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| 8-K - FORM 8-K - EAGLE ROCK ENERGY PARTNERS L P | form8-kcoverpage0911.htm |
EXHIBIT 99.1
November 2, 2011
Eagle Rock Reports Third Quarter 2011 Financial Results
HOUSTON - Eagle Rock Energy Partners, L.P. (“Eagle Rock” or the “Partnership”) (NASDAQ: EROC) today announced its unaudited financial results for the three months and nine months ended September 30, 2011. Key financial results for the third quarter 2011 included the following:
• | Reported Adjusted EBITDA of $62.2 million, up 15% from the $54.0 million reported in second quarter 2011. |
• | Reported Distributable Cash Flow of $36.1 million, an increase of approximately 17% as compared to the $31.0 million reported in second quarter 2011. |
• | Announced a quarterly distribution with respect to the third quarter of 2011 of $0.20 per common unit, an approximate 7% increase from the $0.1875 per common unit paid for the second quarter of 2011. |
• | Reported Net Income of $97.4 million, up 77% as compared to the $55.1 million reported for the second quarter of 2011; the increase was driven primarily by unrealized mark-to-market gains on the Partnership's commodity derivative portfolio. |
Other notable activities of the Partnership during the third quarter of 2011 included the following:
• | Announced the intention to install a recently acquired 60 MMcf/d high efficiency cryogenic processing facility (the Woodall Plant) in Hemphill County, Texas in the first quarter of 2012 to service production from the Granite Wash play. |
• | Secured a substantial increase in committed natural gas liquids transportation and fractionation capacity out of the Texas Panhandle to support additional volumes from the Phoenix-Arrington Ranch Plant expansion and the new Woodall Plant. |
• | Received proceeds of $32.3 million from the exercise of 5.4 million warrants on August 15, 2011. The Partnership used the proceeds to repay outstanding borrowings under its revolving credit facility. |
“We are pleased with our third quarter results,” said Joseph A. Mills, Eagle Rock's Chairman and Chief Executive Officer. “Both of our lines of business performed well during the third quarter despite the volatility in commodity prices. In our Upstream Business, we remain focused on developing our extensive inventory of drilling opportunities in the Golden Trend and the Cana Shale. In our Midstream Business, we continue to demonstrate our commitment to our producer customers by expanding our processing capacity to meet their growing needs. We have completed the Phoenix-Arrington Ranch Plant expansion and are scheduled to have our Woodall and Wheeler Plants online in the Granite Wash play of the Texas Panhandle in 2012.”
Recent Announcements
On October 31, 2011, the Partnership announced its intention to install a 125 MMcf/d high efficiency cryogenic processing plant in Wheeler County, Texas, in the heart of the prolific Granite Wash play. The Partnership expects the installation of the new processing plant (to be named the “Wheeler Plant”) and the construction of the associated infrastructure to be
completed early in the fourth quarter of 2012. Eagle Rock also announced that construction of the 30 MMcf/d expansion of its Phoenix-Arrington Ranch Plant in Hemphill County, Texas is complete. Following the installation of the Woodall and Wheeler plants in 2012, the Partnership will have over 300 MMcf/d of high efficiency processing capacity serving its producer customers in the Granite Wash play of the Texas Panhandle.
On October 4, 2011, the Partnership announced a 6% increase in the upstream component of the borrowing base under its senior secured credit facility, from $353 million to $375 million. Total commitments under the credit facility remained unchanged at $675 million.
Third-Quarter 2011 Financial and Operating Results
Eagle Rock analyzes and manages its operations under six segments: four segments in its Midstream Business - the Texas Panhandle, East Texas/Louisiana, South Texas and Gulf of Mexico Segments - and the Upstream and Corporate and Other Segments. The Corporate and Other Segment includes the Partnership's general and administrative expenses, commodity risk management portfolio, and other corporate activities. The following discussion of Eagle Rock's operating income by business segment compares the Partnership's financial results in the third quarter of 2011 to those of the second quarter of 2011. The Partnership believes comparing these periods is more illustrative of current operating trends than comparing the current quarter to results achieved in the third quarter of 2010. Please refer to the financial tables at the end of this release for further detailed information. In comparing the Partnership's third quarter 2011 financial results against prior periods, including those presented for comparison only in the financial tables at the end of this release, note that all historical financial results for the Partnership's Minerals Business, which was sold during the second quarter of 2010, and a small, non-core gathering system accounted for in the Partnership's South Texas Segment, which was sold in the second quarter of 2011, have been removed from the operating financial results and are reflected in Discontinued Operations.
Midstream Business - Operating income from continuing operations for the Midstream Business, excluding the impact of impairments, in the third quarter of 2011 decreased by approximately $3.0 million compared to the second quarter of 2011. The primary reason for this decrease was lower average realized commodity prices and a 3% decrease in gas gathering volumes as compared to the second quarter of 2011. These factors more than offset the positive impact of an 11% increase in combined natural gas liquid (“NGL”) and condensate equity volumes in the third quarter.
In the Texas Panhandle, gathered volumes were up approximately 6%, with combined equity NGL and condensate volumes up approximately 16%, as compared to the second quarter of 2011. Increased gathering volumes are primarily a result of an increase in drilling activity in the Partnership's East Panhandle system serving the Granite Wash play. Combined equity NGL and condensate volumes were higher in the third quarter due to curtailed customer production and reduced NGL recoveries in the second quarter resulting from damage at the Partnership's Cargray plant due to the severe weather in the first quarter. The Cargray plant was repaired in late June and is now performing consistent with its prior operating performance.
In East Texas/Louisiana, gathered volumes were down approximately 10% and combined equity NGL and condensate volumes were down approximately 7%, compared to the second quarter of 2011. The decrease in gathered volumes and combined equity NGL and condensate volumes were due to natural declines in the production of the existing wells and delays due to certain
mechanical and completion difficulties experienced by the Partnership's producer customers during the quarter.
In South Texas, gathered volumes were down approximately 2 MMcf/d due to natural production declines. Combined equity NGL and condensate volumes remained minimal in the third quarter due to the low liquid content in the natural gas gathered by the Partnership's South Texas gathering systems.
In the Gulf of Mexico, gathered volumes were down approximately 2% and equity NGL volumes were down approximately 9%, as compared to the second quarter of 2011. Gathered volumes and equity NGL volumes were down as a result of the Partnership's ownership interest in the Yscloskey Plant decreasing (by virtue of an annual volume-based ownership adjustment mechanism) from approximately 11.5% to approximately 10.5%, effective September 1, 2011. In addition, the Yscloskey Plant was down for approximately two weeks due to scheduled maintenance during the month of September.
