| March 10, 2009 | CONTACTS: |
| | Jeff Wood – Chief Financial Officer Phone: 281-408-1203 Elizabeth Wilkinson – Investor Relations Phone: 281-408-1329 |
Eagle Rock Reports Fourth-Quarter and Year-End 2008 Results
HOUSTON - Eagle Rock Energy Partners, L.P. (“Eagle Rock” or the “Partnership”) (NASDAQ: EROC) today announced its financial results for the three months and year ended December 31, 2008.
Highlights:
The Partnership highlighted the following results for the fourth quarter of 2008, as compared to the fourth quarter of 2007:
| · | Adjusted EBITDA increased by 22.2% to $63.5 million from $52.0 million. Fourth-quarter 2008 Adjusted EBITDA included an $18.3 million realized gain on commodity derivatives. |
| · | The quarterly distribution rate increased by 4.5% to $0.41 per unit from $0.3925 per unit, resulting in a $31.7 million distribution with respect to fourth quarter 2008. |
| · | Distributable Cash Flow increased by 38.9% to $47.2 million from $34.0 million. Fourth quarter Distributable Cash Flow represents 1.49x coverage of the fourth quarter 2008 distribution. |
| · | Net income increased to $54.8 million from a net loss of $111.6 million; fourth quarter net income benefited from a $214.0 million unrealized gain on derivatives partially offset by a $174.9 million impairment charge. |
Fourth-quarter 2008 Adjusted EBITDA and Distributable Cash Flow excluded $6.5 million in non-cash amortization of commodity hedge costs. Including these costs, Distributable Cash Flow would have been $40.7 million representing 1.28x coverage.
The following are significant results for the year ended December 31, 2008, as compared to the year ended December 31, 2007:
| · | Adjusted EBITDA increased by 86.9% to $249.2 million from $133.4 million. |
| · | The annual distribution rate increased by 9.8% to $1.63 per unit from $1.485 per unit, resulting in total distributions of $120.8 million with respect to 2008. |
| · | Distributable Cash Flow increased by 132.1% to $182.5 million from $78.6 million. 2008 Distributable Cash Flow coverage was 1.51x. |
| · | The midstream and upstream asset bases were expanded via the Millennium Midstream and Stanolind Oil and Gas acquisitions. |
| · | Average daily throughput in the Midstream Business increased by 29.3% to 451 MMcf/d from 349 MMcf/d in 2007. |
| · | Average daily production in the Upstream Business increased by 3.0% to 5.5 MBoe/d from 5.3 MBoe/d in 2007. |
| · | The Minerals Business generated $16.8 million in lease bonus and delay rental income. |
| · | Net income increased to $87.5 million from a net loss of $145.6 million; 2008 net income benefited from a $180.1 million unrealized gain on derivatives partially offset by a $174.9 million impairment charge. |
Full-year 2008 Adjusted EBITDA and Distributable Cash Flow excluded $13.3 million of non-cash amortization of commodity hedge costs. Distributable Cash Flow including these costs would have been $169.2 million representing 1.40x coverage.
"We are very pleased to report solid financial results for the fourth quarter of 2008, despite the continued decline in commodity prices and a marked reduction in processing margins and drilling activity supporting our Midstream Business. During the fourth quarter, we benefited from our diversified business model, as the Upstream Segment achieved solid operating performance and the Minerals Segment contributed additional significant lease bonus income. In addition, the East Texas midstream assets we acquired on October 1 supported our performance during the quarter,” said Joseph A. Mills, chairman and chief executive officer.
He added, “We have prepared for challenging conditions to continue in 2009. We restructured our hedge portfolio in January 2009 so that our expected 2009 cash flows will be much less sensitive to commodity price movements. In addition, we are focused heavily on controlling costs and maintaining investment discipline while we monitor developments in the commodity and capital markets, as well as the drilling activity in our areas of operation.”
