | ) | |||
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Total Segment Margin (1)
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$ | 48,353 | $ | 43,897 | ||
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(1) Calculation represents 100% of Haynesville Joint Venture's Segment Margin.
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Three Months Ended June 30,
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2011
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2010
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($ in thousands)
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Net income
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$ | 20,276 | $ | 14,764 | ||
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Add:
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Operation and maintenance
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3,143 | 2,992 | ||||
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General and administrative
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7,310 | 6,506 | ||||
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Depreciation and amortization
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17,398 | 16,101 | ||||
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Interest expense, net
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12,922 | 10,670 | ||||
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Total Segment Margin (1)
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$ | 61,049 | $ | 51,033 | ||
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(1) Calculation represents 100% of MEP Joint Venture's Segment Margin.
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From May 2, 2011 (Initial Acquisition Date) to June 30, 2011
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($ in thousands)
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Net income
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$ | 27,958 | |
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Add:
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Operation and maintenance
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6,485 | ||
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General and administrative
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4,649 | ||
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Depreciation and amortization
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7,139 | ||
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Tax expense
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192 | ||
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Other income and deductions, net
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(8 | ) | |
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Total Segment Margin (1)
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$ | 46,415 | |
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(1) Calculation represents 100% of Lone Star Joint Venture's Segment Margin. The Partnership acquired 30% interest in the joint venture in May 2011.
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Reconciliation of Non-GAAP Measures to GAAP Measures
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Three Months Ended June 30,
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2011
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2010
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($ in thousands)
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Net income (loss)
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$ | 14,837 | $ | (9,391 | ) | |
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Add (deduct):
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Interest expense, net
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24,689 | 22,224 | ||||
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Depreciation and amortization
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40,503 | 29,604 | ||||
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Income tax expense
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102 | 328 | ||||
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EBITDA (1)
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$ | 80,131 | $ | 42,765 | ||
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Add (deduct):
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Non-cash (gain) loss from commodity and embedded derivatives
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(803 | ) | 9,854 | |||
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Non-cash unit based compensation
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875 | 10,441 | ||||
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Loss on asset sales, net
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153 | 29 | ||||
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Income from unconsolidated affiliates
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(32,167 | ) | (16,080 | ) | ||
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Partnership's ownership interest in Haynesville Joint Venture's adjusted EBITDA (2)
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19,586 | 16,333 | ||||
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Partnership's ownership interest in MEP Joint Venture's adjusted EBITDA (3)
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25,243 | 8,424 | ||||
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Partnership's ownership interest in Lone Star Joint Venture's adjusted EBITDA (4)
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10,584 | - | ||||
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Other (income) expense, net
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(146 | ) | 2,165 | |||
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Adjusted EBITDA
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$ | 103,456 | $ | 73,931 | ||