Upstream Business - Operating income for Eagle Rock's Upstream Business in the third quarter of 2011, excluding the impact of impairments, increased by $1.6 million, or approximately 6%, compared to the second quarter of 2011. The increase was primarily attributable to the full quarter of production from the Mid-Continent assets which Eagle Rock acquired on May 3, 2011. Production volumes in the Upstream Business averaged 81.1 MMcfe/d during the quarter, an increase of approximately 24% over the second quarter of 2011. In addition to the increase in production volumes, the Partnership also benefited from higher realized natural gas and sulfur prices, as well as lower unit operating costs, as compared to the second quarter of 2011. These positive factors were partially offset by an 8% and 10% decrease in realized oil and NGL prices, respectively.
In addition, the Partnership completed a nine day turnaround at its Big Escambia Creek facility in September. The total impact lowered operating income during the third quarter by approximately $3 million.
Corporate Segment - The Partnership recorded a realized commodity derivative settlement net loss of $2.7 million in the third quarter of 2011, as compared to a realized net loss of $8.8 million in the second quarter of 2011. The net loss was lower in the third quarter primarily due to lower crude oil, condensate and NGL settlement prices during the third quarter of 2011, as compared to the second quarter of 2011.
Total revenue for the third quarter of 2011, including the impact of Eagle Rock's realized and unrealized commodity derivative gains and losses, was $375.8 million, up 21% compared with the $311.7 million reported for the second quarter of 2011. The increase in revenue was primarily due to higher unrealized gains on commodity derivatives compared to the second quarter of 2011. Eagle Rock recorded an unrealized gain on commodity derivatives of $97.0 million in the third quarter 2011, as compared to an unrealized gain on commodity derivatives of $43.2 million in the second quarter 2011. The unrealized gain on commodity derivatives is a non-cash, mark-to-market amount which includes the amortization of commodity hedging costs.
Adjusted EBITDA was $62.2 million and Distributable Cash Flow was $36.1 million for the third quarter of 2011. The Partnership's distribution of $0.20 per common unit with respect to the third quarter of 2011 will be paid on Monday, November 14, 2011 to the Partnership's common unitholders of record as of the close of business on Monday, November 7, 2011, excluding
unitholders of record with respect to 1,257,565 restricted common units granted on November 1, 2011 pursuant to the Partnership's Long Term Incentive Plan.
Update Regarding Distribution Policy
As previously stated, management anticipates recommending to the Board of Directors further increases in the distribution in 2011 and 2012, with the expectation and objective of reaching an annualized distribution rate of $1.00 per unit by the end of 2012.
Management's intentions around future distribution recommendations are subject to change, however, should factors affecting the general business climate, market conditions, commodity prices, the Partnership's specific operations, performance of the Partnership's underlying assets, applicable regulatory mandates, or the Partnership's ability to consummate accretive growth projects differ from current expectations.
Actual future distributions will be determined, declared and paid at the discretion of the Board of
Directors.
Capitalization and Liquidity Update
Total debt outstanding as of September 30, 2011 was $741 million. As of September 30, 2011 the debt outstanding under the Partnership's senior unsecured notes was $297.9 million net of an unamortized debt discount of $2.1 million. Total debt outstanding as of September 30, 2011 under the Partnership's senior secured credit facility was $443 million, a decrease of $5.0 million from the amount outstanding at the end of the second quarter of 2011. The Partnership's overall liquidity position in the quarter benefited from $32.3 million of proceeds received from the exercise of 5,390,384 warrants on August 15, 2011.
The Partnership is in compliance with its financial covenants and has no maturities under its credit facility until June 2016. Availability under the credit facility is subject to a borrowing base comprised of two components: the upstream component and the midstream component. As of September 30, 2011, the Partnership had approximately $228 million of availability under the credit facility, based on its outstanding commitments.
Capital Expenditures
In its 2011 capital budget, which excludes capital expenditures that were part of satisfying the purchase price for the Partnership's Mid-Continent assets acquired May 3, 2011 (but which includes capital expenditures on such assets after May 3, 2011), the Partnership estimates it will spend a total of approximately $196 million in 2011 on capital expenditures, including approximately $40 million related to the installation of the Woodall Plant.
The Partnership expects its capital expenditures to increase in response to environmental compliance associated with sulfur dioxide (SO2) emissions. The Partnership has certain permit obligations to lower its SO2 emissions at its Alabama plant operations. Additionally, in mid-2010, the Environmental Protection Agency (“EPA”) enacted new National Ambient Air Quality Standards (“2010 NAAQS”) which substantially lowered the emissions limits for SO2 and mandated timelines for compliance. In order to fulfill its permit obligations, comply with the new 2010 NAAQS requirements and replace and upgrade certain aging assets in the Partnership's
Alabama facilities, the Partnership expects to incur approximately $50 million over the next several years to enhance its SO2 recovery capabilities at its Alabama operations. The expected facility upgrades to Eagle Rock's Alabama operations should not only increase the marketable sulfur recovered from the inlet gas stream, but also are anticipated to reduce plant fuel consumption, improve the plant's operating reliability and extend the plant's operating life. Management does not anticipate, however, that the required spending will generate returns consistent with the Partnership's internal rate of return thresholds for discretionary capital investment.
Management expects a substantial percentage of the total capital invested to achieve the SO2 emissions standard at the Partnership's Alabama operations will be classified as maintenance capital, and therefore will reduce the amount of distributable cash flow Eagle Rock recognizes in the periods in which the capital is spent. Management, based on its current expectations, does not believe the additional maintenance capital will impact its objective of recommending a distribution at an annualized rate of $1.00 per common unit by the end of 2012; it will, however, reduce the Partnership's distribution coverage ratio in the periods in which the capital is spent.
Hedging Update
On October 17 and 20, 2011, the Partnership entered into the hedges outlined below to replace a portion of its 2012 “proxy hedges” (where one commodity is hedged with a closely-correlated commodity) with direct NGL product hedges.
NYMEX WTI Crude to Direct NGL Product Hedges:
Product / (Type) | Quantity | Price | Term | |
WTI Crude (Swap Unwind) | (7,800) Bbls/month | $97.42 | Cal. 2012 | |
WTI Crude (Remaining Swap) | 12,200 Bbls/month | $103.31 | Cal. 2012 | |
Note: Proceeds from unwind rolled into strike price on remaining volumes.