Adjusted EBITDA and Distributable Cash Flow are non GAAP financial measures that are defined below and reconciled to the most directly comparable GAAP financial measure of net income (loss) at the end of this release.
2009 Hedging Update
We entered into a series of hedging transactions in 2009 that supplemented and / or enhanced our existing 2009 hedge portfolio. As a result, we have now hedged approximately 88% of our expected 2009 crude, condensate and natural gas liquids (heavier than ethane) production, and 93% of our expected 2009 natural gas and ethane production. The majority of our liquids hedges (78%) are crude oil derivatives which have an average floor price of $91.59/Bbl, and the majority of our natural gas and ethane hedges (73%) are natural gas derivatives which have an average floor price of $7.36/MMBTU; the balance of our hedges are direct product hedges whose details are on our website.
Fourth-Quarter and Full-Year Results
Eagle Rock analyzes and manages its operations under seven distinct segments: four segments in our Midstream Business that we identify as the Texas Panhandle, East Texas / Louisiana, South Texas and Gulf of Mexico Segments, and the Upstream, Minerals and Corporate Segments. The Corporate Segment includes our risk management (derivatives) and other corporate activities. Please refer to the financial tables at the end of this release for further detailed information.
Fourth-Quarter Results
Revenue for the fourth-quarter 2008, including the impact of our realized and unrealized derivative gains and losses, increased 150.5% to $548.0 million compared with $218.7 million reported for the fourth quarter of 2007. Fourth-quarter 2008 revenues included a realized gain on commodity derivatives of $18.3 million and an unrealized gain on commodity derivatives of $241.2 million, as compared to the fourth-quarter 2007 in which Eagle Rock recorded a $7.4 million realized commodity derivatives loss and a $100.2 million unrealized commodity derivatives loss. The unrealized commodity derivatives gain (loss) is a non-cash, mark-to-market amount which includes the amortization of commodity hedging costs.
Adjusted EBITDA for the fourth quarter of 2008 was $63.5 million compared with $52.0 million for the fourth quarter of 2007, an increase of 22.2%. Fourth-quarter 2008 Distributable Cash Flow totaled $47.2 million compared to $34.0 for the fourth quarter of 2007. Fourth-quarter 2008 Distributable Cash Flow represents 1.49x coverage of the fourth quarter 2008 distribution of $0.41 per unit paid on February 13, 2009.
Fourth-quarter 2008 Adjusted EBITDA and Distributable Cash Flow included a realized commodity derivative gain of $18.3 million, $4.2 million of which related to hedge reset transactions executed in November 2008. Adjusted EBITDA and Distributable Cash Flow exclude $6.5 million of non-cash amortization of commodity hedge costs, such as the amortization of put premiums and of hedge reset costs. Distributable Cash Flow including these costs would have been $40.7 million representing 1.28x coverage.
During the fourth quarter of 2008, and as a result of the depressed commodity price environment and reduced drilling activity impacting its assets, Eagle Rock recorded a non-cash impairment expense of $35.1 million in its Midstream Business, $107.0 million in its Upstream Business, $1.7 million in its Minerals Business and a $31.0 million impairment of goodwill originally recorded in conjunction with the Redman acquisition executed in 2007. There was no impairment associated with the Stanolind and Millennium assets acquired in 2008. During the fourth quarter of 2007, Eagle Rock recorded a non-cash impairment expense of $5.7 million related to its Minerals Business. Pursuant to generally accepted accounting principles in the United States, our impairment analysis does not take into account the value of our commodity derivative instruments, which generally increase as the estimates of future prices decline.
Net income for the fourth quarter of 2008 increased to $54.8 million, primarily due to the $214.0 million combined non-cash, unrealized gain related to commodity and interest rate risk derivatives, offset significantly by a $174.9 million non-cash asset impairment charge. The net loss for the fourth quarter of 2007 of $111.6 million was primarily due to the impact of a combined unrealized loss related to both commodity and interest rate risk derivatives of $110.1 million.
