Attached files
Exhibit 99.1
Regency Energy Partners Reports First Quarter 2012 Earnings Results
DALLAS, May 8, 2012 – Regency Energy Partners LP (NYSE: RGP), (“Regency” or the “Partnership”), announced today its financial results for the first quarter ended March 31, 2012.
Adjusted EBITDA increased 46% to $134 million in the first quarter of 2012, compared to $92 million in the first quarter of 2011. The increase in adjusted EBITDA was primarily due to an $18 million increase in gathering and processing segment margin; a $16 million one-time producer payment received in March 2012; and $15 million related to the Lone Star Joint Venture that was acquired in May 2011; partially offset by a $7 million increase in operations and maintenance expense. The increase in operations and maintenance expense is primarily due to increased volumes across the business segments.
In the first quarter of 2012, Regency generated $103 million in cash available for distribution, compared to $59 million in the first quarter of 2011. The increase in cash available for distribution was primarily related to the increase in adjusted EBITDA. Also in the first quarter of 2012, net income increased to $29 million, compared to $14 million in the first quarter of 2011.
“Regency generated solid first-quarter results, boosted by increased volumes in south and west Texas, and in north Louisiana, as well as the acquisition of the Lone Star assets,” said Mike Bradley, president and chief executive officer of Regency.
“Increased drilling associated with liquids-rich shale plays continues to support construction of our large-scale growth projects in these active regions, and is creating new opportunities for growth across all of our business segments,” continued Bradley. “These opportunities are expected to generate incremental fee-based margins as the majority of these projects come online in 2013.”
REVIEW OF SEGMENT PERFORMANCE
Adjusted total segment margin increased 17% to $117 million for the first quarter of 2012, compared to $99 million for first quarter of 2011.
Gathering and Processing – The Gathering and Processing segment 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.
Adjusted segment margin for the Gathering and Processing segment, which excludes non-cash hedging gains and losses, was $70 million for first quarter of 2012, compared to $52 million for the first 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 38% to 1.4 million MMbtu per day of natural gas for the first quarter of 2012, compared to 1.0 million MMbtu per day of natural gas for the first quarter of 2011. Processed NGLs increased to 38,000 barrels per day for the first quarter of 2012, compared to 28,000 barrels per day for the first quarter of 2011.
Joint Ventures – The Joint Ventures segment, formerly called the Transportation segment, consists of a 49.99% interest in the Haynesville Joint Venture, a 50% interest in the MEP Joint Venture, a 30% interest in the Lone Star Joint Venture and a 33.33% interest in the Ranch 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.
Regency reported income from unconsolidated affiliates of $32 million for the first quarter of 2012, compared to $24 million for the first quarter of 2011.
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 $10 million for the first quarter of 2012, compared to $14 million for the first quarter of 2011. Total throughput volumes for the Haynesville Joint Venture averaged 941,000 MMbtu per day of natural gas for the first quarter of 2012, compared to 1.5 million MMbtu per day for the first 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 increased to $11 million for the first quarter of 2012 from $10 million for the first quarter of 2011. Total throughput volumes for the MEP Joint Venture averaged 1.4 million MMbtu per day of natural gas for the first quarter of 2012 and for the first 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 first quarter of 2012, income from unconsolidated affiliates for the Lone Star Joint Venture was $11 million. For the first quarter of 2012, total throughput volumes for the West Texas Pipeline averaged 135,000 barrels per day and NGL Fractionation throughput volumes averaged 19,000 barrels per day.
The Ranch Joint Venture was created in December 2011 by Regency, Anadarko Pecos Midstream LLC and Chesapeake West Texas Processing, L.L.C., each owning one third of the joint venture interest. Upon completion of construction in 2012, the Ranch Joint Venture will process natural gas delivered from the NGLs-rich Bone Spring and Avalon shale formations in west Texas.
Contract Compression – The Contract Compression segment provides turn-key natural gas compression services for customer-specific systems.
Segment margin for the Contract Compression segment, excluding intercompany segment margin, was $35 million for the first quarter of 2012, compared to $35 million for the first quarter of 2011. As of March 31, 2012, the Contract Compression segment’s revenue generating horsepower was 761,000, compared to 762,000 as of March 31, 2011.