Product / (Type) | Quantity | Price | Term | |
OPIS Propane (Swap) | 961,800 Gallons/month | $1.3425 | Cal. 2012 | |
OPIS IsoButane (Swap) | 310,800 Gallons/month | $1.7700 | Cal. 2012 | |
OPIS Normal Butane (Swap) | 453,600 Gallons/month | $1.6700 | Cal. 2012 | |
OPIS Natural Gasoline (Swap) | 252,000 Gallons/month | $2.1900 | Cal. 2012 | |
NYMEX Henry Hub Natural Gas to Direct Ethane Hedges:
Product / (Type) | Quantity | Price | Term | |
Natural Gas (Swap Offset) | (260,000) MMbtu/month | $3.965 | Jan-Jun 2012 | |
OPIS Ethane (Swap) | 3,150,000 Gallons/month | $0.7300 | Jan-Jun 2012 | |
Note: Natural gas transaction offsets an existing hedge with the same counterparty.
As a result of the hedges outlined above:
• | Approximately 78% of Eagle Rock's expected 2012 heavy NGL (C3+) exposure is hedged directly by specific product. |
• | Approximately 35% of Eagle Rock's expected 2012 ethane exposure is hedged directly. |
Note the preceding hedge discussion excludes the derivative activity associated with the Partnership's natural gas marketing and trading subsidiary.
For more details regarding these hedging transactions and the Partnership's overall hedging portfolio, please visit Eagle Rock's website at www.eaglerockenergy.com under the Investor Relations tab, Presentations, Commodity Hedging Update.
Conference Call
Eagle Rock will hold a conference call to discuss its third quarter 2011 financial and operating results on November 3, 2011 at 2:00 p.m. Eastern Time (1:00 p.m. Central Time).
Interested parties may listen live over the internet or via telephone. To listen live over the internet, log on to the Partnership's web site at www.eaglerockenergy.com. To participate by telephone, the call-in number is 888-680-0860, confirmation code 57796110. Investors are advised to dial into the call at least 15 minutes prior to the call to register. Participants may pre-register for the call by using the following link: https://www.theconferencingservice.com/prereg/key.process?key=PV3689JCR. Interested parties can also view important information about the Partnership's conference call by following this link. Pre-registering is not mandatory but is recommended as it will provide you immediate entry to the call and will facilitate the timely start of the call. Pre-registration only takes a few minutes and you may pre-register at any time, including up to and after the start of the call. An audio replay of the conference call will also be available for thirty days by dialing 888-286-8010, confirmation code 88780783. In addition, a replay of the audio webcast will be available by accessing the Partnership's website after the call is concluded.
About the Partnership
The Partnership is a growth-oriented master limited partnership engaged in two businesses: a) midstream, which includes (i) gathering, compressing, treating, processing and transporting natural gas; (ii) fractionating and transporting natural gas liquids; and (iii) marketing and trading natural gas, and marketing condensate and NGLs; and b) upstream, which includes acquiring, exploiting, developing, and producing hydrocarbons in oil and natural gas properties. Its corporate office is located in Houston, Texas.
References to “Board of Directors” are to the board of directors of Eagle Rock Energy G&P, LLC, the general partner of Eagle Rock Energy GP, L.P., the general partner of Eagle Rock Energy Partners, L.P.
Contacts:
Eagle Rock Energy Partners, L.P.
Jeff Wood, 281-408-1203
Senior Vice President and Chief Financial Officer
Adam Altsuler, 281-408-1350
Director, Corporate Finance and Investor Relations
Use of Non-GAAP Financial Measures
This news release and the accompanying schedules include the non-generally accepted accounting principles, or non-GAAP, financial measures of Adjusted EBITDA and Distributable Cash Flow. The accompanying non-GAAP financial measures schedules (after the financial 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, or GAAP. Non-GAAP financial measures should not be considered alternatives to GAAP measures such as net income (loss), operating income (loss), cash flows from operating activities or any other GAAP measure of liquidity or financial performance.
Eagle Rock defines Adjusted EBITDA as net income (loss) plus or (minus) income tax provision (benefit); interest-net, including realized interest rate risk management instruments and other expense; depreciation, depletion and amortization expense; impairment expense; other operating expense, non-recurring; other non-cash operating and general and administrative expenses, including non-cash compensation related to our equity-based compensation program; unrealized (gains) losses on commodity and interest rate risk management related instruments; (gains) losses on discontinued operations and other (income) expense.
Eagle Rock uses Adjusted EBITDA as a measure of its core profitability to assess the financial performance of its assets. Adjusted EBITDA also is used as a supplemental financial measure by external users of Eagle Rock's financial statements such as investors, commercial banks and research analysts. For example, the Partnership's lenders under its revolving credit facility use a variant of its Adjusted EBITDA in a compliance covenant designed to measure the viability of Eagle Rock and its ability to perform under the terms of the revolving credit facility; Eagle Rock, therefore, uses Adjusted EBITDA to measure its compliance with its revolving credit facility. Eagle Rock believes that investors benefit from having access to the same financial measures that its management uses in evaluating performance. Adjusted EBITDA is useful in determining Eagle Rock's ability to sustain or increase distributions. By excluding unrealized derivative gains (losses), a non-cash, mark-to-market benefit (charge) which represents the change in fair market value of the Partnership's executed derivative instruments and is independent of its assets' performance or cash flow generating ability, Eagle Rock believes Adjusted EBITDA reflects more accurately the Partnership's ability to generate cash sufficient to pay interest costs, support its level of indebtedness, make cash distributions to its unitholders and finance its maintenance capital expenditures. Eagle Rock further believes that Adjusted EBITDA also portrays more accurately the underlying performance of its operating assets by isolating the performance of its operating assets from the impact of an unrealized, non-cash measure
designed to portray the fluctuating inherent value of a financial asset. Similarly, by excluding the impact of non-recurring discontinued operations, Adjusted EBITDA provides users of the Partnership's financial statements a more accurate picture of its current assets' cash generation ability, independently from that of assets which are no longer a part of its operations.
Eagle Rock's Adjusted EBITDA definition may not be comparable to Adjusted EBITDA or similarly titled measures of other entities, as other entities may not calculate Adjusted EBITDA in the same manner as Eagle Rock. For example, the Partnership includes in Adjusted EBITDA the actual settlement revenue created from its commodity hedges by virtue of transactions undertaken by it to reset commodity hedges to prices higher than those reflected in the forward curve at the time of the transaction or to purchase puts or other similar floors despite the fact that the Partnership excludes from Adjusted EBITDA any charge for amortization of the cost of such commodity hedge reset transactions or puts. Eagle Rock has reconciled Adjusted EBITDA to the GAAP financial measure of net income (loss) at the end of this release.
Distributable Cash Flow is defined as Adjusted EBITDA minus: (i) maintenance capital expenditures; (ii) cash interest expense; (iii) cash income taxes; and (iv) the addition of losses or subtraction of gains relating to other miscellaneous non-cash amounts affecting net income (loss) for the period. Maintenance capital expenditures represent capital expenditures made to replace partially or fully depreciated assets; to meet regulatory requirements; to maintain the existing operating capacity of the Partnership's gathering, processing and treating assets or to maintain the Partnership's natural gas, NGL, crude or sulfur production.