Fourth-Quarter 2008 Operating Results by Business
Midstream Business – Segment operating income for the Midstream Business in the fourth quarter of 2008, excluding the impact of the impairment discussed above, decreased by $20.9 million compared to the same period in 2007. The decrease was caused primarily by a 12% decline in gas gathering volumes and lower realized NGL prices in our Texas Panhandle Segment.
Upstream Business – Segment operating income for our Upstream Business in the fourth quarter of 2008, excluding the impact of the impairment discussed above, decreased by $4.2 million compared to the same period in 2007. The decrease was caused in part by a 38% decline in realized crude oil prices and a 7% decline in realized natural gas prices. The decrease was also caused in part by Upstream depreciation, depletion and amortization, which increased by $6.1 million compared to the prior year period due primarily to higher production rates in the fourth quarter of 2008 and the addition of the Stanolind assets. These factors were partially offset by the positive contribution to operating income from our Stanolind Acquisition and the increase in realized sulfur prices from $58 per long ton in fourth quarter 2007 to $304 per long ton in fourth-quarter 2008.
Minerals Business – Segment operating income from our Minerals Business in the fourth quarter of 2008, excluding the impact of the impairments discussed above, increased by $4.5 million compared to the same period in 2007. The increase was primarily due to lease bonuses and delay rental payments totaling $4.6 million in the fourth quarter of 2008 compared to $0.7 million in the fourth quarter of 2007. Total production increased by 7.5% in the fourth quarter of 2008 compared to the same period in 2007. These positive factors were partially offset by decreases in realized prices of crude oil and natural gas of 38% and 18%, respectively.
Full-Year Financial Results
Revenue for 2008, including the impact of both our realized and unrealized derivative gains and losses, increased by 124.4% to $1,743.3 million compared with $776.8 million for the prior year. Revenue for 2008 includes $46.1 million of realized losses on commodity derivatives and $207.8 million of unrealized gains on commodity derivatives. Revenues for 2007 included $3.1 million of realized losses on commodity derivatives and $130.8 million of unrealized losses on commodity derivatives.
Adjusted EBITDA for the year ended December 31, 2008 was $249.2 million compared with $133.4 million for the year ended December 31, 2007, an increase of 86.9%. Distributable Cash Flow for the year ended December 31, 2008 was $182.5 million representing 1.51x coverage of the 2008 distribution.
Adjusted EBITDA and Distributable Cash Flow for the full year ended 2008 exclude $13.3 million of non-cash amortization of commodity hedge costs. Distributable Cash Flow including these costs would have been $169.2 million representing 1.40x coverage.
Net income increased to $87.5 million for the year ended December 31, 2008, compared to the net loss of $145.6 million for the year ended December 31, 2007. Net income of $87.5 million included a net unrealized commodity and interest rate derivative gain totaling $180.1 million, the non-recurring write-off of $10.7 million in bad-debt provisions related to SemCrude’s bankruptcy, and a $174.9 million non-cash asset impairment charge. The net loss of $145.6 million for the year ended December 31, 2007 included combined unrealized derivative losses of $144.2 million on our commodity and interest rate derivatives and a $5.7 million non-cash asset impairment charge.
Contract Mix
As of December 31, 2008, approximately 46.6% of the Partnership’s Midstream gathered volumes were contracted under fee-based contracts, 45.0% under percent-of-proceeds / fixed recovery contracts and 8.4% under keep-whole contracts.
Capitalization and Liquidity Update
On September 29, 2008, we requested a $181.0 million funding under our senior secured revolving credit facility to finance the Millennium acquisition. Lehman Brothers Commercial Bank, a lender under our credit facility, defaulted on its portion of the borrowing request, resulting in an actual funding of $176.4 million. As a result of the Lehman default, we believe the availability under our credit facility has been effectively reduced by approximately $9.1 million. As of December 31, 2008, we had $171.5 million in capacity available under our credit facility, after giving effect to the Lehman default.