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 first quarter of 2012, compared to $7 million for the first quarter of 2011. As of March 31, 2012, revenue generating gallons per minute (“GPM”) was 3,370, compared to 3,268 as of March 31, 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 the first quarter of 2012, compared to $5 million for the first quarter of 2011.
ORGANIC GROWTH
In the three months ended March 31, 2012, Regency incurred $138 million of growth capital expenditures. Growth capital expenditures for the first quarter are primarily related to $71 million for the Joint Ventures segment, $39 million for the Gathering and Processing segment, $19 million for the Contract Compression segment and $9 million for the Contract Treating segment.
In the three months ended March 31, 2012, Regency incurred $7 million of maintenance capital expenditures.
In 2012, Regency expects to invest between $775 and $825 million in growth capital expenditures, of which $275 million is expected to be invested in the Gathering and Processing segment; between $350 and $400 million is expected to be invested in the Lone Star Joint Venture; $70 million is expected to be invested in the Contract Compression segment; $40 million is expected to be invested in the Contract Treating segment; $35 million is expected to be invested in Regency’s portion of growth capital expenditures for the new Ranch Joint Venture; and $5 million is expected to be invested in the Corporate and Others segment.
In addition, Regency expects to make $30 million in maintenance capital expenditures in 2012 including its proportionate share related to joint ventures.
CASH DISTRIBUTIONS
On April 25, 2012, Regency announced a cash distribution of $0.46 per outstanding common unit for the first quarter ended March 31, 2012. This distribution is equivalent to $1.84 per outstanding common unit on an annual basis and will be paid on May 14, 2012, to unitholders of record at the close of business on May 7, 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 first quarter ended March 31, 2012, on the same schedule as set forth above.
In the first quarter of 2012, Regency generated $103 million in cash available for distribution, representing 1.26 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 first-quarter 2012 results on Wednesday, May 9, 2012 at 10 a.m. Central Time (11 a.m. Eastern Time).
The dial-in number for the call is 1-866-831-6247 in the United States, or +1-617-213-8856 outside the United States, passcode 56916360. 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 19141683. 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.
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 or 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 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:
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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 |
Neither EBITDA nor adjusted EBITDA should be considered as 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. 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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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 calculate our Gathering and Processing and the 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 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. 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.
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 (NYSE: RGP) is a growth-oriented, midstream energy partnership engaged in the gathering and processing, contract compression, treating, 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, visit the Regency Energy Partners LP 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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Regency Energy Partners LP
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Condensed Consolidated Balance Sheets
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($ in thousands)
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March 31, 2012
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December 31, 2011
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Assets
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Current assets
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$ | 245,590 | $ | 187,124 | ||
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Property, plant and equipment, net
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1,904,952 | 1,885,528 | ||||
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Investment in unconsolidated affiliates
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2,007,414 | 1,924,705 | ||||
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Long-term derivative assets
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324 | 474 | ||||
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Other assets, net
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38,011 | 39,353 | ||||
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Intangible assets, net
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733,565 | 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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$ | 5,719,645 | $ | 5,567,856 | ||
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Liabilities and Partners' Capital and Noncontrolling Interest
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Current liabilities
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$ | 209,724 | $ | 233,306 | ||
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Long-term derivative liabilities
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38,887 | 39,112 | ||||
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Other long-term liabilities
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5,845 | 6,071 | ||||
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Long-term debt
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1,604,915 | 1,687,147 | ||||
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Series A Preferred Units
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72,196 | 71,144 | ||||
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Partners' capital
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3,749,677 | 3,498,207 | ||||
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Noncontrolling interest
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38,401 | 32,869 | ||||
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Total Partners' Capital and Noncontrolling Interest
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3,788,078 | 3,531,076 | ||||
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Total Liabilities and Partners' Capital and Noncontrolling Interest
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$ | 5,719,645 | $ | 5,567,856 | ||
Consolidated Income Statement
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Regency Energy Partners LP
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Condensed Consolidated Income Statements
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($ in thousands)
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Three Months Ended March 31,
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2012
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2011
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REVENUES
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$ | 357,899 | $ | 317,252 | ||
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OPERATING COSTS AND EXPENSES
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Cost of sales, including related party amounts
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239,653 | 216,261 | ||||
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Operation and maintenance
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40,981 | 33,672 | ||||
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General and administrative, including related party amounts
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15,695 | 18,997 | ||||
