Attached files
Exhibit 99.1
Regency Energy Partners Reports Second Quarter 2012 Earnings Results
DALLAS, August 7, 2012 – 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:
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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. 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:
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non-cash loss (gain) from commodity and embedded derivatives;
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non-cash unit-based compensation expenses;
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loss (gain) on asset sales, net;
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loss on debt refinancing, net;
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other non-cash (income) expense, net;
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net income attributable to noncontrolling interest; and
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our interest in adjusted EBITDA from unconsolidated affiliates less income from unconsolidated affiliates.
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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:
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financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
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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;
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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
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the viability of acquisitions and capital expenditure projects.
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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:
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minus interest expense, excluding capitalized interest;
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minus maintenance capital expenditures;
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minus distributions to Series A Preferred Units,
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plus cash proceeds from asset sales, if any; and
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other adjustments.
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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 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.
CONTACT:
Investor Relations:
Lyndsay Hannah
Regency Energy Partners
Manager, Finance & Investor Relations
214-840-5477
ir@regencygas.com
Media Relations:
Vicki Granado
Granado Communications Group
214-599-8785
vicki@granadopr.com
Consolidated Balance Sheet
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Condensed Consolidated Balance Sheets
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($ in thousands)
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June 30, 2012
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December 31, 2011
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Assets
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Current assets
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$ | 184,934 | $ | 187,124 | ||
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Property, plant and equipment, net
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1,992,448 | 1,885,528 | ||||
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Investment in unconsolidated affiliates
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2,102,503 | 1,924,705 | ||||
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Long-term derivative assets
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1,872 | 474 | ||||
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Other assets, net
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34,770 | 39,353 | ||||
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Intangible assets, net
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726,246 | 740,883 | ||||
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Goodwill
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789,789 | 789,789 | ||||
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Total Assets
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$ | 5,832,562 | $ | 5,567,856 | ||
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Liabilities and Partners' Capital and Noncontrolling Interest
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Current liabilities
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$ | 202,676 | $ | 233,306 | ||
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Long-term derivative liabilities
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30,644 | 39,112 | ||||
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Other long-term liabilities
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5,721 | 6,071 | ||||
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Long-term debt
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1,780,558 | 1,687,147 | ||||
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Series A Preferred Units
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72,370 | 71,144 | ||||
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Partners' capital
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3,696,842 | 3,498,207 | ||||
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Noncontrolling interest
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43,751 | 32,869 | ||||
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Total Partners' Capital and Noncontrolling Interest
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3,740,593 | 3,531,076 | ||||
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Total Liabilities and Partners' Capital and Noncontrolling Interest
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$ | 5,832,562 | $ | 5,567,856 | ||
Consolidated Statements of Operations
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Condensed Consolidated Statements of Operations
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($ in thousands)
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Three Months Ended June 30,
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2012
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2011
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REVENUES
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$ | 311,976 | $ | 356,498 | ||
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OPERATING COSTS AND EXPENSES
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Cost of sales, including related party amounts
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186,815 | 259,475 | ||||
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Operation and maintenance
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38,992 | 33,996 | ||||
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General and administrative, including related party amounts
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16,476 | 17,551 | ||||
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Loss on asset sales, net
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1,548 | 153 | ||||
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Depreciation and amortization
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45,132 | 40,503 | ||||
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Total operating costs and expenses
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288,963 | 351,678 | ||||
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OPERATING INCOME
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23,013 | 4,820 | ||||
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Income from unconsolidated affiliates
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34,185 | 32,167 | ||||
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Interest expense, net
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(27,934 | ) | (24,689 | ) | ||
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Loss on debt refinancing, net
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(7,820 | ) | - | |||
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Other income and deductions, net
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7,921 | 2,641 | ||||
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INCOME BEFORE INCOME TAXES
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29,365 | 14,939 | ||||
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Income tax expense
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38 | 102 | ||||
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NET INCOME
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$ | 29,327 | $ | 14,837 | ||
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Net income attributable to noncontrolling interest
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(649 | ) | (293 | ) | ||
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NET INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP
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$ | 28,678 | $ | 14,544 | ||
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Limited partners' interest in net income
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$ | 24,053 | $ | 10,999 | ||
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Weighted average number of common units outstanding
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170,107,060 | 142,937,163 | ||||
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Basic income per common unit
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$ | 0.14 | $ | 0.08 | ||
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Diluted income per common unit
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$ | 0.10 | $ | 0.07 | ||
Segment Financial and Operating Data
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Three Months Ended June 30,
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2012
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2011
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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
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$ | 79,416 | $ | 50,495 | ||
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Adjusted segment margin
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65,463 | 52,642 | ||||
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Operating data:
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Throughput (MMbtu/d)
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1,380,000 | 1,063,000 | ||||
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NGL gross production (Bbls/d)
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37,200 | 28,000 | ||||
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Three Months Ended June 30,
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2012
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2011
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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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$ | 38,015 | $ | 36,973 | ||
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Operating data:
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Revenue generating horsepower, including intercompany revenue generating horsepower
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825,000 | 811,000 | ||||
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Three Months Ended June 30,
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2012
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2011
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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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$ | 7,241 | $ | 7,701 | ||