We are within our financial covenants and have no maturities under our credit facility until December 2012. As of December 31, 2008, our interest coverage ratio, as defined in our credit agreement, was 6.6 as compared to a minimum interest coverage ratio of 2.5; our leverage ratio, as defined in the credit agreement, was 3.7 as compared to a maximum leverage ratio of 5.0 (5.25 until March 31, 2009 as a result of the Millennium acquisition).
Total funded debt as of December 31, 2008 was approximately $799.4 million. Subsequent to year-end we added a net $20 million under our LIBOR-based borrowings, in addition to swingline activity under our credit facility.
We estimate that our capital expenditures will be approximately $40 million in 2009 as compared to $70.7 million in 2008. We expect the $40 million of total capital expenditures will be weighted equally between maintenance capital expenditures, which are funded from our cash flow, and growth capital expenditures, which are typically funded from external financing sources.
Unit Distributions
On February 4, 2009, we announced a fourth-quarter 2008 cash distribution of $0.41 per unit, or $1.64 per unit on an annualized basis, for all of our outstanding common, subordinated and general partner units. This distribution was paid on February 13, 2009, to unitholders of record on February 10, 2009. This distribution was equal to the prior quarter’s distribution and reflects an increase of approximately 4.5% over the distribution for the fourth quarter of 2007.
In the fourth quarter of 2008, we generated $47.2 million of Distributable Cash Flow ($40.7 million including amortization of commodity hedge costs), representing coverage of 1.49x of the amount required to pay our announced distribution to common, general partner and subordinated unitholders.
We make distribution determinations as required under our partnership agreement based on our Adjusted EBITDA, Distributable Cash Flow and the sustainability of distribution levels over an extended period. In addition to considering the Adjusted EBITDA and Distributable Cash Flow generated during the quarter, we take into account cash reserves in accordance with our partnership agreement established with respect to prior distributions and our internal forecasts of Adjusted EBITDA and Distributable Cash Flow over an extended period.
Distributions are set by the Board of Directors and are made in accordance with our partnership agreement and in consideration of the long-term sustainability of the business. Eagle Rock continues to evaluate its distribution policy given the current market conditions, including a depressed commodity pricing environment, a continued lack of access to both debt and equity markets, an increased cost of capital and/or decreased producer drilling activity. We anticipate these conditions may persist, which could lead to a reduction in distributions.
Given that our 20.7 million subordinated units have not converted into common units, and will not do so prior to the third quarter of 2010 at the earliest, our common unitholders have substantial downside protection to their distribution below our Minimum Quarterly Distribution (as defined in our Partnership Agreement) of $0.3625 per unit or $1.45 per unit annualized.
Conference Call
Eagle Rock will hold a conference call to discuss its fourth-quarter, year-end 2008 financial results and recent developments on Wednesday, March 11 at 10 a.m. Eastern Time (9 a.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 888-679-8033, confirmation code 60286598. 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 to pre-register and view important information about this conference call. 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 call start. To pre-register, please click https://www.theconferencingservice.com/prereg/key.process?key=PU4XVXRHQ. (Due to its length, this URL may need to be copied/pasted into your internet browser’s address field. Remove extra space if one exists.) An audio replay of the conference call will also be available for thirty days by dialing 888-286-8010, confirmation code 29729718. In addition, a replay of the audio webcast will be available within a few days after the call on Eagle Rock’s website.
The Partnership is a growth-oriented master limited partnership engaged in three businesses: a) midstream, which includes (i) gathering, compressing, treating, processing and transporting natural gas; (ii) fractionating and transporting natural gas liquids; and (iii) marketing natural gas, condensate and NGLs; b) upstream, which includes acquiring, exploiting, developing, and producing interests in oil and natural gas properties; and c) minerals, which includes acquiring and managing fee mineral and royalty interests, either through direct ownership or through investment in other partnerships in properties located in multiple producing trends across the United States. Its corporate office is located in Houston, Texas.