Distributable Cash Flow is a significant performance metric used by senior management to compare cash flows generated by the Partnership (excluding growth capital expenditures and prior to the establishment of any retained cash reserves by the Board of Directors) to the cash distributions expected to be paid to unitholders. Using this metric, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. This financial measure also is important to investors as an indicator of whether the Partnership is generating cash flow at a level that can sustain or support an increase in quarterly distribution rates. Actual distributions are set by the Board of Directors.
The GAAP measure most directly comparable to Distributable Cash Flow is net income (loss). Eagle Rock's Distributable Cash Flow definition may not be comparable to Distributable Cash Flow or similarly titled measures of other entities, as other entities may not calculate Distributable Cash Flow (and Adjusted EBITDA, on which it builds) in the same manner as Eagle Rock. See the example given above for Adjusted EBITDA related to amortization of costs of commodity hedges, including costs of hedge reset transactions. Eagle Rock has reconciled Distributable Cash Flow to the GAAP financial measure of net income/(loss) at the end of this release.
This news release may include “forward-looking statements.” All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Partnership expects, believes or anticipates will or may occur in the future are forward-looking statements and speak only as of the date on which such statement is made. These statements are based on certain assumptions made by the Partnership based on its experience and perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate under the circumstances. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are
beyond the control of the Partnership. These include, but are not limited to, risks related to volatility of commodity prices; market demand for natural gas and natural gas liquids; the effectiveness of the Partnership's hedging activities; the Partnership's ability to retain key customers; the Partnership's ability to continue to obtain new sources of natural gas supply; the availability of local, intrastate and interstate transportation systems and other facilities to transport natural gas and natural gas liquids; competition in the oil and gas industry; the Partnership's ability to obtain credit and access the capital markets; general economic conditions; and the effects of government regulations and policies. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, the Partnership's actual results and plans could differ materially from those implied or expressed by any forward-looking statements. The Partnership assumes no obligation to update any forward-looking statement as of any future date. For a detailed list of the Partnership's risk factors, please consult the Partnership's Form 10-K, filed with the Securities and Exchange Commission (“SEC”) for the year ended December 31, 2010 and the Partnership's Forms 10-Q filed with the SEC for subsequent quarters, as well as any other public filings and press releases.
Eagle Rock Energy Partners, L.P.
Consolidated Statement of Operations
($ in thousands)
(unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended June 30, 2011 | |||||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||||||
REVENUE: | |||||||||||||||||||
Natural gas, natural gas liquids, oil, condensate and sulfur sales | $ | 269,790 | $ | 159,303 | $ | 738,162 | $ | 516,276 | $ | 265,317 | |||||||||
Gathering, compression, processing and treating fees | 11,567 | 12,093 | 37,116 | 40,806 | 12,304 | ||||||||||||||
Unrealized commodity derivative gains (losses) | 97,011 | (17,044 | ) | 86,164 | 37,839 | 43,151 | |||||||||||||
Realized commodity derivative losses | (2,698 | ) | (1,535 | ) | (17,958 | ) | (10,031 | ) | (8,813 | ) | |||||||||
Other revenue | 141 | 100 | 1,406 | (115 | ) | (244 | ) | ||||||||||||
Total revenue | 375,811 | 152,917 | 844,890 | 584,775 | 311,715 | ||||||||||||||
COSTS AND EXPENSES: | |||||||||||||||||||
Cost of natural gas and natural gas liquids | 171,964 | 106,682 | 491,957 | 353,227 | 172,674 | ||||||||||||||
Operations and maintenance | 24,897 | 18,714 | 66,323 | 57,511 | 21,951 | ||||||||||||||
Taxes other than income | 4,556 | 2,609 | 13,061 | 8,949 | 5,189 | ||||||||||||||
General and administrative | 16,068 | 10,674 | 43,746 | 36,491 | 15,902 | ||||||||||||||
Other operating income | — | — | (2,893 | ) | — | (2,893 | ) | ||||||||||||
Impairment | 9,870 | 3,432 | 14,754 | 6,562 | 4,560 | ||||||||||||||
Depreciation, depletion and amortization | 35,040 | 25,892 | 90,314 | 80,805 | 31,576 | ||||||||||||||
Total costs and expenses | 262,395 | 168,003 | 717,262 | 543,545 | 248,959 | ||||||||||||||
OPERATING INCOME (LOSS) | 113,416 | (15,086 | ) | 127,628 | 41,230 | 62,756 | |||||||||||||
OTHER INCOME (EXPENSE): | |||||||||||||||||||
Interest income | 7 | 9 | 13 | 184 | 3 | ||||||||||||||
Interest expense, net | (10,057 | ) | (3,258 | ) | (19,592 | ) | (12,056 | ) | (6,311 | ) | |||||||||
Realized interest rate derivative losses | (3,713 | ) | (5,170 | ) | (13,374 | ) | (15,012 | ) | (4,434 | ) | |||||||||
Unrealized interest rate derivative (losses) gains | (3,165 | ) | (3,112 | ) | 2,191 | (12,288 | ) | 2,791 | |||||||||||
Other (expense) income | (3 | ) | (30 | ) | (167 | ) | 48 | (114 | ) | ||||||||||
Total other income (expense) | (16,931 | ) | (11,561 | ) | (30,929 | ) | (39,124 | ) | (8,065 | ) | |||||||||
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | 96,485 | (26,647 | ) | 96,699 | 2,106 | 54,691 | |||||||||||||
INCOME TAX BENEFIT | (1,077 | ) | (1,244 | ) | (1,810 | ) | (970 | ) | (691 | ) | |||||||||
INCOME (LOSS) FROM CONTINUING OPERATIONS | 97,562 | (25,403 | ) | 98,509 | 3,076 | 55,382 | |||||||||||||
DISCONTINUED OPERATIONS, NET OF TAX | (197 | ) | 166 | 210 | 43,811 | (311 | ) | ||||||||||||
NET INCOME (LOSS) | $ | 97,365 | $ | (25,237 | ) | $ | 98,719 | $ | 46,887 | $ | 55,071 | ||||||||
Eagle Rock Energy Partners, L.P.