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Operating data:
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Revenue generating gallons per minute
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3,773 | 3,368 | ||||
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Three Months Ended June 30,
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2012
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2011
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($ in thousands)
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Corporate & Others
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Financial data:
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Segment margin
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$ | 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
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Three Months Ended June 30,
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2012
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2011
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($ in thousands)
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Haynesville Joint Venture
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Financial data:
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Segment margin
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$ | 46,311 | $ | 48,353 | ||
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Operating data:
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Throughput (MMbtu/d)
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903,344 | 1,528,333 | ||||
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Three Months Ended June 30,
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2012
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2011
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MEP Joint Venture
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Financial data:
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Segment margin
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$ | 61,090 | $ | 61,049 | ||
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Operating data:
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Throughput (MMbtu/d)
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1,418,206 | 1,197,520 | ||||
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Three Months Ended June 30, 2012
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From May 2, 2011 (initial Acquisition date) to June 30, 2011
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Lone Star Joint Venture
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Financial data:
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Segment margin
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$ | 72,250 | $ | 46,415 | ||
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Operating data:
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West Texas Pipeline Throughput (Bbls/d)
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133,429 | 128,127 | ||||
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NGL Fractionation Throughput (Bbls/d)
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20,575 | 14,806 | ||||
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We acquired a 30% interest in the Lone Star Joint Venture in May 2011.
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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 June 30,
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2012
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2011
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Haynesville Joint Venture
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($ in thousands)
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Net income
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$ | 26,222 | $ | 30,265 | ||
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Add:
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Operation and maintenance
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5,367 | 4,828 | ||||
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General and administrative
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5,156 | 4,345 | ||||
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Depreciation and amortization
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9,108 | 8,664 | ||||
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Interest expense, net
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460 | 251 | ||||
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Other income and deductions, net
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(2 | ) | - | |||
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Total Segment Margin
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$ | 46,311 | $ | 48,353 | ||
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Three Months Ended June 30,
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2012
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2011
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MEP Joint Venture
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($ in thousands)
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Net income
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$ | 20,377 | $ | 20,276 | ||
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Add:
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Operation and maintenance
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3,535 | 3,143 | ||||
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General and administrative
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6,922 | 7,310 | ||||
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Depreciation and amortization
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17,357 | 17,398 | ||||
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Interest expense, net
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12,899 | 12,922 | ||||
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Total Segment Margin
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$ | 61,090 | $ | 61,049 | ||
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Three Months Ended June 30,
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2012
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2011
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Lone Star Joint Venture
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($ in thousands)
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Net income
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$ | 41,220 | $ | 27,958 | ||
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Add:
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Operation and maintenance
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15,054 | 6,485 | ||||
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General and administrative
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4,496 | 4,649 | ||||
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Depreciation and amortization
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12,635 | 7,139 | ||||
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Tax expense
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402 | 192 | ||||
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Other income and deductions, net
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(1,557 | ) | (8 | ) | ||
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Total Segment Margin
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$ | 72,250 | $ | 46,415 | ||
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We acquired a 30% interest in Lone Star 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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2012
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2011
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($ in thousands)
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Net income
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$ | 29,327 | $ | 14,837 | ||
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Add (deduct):
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Interest expense, net
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27,934 | 24,689 | ||||
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Depreciation and amortization
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45,132 | 40,503 | ||||
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Income tax expense
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38 | 102 | ||||
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EBITDA (1)
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$ | 102,431 | $ | 80,131 | ||
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Add (deduct):
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Non-cash gain from commodity and embedded derivatives
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(21,862 | ) | (803 | ) | ||
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Unit-based compensation expenses
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1,005 | 875 | ||||
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Loss on asset sales, net
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1,548 | 153 | ||||
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Loss on debt refinancing, net
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7,820 | - | ||||
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Income from unconsolidated affiliates
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(34,185 | ) | (32,167 | ) | ||
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Partnership's interest in unconsolidated affiliates' adjusted EBITDA (2)(3)(4)(5)
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59,163 | 55,413 | ||||
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Other income, net
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(649 | ) | (146 | ) | ||
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Adjusted EBITDA
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$ | 115,271 | $ | 103,456 | ||
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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 and the Partnership's interest are calculated as follows:
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Net income Haynesville Joint Venture
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$ | 26,222 | $ | 30,265 | ||
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Add (deduct):
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Depreciation and amortization
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9,108 | 8,664 | ||||
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Interest expense, net
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460 | 251 | ||||
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Other expense, net
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- | - | ||||
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Haynesville Joint Venture's Adjusted EBITDA
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$ | 35,790 | $ | 39,180 | ||
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Ownership interest
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49.99 | % | 49.99 | % | ||
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Partnership's interest in Haynesville Joint Venture's Adjusted EBITDA
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$ | 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 | ||