“Board of Directors” in this press release refers to the Board of Directors of the general partner of the general partner of the Partnership.
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 as 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; and other (income) expense.
We use Adjusted EBITDA as a measure of our core profitability to assess the financial performance of our 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, our lenders under our revolving credit facility use a variant of our 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; we, therefore, use Adjusted EBITDA to measure our compliance with our 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 our 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 our executed derivative instruments and is independent of our assets’ performance or cash flow generating ability, we believe Adjusted EBITDA reflects more accurately our ability to generate cash sufficient to pay interest costs, support our level of indebtedness, make cash distributions to our unitholders and general partner and finance our maintenance capital expenditures. We further believe that Adjusted EBITDA also describes more accurately the underlying performance of our operating assets by isolating the performance of our operating assets from the impact of an unrealized, non-cash measure designed to describe the fluctuating inherent value of a financial asset. Similarly, by excluding the impact of non-recurring discontinued operations, Adjusted EBITDA provides users of our financial statements a more accurate picture of our current assets’ cash generation ability, independently from that of assets which are no longer a part of our 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, we include in Adjusted EBITDA the actual settlement revenue created from our commodity hedges by virtue of transactions undertaken by us to reset commodity hedges to higher prices or purchase puts or other similar floors despite the fact that we exclude 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: a) in our Midstream Business, capital expenditures employed to replace partially- or fully- depreciated assets to maintain the existing operating capacity of the Partnership’s assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows, including well-connect expenditures; and b) in our Upstream Business, capital expenditures employed to partially or fully replace production volumes in order to maintain existing volumes and related cash flows.
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 and are made in consideration of the long-term sustainability of the business.
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. 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” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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. 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, which may cause the Partnership’s actual results to differ materially from those implied or expressed by the forward-looking statements. 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 for the year ended December 31, 2007, and the Partnership’s Forms 10-Q, filed with the SEC for subsequent quarters. In addition, we encourage you to look for an update to these risk factors which will be included in our 2008 Annual Report on Form 10-K that we intend to file shortly following the issuance of this press release.
Eagle Rock Energy Partners, L.P.
Consolidated Statements of Operations
($ in thousands)
(unaudited)
| | | Three Months | | | Twelve Months | | | Three Months | |
| | | Ended Dec. 31, | | | Ended December 31, | | | Ended | |
| | | 2008 | | | 2007 | | | 2008 | | | 2007 | | | September 30, 2008 | |
| | | | | | | | | | | | | | | | |
| REVENUE: | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| Natural gas, NGLs, condensate, oil and sulfur sales | | $ | 268,841 | | | $ | 312,275 | | | $ | 1,498,975 | | | $ | 868,101 | | | $ | 421,346 | |