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Loss on asset sales, net
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36 | 28 | ||||
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Depreciation and amortization
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51,506 | 40,236 | ||||
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Total operating costs and expenses
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347,871 | 309,194 | ||||
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OPERATING INCOME
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10,028 | 8,058 | ||||
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Income from unconsolidated affiliates
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31,958 | 23,808 | ||||
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Interest expense, net
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(29,557 | ) | (20,007 | ) | ||
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Other income and deductions, net
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16,522 | 2,414 | ||||
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INCOME BEFORE INCOME TAXES
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28,951 | 14,273 | ||||
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Income tax expense (benefit)
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51 | (32 | ) | |||
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NET INCOME
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$ | 28,900 | $ | 14,305 | ||
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Net income attributable to noncontrolling interest
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(399 | ) | (231 | ) | ||
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NET INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP
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$ | 28,501 | $ | 14,074 | ||
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Amounts attributable to Series A Preferred Units
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2,997 | 1,993 | ||||
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General partners' interest, including IDRs
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2,488 | 1,292 | ||||
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Limited partners' interest in net income
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$ | 23,106 | $ | 10,789 | ||
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Limited partners' interest in net income
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$ | 23,016 | $ | 10,789 | ||
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Weighted average number of common units outstanding
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158,690,035 | 137,304,783 | ||||
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Basic income per common units
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$ | 0.15 | $ | 0.08 | ||
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Diluted income per common units
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$ | 0.14 | $ | 0.07 | ||
Segment Financial and Operating Data
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Three Months Ended March 31,
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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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$ | 71,335 | $ | 53,800 | ||
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Adjusted segment margin
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69,716 | 52,085 | ||||
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Operating data:
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Throughput (MMbtu/d)
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1,386,968 | 1,005,797 | ||||
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NGL gross production (Bbls/d)
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37,714 | 28,202 | ||||
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Three Months Ended March 31,
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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- Gross
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$ | 38,986 | $ | 41,440 | ||
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Less: Inter-segment elimination
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(4,111 | ) | (6,553 | ) | ||
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Segment margin, net of inter-segment elimination
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$ | 34,875 | $ | 34,887 | ||
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Operating data:
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Revenue generating horsepower
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760,914 | 761,953 | ||||
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Three Months Ended March 31,
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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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$ | 7,883 | $ | 7,251 | ||
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Operating data:
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Revenue generating gallons per minute
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3,370 | 3,268 | ||||
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Three Month Ended March 31,
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2012
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2011
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($ in thousands)
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Corporate & Others Segment
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Financial data:
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Segment margin
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$ | 4,648 | $ | 5,053 | ||
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 March 31,
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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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$ | 41,737 | $ | 47,472 | ||
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Operating data:
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Throughput (MMbtu/d)
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941,139 | 1,516,632 | ||||
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Three Months Ended March 31,
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2012
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2011
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($ in thousands)
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MEP Joint Venture
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Financial data:
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Segment margin
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$ | 62,278 | $ | 60,969 | ||
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Operating data:
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Throughput (MMbtu/d)
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1,429,103 | 1,389,751 | ||||
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Three Months Ended March 31,
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2012
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2011
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($ in thousands)
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Lone Star Joint Venture
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Financial data:
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Segment margin
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$ | 68,349 | N/A | |||
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Operating data:
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West Texas Pipeline Throughput (Bbls/d)
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134,616 | N/A | ||||
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NGL Fractionation Throughput (Bbls/d)