Consolidated Balance Sheets
($ in thousands)
(unaudited)
September 30, 2011 | December 31, 2010 | ||||||
ASSETS | |||||||
CURRENT ASSETS: | |||||||
Cash and cash equivalents | $ | 17,662 | $ | 4,049 | |||
Accounts receivable | 93,434 | 75,695 | |||||
Risk management assets | 18,577 | — | |||||
Prepayments and other current assets | 5,943 | 2,498 | |||||
Assets held for sale | — | 8,615 | |||||
Total current assets | 135,616 | 90,857 | |||||
PROPERTY, PLANT AND EQUIPMENT - Net | 1,716,875 | 1,137,239 | |||||
INTANGIBLE ASSETS - Net | 111,264 | 113,634 | |||||
DEFERRED TAX ASSET | 1,765 | 1,969 | |||||
RISK MANAGEMENT ASSETS | 38,568 | 1,075 | |||||
OTHER ASSETS | 21,043 | 4,623 | |||||
TOTAL ASSETS | $ | 2,025,131 | $ | 1,349,397 | |||
LIABILITIES AND MEMBERS' EQUITY | |||||||
CURRENT LIABILITIES: | |||||||
Accounts payable | $ | 135,311 | $ | 91,886 | |||
Due to affiliate | 41 | 56 | |||||
Accrued liabilities | 21,843 | 10,940 | |||||
Taxes payable | 707 | 1,102 | |||||
Risk management liabilities | 4,073 | 39,350 | |||||
Liabilities held for sale | — | 1,705 | |||||
Total current liabilities | 161,975 | 145,039 | |||||
LONG-TERM DEBT | 740,904 | 530,000 | |||||
ASSET RETIREMENT OBLIGATIONS | 30,303 | 24,711 | |||||
DEFERRED TAX LIABILITY | 38,444 | 38,662 | |||||
RISK MANAGEMENT LIABILITIES | 4,594 | 31,005 | |||||
OTHER LONG TERM LIABILITIES | 2,473 | 867 | |||||
MEMBERS' EQUITY | 1,046,438 | 579,113 | |||||
TOTAL LIABILITIES AND MEMBERS' EQUITY | $ | 2,025,131 | $ | 1,349,397 | |||
Eagle Rock Energy Partners, L.P.
Segment Summary
Operating Income
($ in thousands)
(unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended June 30, 2011 | |||||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||||||
Midstream | |||||||||||||||||||
Revenues: | |||||||||||||||||||
Natural gas, natural gas liquids, oil and condensate sales (1) | $ | 223,594 | $ | 136,665 | $ | 634,940 | $ | 446,477 | $ | 225,749 | |||||||||
Gathering and treating services | 11,567 | 12,093 | 37,116 | 40,806 | 12,304 | ||||||||||||||
Total revenue | 235,161 | 148,758 | 672,056 | 487,283 | 238,053 | ||||||||||||||
Cost of natural gas, natural gas liquids, oil and condensate (2) | 186,522 | 106,682 | 527,507 | 353,227 | 186,577 | ||||||||||||||
Operating costs and expenses: | |||||||||||||||||||
Operations and maintenance | 16,716 | 14,401 | 48,081 | 41,507 | 16,580 | ||||||||||||||
Impairment | — | — | 4,560 | 3,130 | 4,560 | ||||||||||||||
Depreciation, depletion and amortization | 16,093 | 18,683 | 48,250 | 55,138 | 16,076 | ||||||||||||||
Total operating costs and expenses | 32,809 | 33,084 | 100,891 | 99,775 | 37,216 | ||||||||||||||
Operating income from continuing operations | 15,830 | 8,992 | 43,658 | 34,281 | 14,260 | ||||||||||||||
Discontinued Operations (3) | (197 | ) | (15 | ) | (194 | ) | 363 | (449 | ) | ||||||||||
Operating income | $ | 15,633 | $ | 8,977 | $ | 43,464 | $ | 34,644 | $ | 13,811 | |||||||||
Upstream | |||||||||||||||||||
Revenue | |||||||||||||||||||
Oil and condensate sales (4) | $ | 24,720 | $ | 14,292 | $ | 63,774 | $ | 37,654 | $ | 24,193 | |||||||||
Natural gas sales (5) | 17,417 | 2,617 | 32,697 | 11,982 | 11,886 | ||||||||||||||
Natural gas liquids sales (6) | 12,186 | 4,231 | 29,678 | 15,485 | 11,826 | ||||||||||||||
Sulfur sales (7) | 5,057 | 1,498 | 12,781 | 4,678 | 4,684 | ||||||||||||||
Other | 141 | 100 | 1,406 | (115 | ) | (244 | ) | ||||||||||||
Total revenue | 59,521 | 22,738 | 140,336 | 69,684 | 52,345 | ||||||||||||||
Operating costs and expenses: | |||||||||||||||||||
Operations and maintenance (3) | 12,737 | 6,922 | 31,369 | 24,224 | 10,584 | ||||||||||||||
Sulfur disposal costs | — | — | — | 729 | — | ||||||||||||||
Impairment | 9,870 | 3,432 | 10,194 | 3,432 | — | ||||||||||||||
Depreciation, depletion and amortization | 18,636 | 6,810 | 41,046 | 24,433 | 15,180 | ||||||||||||||
Total operating costs and expenses | 41,243 | 17,164 | 82,609 | 52,818 | 25,764 | ||||||||||||||
Operating income | $ | 18,278 | $ | 5,574 | $ | 57,727 | $ | 16,866 | $ | 26,581 | |||||||||
Corporate and Other | |||||||||||||||||||
Revenues: | |||||||||||||||||||
Unrealized commodity derivative gains (losses) | $ | 97,011 | $ | (17,044 | ) | $ | 86,164 | $ | 37,839 | $ | 43,151 | ||||||||
Realized commodity derivative losses | (2,698 | ) | (1,535 | ) | (17,958 | ) | (10,031 | ) | (8,813 | ) | |||||||||
Intersegment elimination - Sales of natural gas, oil and condensate | (13,184 | ) | — | (35,708 | ) | — | (13,021 | ) | |||||||||||
Total revenue | 81,129 | (18,579 | ) | 32,498 | 27,808 | 21,317 | |||||||||||||
Costs and expenses: | |||||||||||||||||||
Intersegment elimination - Cost of natural gas, oil and condensate | (14,558 | ) | — | (35,550 | ) | — | (13,903 | ) | |||||||||||
General and administrative | 16,068 | 10,674 | 43,746 | 36,491 | 15,902 | ||||||||||||||
Intersegment elimination - Operations and maintenance | — | — | (66 | ) | — | (24 | ) | ||||||||||||
Other operating Income | — | — | (2,893 | ) | — | (2,893 | ) | ||||||||||||
Depreciation, depletion and amortization | 311 | 399 | 1,018 | 1,234 | 320 | ||||||||||||||
Operating income (loss) | $ | 79,308 | $ | (29,652 | ) | $ | 26,243 | $ | (9,917 | ) | $ | 21,915 | |||||||
________________________
(1) | Includes sales of natural gas between Midstream Segments of $4,330 for both of the three and nine months ended September 30, 2011. |
(2) | Includes purchases of natural gas between Midstream Segments of $4,330 and purchases of natural gas, oil and condensate from the Upstream Segment of $10,228 and $31,220 for the three and nine months ended September 30, 2011, respectively, and $13,903 for the three months ended June 30, 2011. |
(3) | Includes natural gas sales of $66 and $24 from the South Texas Segment to the Upstream Segment for the nine months ended September 30, 2011 and the three months ended June 30, 2011, respectively. |
(4) | Includes sales of oil and condensate to the Texas Panhandle Segment of $13,184 and $35,708 for the three and nine months ended September 30, 2011, respectively, and $13,021 for the three months ended June 30, 2011. |
(5) | Revenues include a change in the value of product imbalances of $(38), $22, $(48) and $519 for the three and nine months ended September 30, 2011 and 2010, respectively, and $53 for the three months ended June 30, 2011. |
(6) | Revenues include a change in the value of product imbalances of $270, $(81), $155 and $(81) for the three and nine months ended September 30, 2011 and 2010, respectively, and $(195) for the three months ended June 30, 2011. |
(7) | Revenues include a change in the value of product imbalances of $(125), $27, $(54) and $27 for the three and nine months ended September 30, 2011 and 2010, respectively, and $66 for the three months ended June 30, 2011. |
Eagle Rock Energy Partners, L.P.