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(1) Earnings before interest, taxes, depreciation and amortization.
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(2) 100% of Haynesville Joint Venture's Adjusted EBITDA is calculated as follows:
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Net income Haynesville Joint Venture
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$ | 30,265 | $ | 25,871 | ||
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Add:
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Depreciation and amortization
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8,664 | 8,100 | ||||
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Interest expense, net
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251 | 99 | ||||
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Other expense, net
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- | 12 | ||||
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Haynesville Joint Venture's Adjusted EBITDA
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$ | 39,180 | $ | 34,082 | ||
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(3) 100% of MEP Joint Venture's Adjusted EBITDA is calculated as follows:
|
||||||
|
Net income MEP Joint Venture
|
$ | 20,276 | $ | 8,068 | ||
|
Add:
|
||||||
|
Depreciation and amortization
|
17,398 | 5,383 | ||||
|
Interest expense, net
|
12,913 | 3,431 | ||||
|
MEP Joint Venture's Adjusted EBITDA
|
$ | 50,587 | $ | 16,882 | ||
|
(4) 100% of Lone Star Joint Venture's Adjusted EBITDA is calculated as follows:
|
||||||
|
Net income Lone Star Joint Venture
|
$ | 27,958 | $ | - | ||
|
Add:
|
||||||
|
Depreciation and amortization
|
7,139 | - | ||||
|
Income tax expense
|
192 | - | ||||
|
Other (income) expense
|
(7 | ) | - | |||
|
Lone Star Joint Venture's Adjusted EBITDA
|
$ | 35,282 | $ | - | ||
Non-GAAP Adjusted Segment Margin to GAAP Net Income
|
Three Months Ended
|
||||||
|
June 30, 2011
|
June 30, 2010 (1)
|
|||||
|
Net income (loss)
|
$ | 14,837 | $ | (9,391 | ) | |
|
Add (Deduct):
|
||||||
|
Operation and maintenance
|
33,996 | 29,717 | ||||
|
General and administrative
|
17,551 | 28,913 | ||||
|
Loss on asset sales, net
|
153 | 29 | ||||
|
Depreciation and amortization
|
40,503 | 27,434 | ||||
|
Income from unconsolidated affiliates
|
(32,167 | ) | (16,080 | ) | ||
|
Interest expense, net
|
24,689 | 22,140 | ||||
|
Loss on debt refinancing, net
|
- | |||||
|
Other income and deductions, net
|
(2,641 | ) | 4,145 | |||
|
Income tax expense
|
102 | 328 | ||||
|
Discontinued Operations
|
- | (671 | ) | |||
|
Total Segment Margin (1)
|
97,023 | 86,564 | ||||
|
Non-cash loss from commodity derivatives
|
2,147 | 5,594 | ||||
|
Adjusted Total Segment Margin (1)
|
99,170 | 92,158 | ||||
|
Gathering and Processing Segment Margin
|
$ | 50,495 | $ | 49,568 | ||
|
Non-cash loss from commodity derivatives
|
2,147 | 5,594 | ||||
|
Adjusted Gathering and Processing Segment Margin
|
52,642 | 55,162 | ||||
|
Contract Compression Segment Margin
|
36,973 | 37,814 | ||||
|
Contract Treating Segment Margin
|
7,701 | - | ||||
|
Corporate and Others Segment Margin (1)
|
4,762 | 4,974 | ||||
|
Inter-segment Elimination
|
(2,908 | ) | (5,792 | ) | ||
|
Adjusted Total Segment Margin (1)
|
$ | 99,170 | $ | 92,158 | ||
|
(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 and a functional reorganization of our operating segments.
|
||||||
Reconciliation of “cash available for distribution” to net cash flows provided by operating activities and to net income
|
Three Months Ended
|
|||
|
June 30, 2011
|
|||
|
($ in thousands)
|
|||
|
Net cash flows provided by operating activities
|
$ | 72,136 | |
|
Add (deduct):
|
- | ||
|
Depreciation and amortization, including debt issuance cost amortization
|
(41,938 | ) | |
|
Amortization of excess fair value of unconsolidated subsidiaries
|
(1,461 | ) | |
|
Income from unconsolidated subsidiaries
|
33,628 | ||
|
Derivative valuation change
|
1,140 | ||
|
Loss on asset sales, net
|
(153 | ) | |
|
Unit based compensation expenses
|
(826 | ) | |
|
Trade accounts receivables, accrued revenues, and related party receivables
|
16,147 | ||
|
Other current assets
|
(3,060 | ) | |
|
Trade accounts payable, accrued cost of gas and liquids, related party payables and deferred revenues
|
(40,722 | ) | |
|
Other current liabilities
|
13,377 | ||
|
Distributions received from unconsolidated subsidiaries
|
(33,628 | ) | |
|
Other assets and liabilities
|
197 | ||
|
Net income
|
$ | 14,837 | |
|
Add:
|
|||
|
Interest expense, net
|
24,689 | ||
|
Depreciation and amortization
|
40,503 | ||
|
Income tax expense
|
102 | ||
|
EBITDA
|
$ | 80,131 | |
|
Add (deduct):
|
|||
|
Non-cash gain from commodity and embedded derivatives
|
(803 | ) | |
|
Non-cash unit based compensation
|
875 | ||
|
Loss on asset sales, net
|
153 | ||
|
Income from unconsolidated affiliates
|
(32,167 | ) | |
|
Partnership's ownership interest in Haynesville Joint Venture's adjusted EBITDA
|
19,586 | ||
|
Partnership's ownership interest in MEP Joint Venture's adjusted EBITDA
|
25,243 | ||
|
Partnership's ownership interest in Lone Star Joint Venture's adjusted EBITDA
|
10,584 | ||
|
Other expense, net
|
(146 | ) | |
|
Adjusted EBITDA
|
$ | 103,456 | |
|
Add (deduct):
|
|||
|
Interest expense, excluding capitalized interest
|
(23,724 | ) | |
|
Maintenance capital expenditures
|
(2,010 | ) | |
|
Proceeds from asset disposal
|
3,978 | ||
|
Convertible preferred distribution
|
(1,945 | ) | |
|
Joint venture adjustments (1)
|
(9,115 | ) | |
|
Other
|
(65 | ) | |
|
Cash available for distribution
|
$ | 70,575 | |
|
(1) Adjustments for the Partnership's share of the Haynesville Joint Venture's, MEP Joint Venture's and Lone Star Joint Venture's adjustments between their respective adjusted EBITDA and cash available for distribution. Adjustments mainly include interest expense and maintenance capital expenditures.
|
|||