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19,245 | N/A | ||||
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N/A - 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 March 31,
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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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$ | 22,622 | $ | 30,156 | ||
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Add:
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Operation and maintenance
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5,457 | 4,719 | ||||
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General and administrative
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4,217 | 4,344 | ||||
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Depreciation and amortization
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9,094 | 8,082 | ||||
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Interest expense, net
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480 | 136 | ||||
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Other income and deductions, net
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(133 | ) | 35 | |||
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Total Segment Margin
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$ | 41,737 | $ | 47,472 | ||
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Three Months Ended March 31,
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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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$ | 21,494 | $ | 20,410 | ||
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Add:
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Operation and maintenance
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3,676 | 3,130 | ||||
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General and administrative
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6,850 | 7,197 | ||||
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Depreciation and amortization
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17,364 | 17,377 | ||||
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Interest expense, net
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12,894 | 12,855 | ||||
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Total Segment Margin
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$ | 62,278 | $ | 60,969 | ||
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Three Months Ended March 31,
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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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$ | 37,881 | N/A | |||
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Add:
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Operation and maintenance
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12,423 | N/A | ||||
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General and administrative
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5,102 | N/A | ||||
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Depreciation and amortization
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12,270 | N/A | ||||
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Tax expense
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436 | N/A | ||||
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Other income and deductions, net
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237 | N/A | ||||
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Total Segment Margin
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$ | 68,349 | N/A | |||
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N/A - 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 March 31,
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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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$ | 28,900 | $ | 14,305 | ||
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Add (deduct):
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Interest expense, net
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29,557 | 20,007 | ||||
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Depreciation and amortization
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51,506 | 40,236 | ||||
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Income tax expense (benefit)
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51 | (32 | ) | |||
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EBITDA (1)
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$ | 110,014 | $ | 74,516 | ||
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Add (deduct):
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Non-cash gain from commodity and embedded derivatives
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(2,115 | ) | (4,290 | ) | ||
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Unit-based compensation expenses
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1,289 | 921 | ||||
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loss on asset sales, net
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36 | 28 | ||||
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Income from unconsolidated affiliates
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(31,958 | ) | (23,808 | ) | ||
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Partnership's interest in unconsolidated affiliates'' adjusted EBITDA (2)(3)(4)
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57,218 | 44,459 | ||||
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Other income, net
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(434 | ) | (89 | ) | ||
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Adjusted EBITDA
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$ | 134,050 | $ | 91,737 | ||
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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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$ | 22,622 | $ | 30,156 | ||
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Add (deduct):
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Depreciation and amortization
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9,094 | 8,082 | ||||
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Interest expense, net
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480 | 136 | ||||
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Other expense, net
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- | 11 | ||||
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Haynesville Joint Venture's Adjusted EBITDA
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$ | 32,196 | $ | 38,385 | ||
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Net income MEP Joint Venture
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$ | 21,494 | $ | 20,410 | ||
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Add:
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Depreciation and amortization
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17,364 | 17,377 | ||||
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Interest expense, net
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12,894 | 12,855 | ||||
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MEP Joint Venture's Adjusted EBITDA
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$ | 51,752 | $ | 50,642 | ||
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(4) 100% of Lone Star Joint Venture's Adjusted EBITDA is calculated as follows:
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Net income Lone Star Joint Venture
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$ | 37,881 | N/A | |||
|
Add (deduct):
|
||||||
|
Depreciation and amortization
|
12,270 | N/A | ||||
|
Other expenses, net
|
673 | N/A | ||||
|
Lone Star Joint Venture's Adjusted EBITDA
|
$ | 50,824 | N/A | |||
|
N/A - We acquired a 30% interest in the Lone Star Joint Venture in May 2011.