Midstream Segment
Operating Income
($ in thousands)
(unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended June 30, 2011 | |||||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||||||
Texas Panhandle | |||||||||||||||||||
Revenues: | |||||||||||||||||||
Natural gas, natural gas liquids, oil and condensate sales | $ | 159,674 | $ | 78,905 | $ | 436,825 | $ | 250,593 | $ | 156,073 | |||||||||
Gathering, compression, processing and treating services | 4,892 | 2,821 | 12,905 | 8,811 | 4,227 | ||||||||||||||
Total revenue | 164,566 | 81,726 | 449,730 | 259,404 | 160,300 | ||||||||||||||
Cost of natural gas, natural gas liquids, oil and condensate (1) | 129,986 | 54,783 | 351,305 | 176,485 | 125,391 | ||||||||||||||
Operating costs and expenses: | |||||||||||||||||||
Operations and maintenance | 10,828 | 9,155 | 31,436 | 25,666 | 11,207 | ||||||||||||||
Impairment | — | — | 4,560 | — | 4,560 | ||||||||||||||
Depreciation, depletion and amortization | 9,145 | 11,702 | 27,382 | 34,931 | 9,116 | ||||||||||||||
Total operating costs and expenses | 19,973 | 20,857 | 63,378 | 60,597 | 24,883 | ||||||||||||||
Operating income | $ | 14,607 | $ | 6,086 | $ | 35,047 | $ | 22,322 | $ | 10,026 | |||||||||
East Texas/Louisiana | |||||||||||||||||||
Revenues: | |||||||||||||||||||
Natural gas, natural gas liquids, oil and condensate sales | $ | 43,817 | $ | 37,352 | $ | 138,237 | $ | 127,816 | $ | 47,828 | |||||||||
Gathering, compression, processing and treating services | 6,123 | 8,854 | 22,517 | 29,532 | 7,813 | ||||||||||||||
Total revenue | 49,940 | 46,206 | 160,754 | 157,348 | 55,641 | ||||||||||||||
Cost of natural gas and natural gas liquids | 37,892 | 33,940 | 120,946 | 114,622 | 41,386 | ||||||||||||||
Operating costs and expenses: | |||||||||||||||||||
Operations and maintenance | 4,990 | 4,502 | 14,193 | 12,921 | 4,651 | ||||||||||||||
Depreciation, depletion and amortization | 4,589 | 4,631 | 13,706 | 13,171 | 4,561 | ||||||||||||||
Total operating costs and expenses | 9,579 | 9,133 | 27,899 | 26,092 | 9,212 | ||||||||||||||
Operating income | $ | 2,469 | $ | 3,133 | $ | 11,909 | $ | 16,634 | $ | 5,043 | |||||||||
South Texas | |||||||||||||||||||
Revenues: | |||||||||||||||||||
Natural gas, natural gas liquids, oil and condensate sales | $ | 11,042 | $ | 12,785 | $ | 32,186 | $ | 44,766 | $ | 11,151 | |||||||||
Gathering, compression, processing and treating services | 429 | 207 | 1,305 | 1,644 | 162 | ||||||||||||||
Total revenue | 11,471 | 12,992 | 33,491 | 46,410 | 11,313 | ||||||||||||||
Cost of natural gas and natural gas liquids | 10,910 | 11,321 | 31,544 | 41,624 | 10,714 | ||||||||||||||
Operating costs and expenses: | |||||||||||||||||||
Operations and maintenance | 400 | 390 | 1,055 | 1,530 | 278 | ||||||||||||||
Impairment | — | — | — | 3,130 | — | ||||||||||||||
Depreciation, depletion and amortization | 735 | 699 | 2,208 | 2,215 | 735 | ||||||||||||||
Total operating costs and expenses | 1,135 | 1,089 | 3,263 | 6,875 | 1,013 | ||||||||||||||
Operating (loss) income from continuing operations | (574 | ) | 582 | (1,316 | ) | (2,089 | ) | (414 | ) | ||||||||||
Discontinued Operations (2) | (197 | ) | (15 | ) | (194 | ) | 363 | (449 | ) | ||||||||||
Operating income (loss) | $ | (771 | ) | $ | 567 | $ | (1,510 | ) | $ | (1,726 | ) | $ | (863 | ) | |||||
Gulf of Mexico | |||||||||||||||||||
Revenues: | |||||||||||||||||||
Natural gas, natural gas liquids, oil and condensate sales | $ | 9,061 | $ | 7,623 | $ | 27,692 | $ | 23,302 | $ | 10,697 | |||||||||
Gathering, compression, processing and treating services | 123 | 211 | 389 | 819 | 102 | ||||||||||||||
Total revenue | 9,184 | 7,834 | 28,081 | 24,121 | 10,799 | ||||||||||||||
Cost of natural gas and natural gas liquids | 7,734 | 6,638 | 23,712 | 20,496 | 9,086 | ||||||||||||||
Operating costs and expenses: | |||||||||||||||||||
Operations and maintenance | 498 | 354 | 1,397 | 1,390 | 444 | ||||||||||||||
Depreciation, depletion and amortization | 1,624 | 1,651 | 4,954 | 4,821 | 1,664 | ||||||||||||||
Total operating costs and expenses | 2,122 | 2,005 | 6,351 | 6,211 | 2,108 | ||||||||||||||
Operating loss | $ | (672 | ) | $ | (809 | ) | $ | (1,982 | ) | $ | (2,586 | ) | $ | (395 | ) | ||||
____________________
(1) | Includes purchases of natural gas between Midstream Segments of $4,330 and purchases of natural gas, oil and condensate from the Upstream Segment of $10,228 and $31,220 for the three and nine months ended September 30, 2011, respectively, and $13,903 for the three months ended June 30, 2011. |
(2) | Includes sales of natural gas of $66 and $24 to the Upstream Segment for the nine months ended September 30, 2011 and the three months ended June 30, 2011, respectively. |
Eagle Rock Energy Partners, L.P.