|
||||||
Non-GAAP Adjusted Total Segment Margin to GAAP Net Income
|
Three Months Ended March 31,
|
||||||
|
2012
|
2011
|
|||||
|
($ in thousands)
|
||||||
|
Net income
|
$ | 28,900 | $ | 14,305 | ||
|
Add (Deduct):
|
||||||
|
Operation and maintenance
|
40,981 | 33,672 | ||||
|
General and administrative
|
15,695 | 18,997 | ||||
|
Loss on asset sales, net
|
36 | 28 | ||||
|
Depreciation and amortization
|
51,506 | 40,236 | ||||
|
Income from unconsolidated affiliates
|
(31,958 | ) | (23,808 | ) | ||
|
Interest expense, net
|
29,557 | 20,007 | ||||
|
Other income and deductions, net
|
(16,522 | ) | (2,414 | ) | ||
|
Income tax expense (benefit)
|
51 | (32 | ) | |||
|
Total Segment Margin
|
118,246 | 100,991 | ||||
|
Non-cash gain from commodity derivatives
|
(1,619 | ) | (1,715 | ) | ||
|
Adjusted Total Segment Margin
|
$ | 116,627 | $ | 99,276 | ||
|
Gathering & Processing Segment Margin
|
$ | 71,335 | $ | 53,800 | ||
|
Non-cash gain from commodity derivatives
|
(1,619 | ) | (1,715 | ) | ||
|
Adjusted Gathering and Processing Segment Margin
|
69,716 | 52,085 | ||||
|
Contract Compression Segment Margin
|
38,986 | 41,440 | ||||
|
Contract Treating Segment Margin
|
7,883 | 7,251 | ||||
|
Corporate & Others Segment Margin
|
4,648 | 5,053 | ||||
|
Inter-segment Elimination
|
(4,606 | ) | (6,553 | ) | ||
|
Adjusted Total Segment Margin
|
$ | 116,627 | $ | 99,276 | ||
Reconciliation of “cash available for distribution” to net cash flows provided by operating activities and to net income
|
Three Months Ended March 31,
|
||||||
|
2012
|
2011
|
|||||
|
($ in thousands)
|
||||||
|
Net cash flows provided by operating activities
|
$ | 56,067 | $ | 57,366 | ||
|
Add (deduct):
|
||||||
|
Depreciation and amortization, including debt issuance cost, bond premium and excess fair value of unconsolidated affiliates amortization
|
(54,491 | ) | (43,111 | ) | ||
|
Income from unconsolidated affiliates
|
33,420 | 25,270 | ||||
|
Derivative valuation change
|
2,588 | 4,686 | ||||
|
Loss on asset sales, net
|
(36 | ) | (28 | ) | ||
|
Unit-based compensation expenses
|
(1,289 | ) | (921 | ) | ||
|
Cash flow changes in current assets and liabilities:
|
||||||
|
Trade accounts receivables, accrued revenues, and related party receivables
|
(7,348 | ) | (7,300 | ) | ||
|
Other current assets
|
723 | 2,096 | ||||
|
Trade accounts payable, accrued cost of gas and liquids, related party payables and deferred revenues
|
33,546 | 12,145 | ||||
|
Other current liabilities
|
(5,384 | ) | (10,613 | ) | ||
|
Distributions received from unconsolidated affiliates
|
(29,012 | ) | (25,270 | ) | ||
|
Other assets and liabilities
|
116 | (15 | ) | |||
|
Net Income
|
$ | 28,900 | $ | 14,305 | ||
|
Add:
|
||||||
|
Interest expense, net
|
29,557 | 20,007 | ||||
|
Depreciation and amortization
|
51,506 | 40,236 | ||||
|
Income tax expense (benefit)
|
51 | (32 | ) | |||
|
EBITDA
|
$ | 110,014 | $ | 74,516 | ||
|
Add (deduct):
|
||||||
|
Non-cash gain from commodity and embedded derivatives
|
(2,115 | ) | (4,290 | ) | ||
|
Unit-based compensation expenses
|
1,289 | 921 | ||||
|
Loss on asset sales, net
|
36 | 28 | ||||
|
Income from unconsolidated affiliates
|
(31,958 | ) | (23,808 | ) | ||
|
Partnership's interest in unconsolidated affiliates' adjusted EBITDA
|
57,218 | 44,459 | ||||
|
Other income, net
|
(434 | ) | (89 | ) | ||
|
Adjusted EBITDA
|
$ | 134,050 | $ | 91,737 | ||
|
Add (deduct):
|
||||||
|
Interest expense, excluding capitalized interest
|
(35,232 | ) | (19,446 | ) | ||
|
Maintenance capital expenditures
|
(7,181 | ) | (3,433 | ) | ||
|
Distribution to Series A Preferred Units
|
(1,945 | ) | (1,945 | ) | ||
|
Other adjustments
|
13,348 | (7,962 | ) | |||
|
Cash available for distribution
|
$ | 103,040 | $ | 58,951 | ||