Midstream Operations Information
(unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended June 30, 2011 | |||||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||||||
Gas gathering volumes - (Average Mcf/d) | |||||||||||||||||||
Texas Panhandle | 163,665 | 123,541 | 154,011 | 128,201 | 153,870 | ||||||||||||||
East Texas/Louisiana (1) | 173,567 | 205,194 | 188,431 | 209,724 | 191,735 | ||||||||||||||
South Texas | 25,170 | 39,792 | 29,423 | 54,347 | 27,221 | ||||||||||||||
Gulf of Mexico | 113,365 | 101,473 | 113,150 | 100,560 | 115,581 | ||||||||||||||
Total | 475,767 | 470,000 | 485,015 | 492,832 | 488,407 | ||||||||||||||
NGLs - (Net equity Bbls) | |||||||||||||||||||
Texas Panhandle | 231,965 | 198,639 | 609,097 | 660,839 | 181,186 | ||||||||||||||
East Texas/Louisiana (1) | 89,050 | 115,625 | 267,348 | 328,147 | 99,483 | ||||||||||||||
South Texas | 1,248 | 1,483 | 3,393 | 5,994 | 1,069 | ||||||||||||||
Gulf of Mexico | 23,981 | 27,995 | 74,514 | 77,961 | 26,373 | ||||||||||||||
Total | 346,244 | 343,742 | 954,352 | 1,072,941 | 308,111 | ||||||||||||||
Condensate - (Net equity Bbls) | |||||||||||||||||||
Texas Panhandle | 260,228 | 303,197 | 728,860 | 780,148 | 243,238 | ||||||||||||||
East Texas/Louisiana | 10,364 | 9,457 | 34,382 | 29,070 | 6,939 | ||||||||||||||
South Texas | 155 | (588 | ) | 1,045 | 10,999 | — | |||||||||||||
Total | 270,747 | 312,066 | 764,287 | 820,217 | 250,177 | ||||||||||||||
Natural gas short position - (Average MMbtu/d) | |||||||||||||||||||
Texas Panhandle | (7,418 | ) | (4,776 | ) | (5,517 | ) | (5,405 | ) | (360 | ) | |||||||||
East Texas/Louisiana | 523 | 317 | 1,129 | 949 | 1,717 | ||||||||||||||
South Texas | 1,235 | 773 | 834 | 995 | 145 | ||||||||||||||
Total | (5,660 | ) | (3,686 | ) | (3,554 | ) | (3,461 | ) | 1,502 | ||||||||||
Average realized NGL price - per Bbl | |||||||||||||||||||
Texas Panhandle | $ | 53.39 | $ | 40.38 | $ | 55.28 | $ | 44.99 | $ | 58.27 | |||||||||
East Texas/Louisiana | $ | 50.94 | $ | 31.32 | $ | 48.94 | $ | 34.48 | $ | 53.23 | |||||||||
South Texas | $ | 58.64 | $ | 40.81 | $ | 53.41 | $ | 45.09 | $ | 55.37 | |||||||||
Gulf of Mexico | $ | 55.58 | $ | 43.52 | $ | 56.70 | $ | 45.31 | $ | 61.23 | |||||||||
Weighted Average | $ | 53.08 | $ | 37.74 | $ | 53.51 | $ | 42.15 | $ | 56.80 | |||||||||
Average realized condensate price - per Bbl | |||||||||||||||||||
Texas Panhandle | $ | 79.43 | $ | 60.82 | $ | 82.31 | $ | 64.81 | $ | 87.54 | |||||||||
East Texas/Louisiana | $ | 94.20 | $ | 79.15 | $ | 95.42 | $ | 75.91 | $ | 109.51 | |||||||||
South Texas | $ | 80.06 | $ | 67.24 | $ | 82.34 | $ | 74.56 | $ | — | |||||||||
Total | $ | 79.74 | $ | 60.31 | $ | 83.31 | $ | 65.33 | $ | 88.80 | |||||||||
Average realized natural gas price - per MMbtu | |||||||||||||||||||
Texas Panhandle | $ | 3.86 | $ | 3.45 | $ | 3.95 | $ | 3.98 | $ | 4.00 | |||||||||
East Texas/Louisiana | $ | 4.43 | $ | 4.56 | $ | 4.55 | $ | 5.15 | $ | 4.61 | |||||||||
South Texas | $ | 4.21 | $ | 4.45 | $ | 4.15 | $ | 4.60 | $ | 4.26 | |||||||||
Total | $ | 4.05 | $ | 3.97 | $ | 4.14 | $ | 4.47 | $ | 4.18 | |||||||||
____________________
(1) | The Partnership changed the way it reports NGL and condensate volumes under certain contracts in its East Texas/Louisiana Segment. For the three and nine months ended September 30, 2011 and the three months ended June 30, 2011, volumes from Eagle Rock's Indian Springs plant, in which the Partnership owns 25%, are included in equity NGL and condensate volumes, as the Partnership believes including these volumes is more illustrative of current operating trends. In addition, volumes associated with a certain contract at the Partnership's Brookeland plant have been excluded from the three and nine months ended September 30, 2011 and three months ended June 30, 2011 due to a change in reporting methodology. |
Eagle Rock Energy Partners, L.P.
Upstream Operations Information
(unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended June 30, 2011 | |||||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||||||
Upstream | |||||||||||||||||||
Production: | |||||||||||||||||||
Oil and condensate (Bbl) | 302,766 | 212,083 | 772,350 | 613,315 | 272,850 | ||||||||||||||
Gas (Mcf) | 4,274,811 | 778,793 | 8,272,176 | 2,743,883 | 3,165,060 | ||||||||||||||
NGLs (Bbl) | 227,614 | 102,967 | 533,223 | 355,470 | 206,251 | ||||||||||||||
Total Mcfe | 7,457,091 | 2,669,093 | 16,105,615 | 8,556,593 | 6,039,672 | ||||||||||||||
Sulfur (long ton) (1) | 27,706 | 17,622 | 71,509 | 69,929 | 25,268 | ||||||||||||||
Realized prices, excluding derivatives: (2) | |||||||||||||||||||
Oil and condensate (per Bbl) | $ | 81.65 | $ | 60.21 | $ | 82.57 | $ | 60.98 | $ | 88.67 | |||||||||
Gas (Mcf) | $ | 4.08 | $ | 4.30 | $ | 3.95 | $ | 4.54 | $ | 3.74 | |||||||||
NGLs (Bbl) | $ | 52.35 | $ | 41.92 | $ | 55.37 | $ | 45.70 | $ | 58.29 | |||||||||
Sulfur (long ton) (1) | $ | 187.03 | $ | 80.54 | $ | 179.48 | $ | 75.38 | $ | 182.73 | |||||||||
Operating statistics: | |||||||||||||||||||
Operating costs per Mcfe (incl production taxes) (3) | $ | 1.48 | $ | 2.59 | $ | 1.84 | $ | 2.83 | $ | 1.75 | |||||||||
Operating costs per Mcfe (excl production taxes) (3) | $ | 0.98 | $ | 1.93 | $ | 1.19 | $ | 2.08 | $ | 1.04 | |||||||||
Operating income per Mcfe | $ | 2.45 | $ | 2.09 | $ | 3.58 | $ | 1.97 | $ | 4.40 | |||||||||
Drilling program (gross wells): | |||||||||||||||||||
Development wells | 13 | 3 | 31 | 6 | 18 | ||||||||||||||
Completions | 13 | 2 | 31 | 5 | 18 | ||||||||||||||
Workovers | 5 | 6 | 14 | 13 | 7 | ||||||||||||||
Recompletions | 4 | 5 | 5 | 11 | 1 | ||||||||||||||
______________________
(1) | During the three months ended March 31, 2010, an adjustment was made to decrease sulfur volumes by 5,230 long tons related to a prior period adjustment. This adjustment is excluded from the calculation of realized prices. |
(2) | Calculation does not include impact of product imbalances. |
(3) | Excludes sulfur disposal costs of $729 the nine months ended September 30, 2010 and excludes post-production costs of $1,683 for both the three and nine months ended September 30, 2011, and $63 and $(383) for the three and nine months ended September 30, 2010, respectively. |
Non-GAAP Financial Measures
The following tables present a reconciliation of the non-GAAP financial measures of Adjusted EBITDA and Distributable Cash Flow to the GAAP financial measure of net income for each of the periods indicated (in thousands).
Eagle Rock Energy Partners, L.P.
GAAP to Non-GAAP Reconciliations
($ in thousands)
(unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended June 30, 2011 | |||||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||||||
Net (loss) income to Adjusted EBITDA | |||||||||||||||||||
Net (loss) income, as reported | $ | 97,365 | $ | (25,237 | ) | $ | 98,719 | $ | 46,887 | $ | 55,071 | ||||||||
Depreciation, depletion and amortization | 35,040 | 25,892 | 90,314 | 80,805 | 31,576 | ||||||||||||||
Impairment | 9,870 | 3,432 | 14,754 | 6,562 | 4,560 | ||||||||||||||
Risk management interest related instruments - unrealized | 3,165 | 3,112 | (2,191 | ) | 12,288 | (2,791 | ) | ||||||||||||
Risk management commodity related instruments - unrealized, including amortization of commodity derivative costs | (97,011 | ) | 17,044 | (86,164 | ) | (37,839 | ) | (43,151 | ) | ||||||||||
Other Operating Income | — | — | (2,893 | ) | — | (2,893 | ) | ||||||||||||
Non-cash mark-to-market of Upstream product imbalances | (107 | ) | 102 | (123 | ) | (465 | ) | 76 | |||||||||||
Unrealized gains from Eagle Rock Gas Services | (538 | ) | — | (538 | ) | — | — | ||||||||||||
Restricted units non-cash amortization expense | 1,507 | 1,294 | 3,441 | 4,652 | 1,024 | ||||||||||||||
Income tax (benefit) provision | (1,077 | ) | (1,244 | ) | (1,810 | ) | (970 | ) | (691 | ) | |||||||||
Interest - net including realized risk management instruments and other expense | 13,766 | 8,470 | 33,120 | 26,935 | 10,856 | ||||||||||||||
Other income | — | (21 | ) | — | (99 | ) | — | ||||||||||||
Discontinued operations | 197 | (166 | ) | (210 | ) | (43,811 | ) | 311 | |||||||||||
Adjusted EBITDA | $ | 62,177 | $ | 32,678 | $ | 146,419 | $ | 94,945 | $ | 53,948 | |||||||||
Net (loss) income to Distributable Cash Flow | |||||||||||||||||||
Net (loss) income, as reported | $ | 97,365 | $ | (25,237 | ) | $ | 98,719 | $ | 46,887 | $ | 55,071 | ||||||||
Depreciation, depletion and amortization expense | 35,040 | 25,892 | 90,314 | 82,550 | 31,576 | ||||||||||||||
Impairment | 9,870 | 3,432 | 14,754 | 6,562 | 4,560 | ||||||||||||||
Risk management interest related instruments-unrealized | 3,165 | 3,112 | (2,191 | ) | 12,288 | (2,791 | ) | ||||||||||||
Risk management commodity related instruments - unrealized, including amortization of commodity derivative costs | (97,549 | ) | 17,044 | (86,702 | ) | (37,839 | ) | (43,151 | ) | ||||||||||
Capital expenditures-maintenance related | (11,980 | ) | (7,903 | ) | (30,311 | ) | (19,970 | ) | (11,874 | ) | |||||||||
Non-cash mark-to-market of Upstream product imbalances | (107 | ) | 102 | (123 | ) | (465 | ) | 76 | |||||||||||
Restricted units non-cash amortization expense | 1,507 | 1,294 | 3,441 | 4,652 | 1,024 | ||||||||||||||
Other Operating Income | — | — | (2,893 | ) | — | (2,893 | ) | ||||||||||||
Income tax (benefit) provision | (1,077 | ) | (1,244 | ) | (1,810 | ) | (940 | ) | (691 | ) | |||||||||
Other income | — | (21 | ) | — | (99 | ) | — | ||||||||||||
Cash income taxes | (325 | ) | 376 | (802 | ) | (605 | ) | (268 | ) | ||||||||||
Discontinued operations | 197 | (166 | ) | (210 | ) | (43,811 | ) | 311 | |||||||||||
Distributable Cash Flow | $ | 36,106 | $ | 16,681 | $ | 82,186 | $ | 49,210 | $ | 30,950 | |||||||||
Supplemental Information | |||||||||||||||||||
($ in thousands) | |||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended June 30, 2011 | |||||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||||||
Amortization of commodity derivative costs | $ | — | $ | 437 | $ | — | $ | 3,515 | $ | — | |||||||||
###