| Gathering, compression, processing and treating fees | | | 11,130 | | | | 8,148 | | | | 38,871 | | | | 27,417 | | | | 12,513 | |
| Minerals and royalty income | | | 8,388 | | | | 5,803 | | | | 42,994 | | | | 15,004 | | | | 17,393 | |
| Unrealized commodity derivative gains (losses) | | | 241,205 | | | | (100,240 | ) | | | 207,824 | | | | (130,773 | ) | | | 255,956 | |
| Realized commodity derivative gains (losses) | | | 18,329 | | | | (7,385 | ) | | | (46,059 | ) | | | (3,061 | ) | | | (24,105 | ) |
| Other income | | | 106 | | | | 130 | | | | 716 | | | | 110 | | | | 428 | |
| Total Revenue | | | 547,999 | | | | 218,731 | | | | 1,743,321 | | | | 776,798 | | | | 683,531 | |
| | | | | | | | | | | | | | | | | | | | | |
| COSTS AND EXPENSES: | | | | | | | | | | | | | | | | | | | | |
| Cost of natural gas and NGLs | | | 208,530 | | | | 235,042 | | | | 1,154,707 | | | | 686,882 | | | | 316,788 | |
| Operations and maintenance | | | 18,848 | | | | 16,962 | | | | 73,620 | | | | 52,793 | | | | 21,475 | |
| Taxes other than income | | | 4,961 | | | | 3,792 | | | | 19,936 | | | | 8,340 | | | | 5,365 | |
| Impairment | | | 143,857 | | | | - | | | | 143,857 | | | | - | | | | - | |
| Goodwill Impairment | | | 30,994 | | | | 5,749 | | | | 30,994 | | | | 5,749 | | | | - | |
| General and administrative | | | 14,540 | | | | 11,212 | | | | 45,701 | | | | 27,799 | | | | 9,893 | |
| Other operating | | | 565 | | | | 916 | | | | 10,699 | | | | 2,847 | | | | 3,920 | |
| Depreciation, depletion and amortization | | | 35,955 | | | | 29,675 | | | | 116,754 | | | | 80,559 | | | | 28,597 | |
| Total Costs and Expenses | | | 458,250 | | | | 303,348 | | | | 1,596,268 | | | | 864,969 | | | | 386,038 | |
| | | | | | | | | | | | | | | | | | | | | |
| OPERATING INCOME ( LOSS) | | | 89,749 | | | | (84,617 | ) | | | 147,053 | | | | (88,171 | ) | | | 297,493 | |
| | | | | | | | | | | | | | | | | | | | | |
| Other Income (Expense): | | | | | | | | | | | | | | | | | | | | |
| Interest income | | | 120 | | | | 630 | | | | 793 | | | | 1,160 | | | | 212 | |
| Other income | | | 2,461 | | | | (183 | ) | | | 5,328 | | | | 696 | | | | 434 | |
| Interest expense, net | | | (9,308 | ) | | | (11,905 | ) | | | (32,884 | ) | | | (38,936 | ) | | | (7,498 | ) |
| Unrealized interest rate derivative gains (losses) | | | (27,245 | ) | | | (9,848 | ) | | | (27,717 | ) | | | (13,403 | ) | | | (501 | ) |
| Realized interest rate derivative gains (losses) | | | (311 | ) | | | 448 | | | | (5,214 | ) | | | 1,415 | | | | (2,358 | ) |
| Other expense | | | (303 | ) | | | (6,682 | ) | | | (955 | ) | | | (8,226 | ) | | | (205 | ) |
| Total Other Income (Expense) | | | (34,586 | ) | | | (27,540 | ) | | | (60,649 | ) | | | (57,294 | ) | | | (9,916 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| INCOME (LOSS) BEFORE INCOME TAXES | | | 55,163 | | | | (112,157 | ) | | | 86,404 | | | | (145,465 | ) | | | 287,577 | |
| | | | | | | | | | | | | | | | | | | | | |
| Income tax (benefit) provision | | | 366 | | | | 603 | | | | (1,116 | ) | | | 169 | | | | (494 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| NET INCOME ( LOSS) | | $ | 54,797 | | | $ | (111,554 | ) | | $ | 87,520 | | | $ | (145,634 | ) | | $ | 288,071 | |
Eagle Rock Energy Partners, L.P.
Consolidated Balance Sheets
($ in thousands)
(unaudited)
| | | December 31, | | | December 31, | |
| | | 2008 | | | 2007 | |
| | | | | | | |
| Assets | | | | | | |
| Current assets: | | | | | | |
| Cash and cash equivalents | | $ | 17,916 | | | $ | 68,552 | |
| Accounts receivable | | | 115,932 | | | | 135,633 | |
| Risk management assets | | | 76,769 | | | | - | |
| Prepayments and other current assets | | | 2,607 | | | | 3,992 | |
| | | | 213,224 | | | | 208,177 | |
| | | | | | | | | |
| Property plant and equipment - net | | | 1,357,609 | | | | 1,207,130 | |
| Intangible assets - net | | | 154,206 | | | | 153,948 | |
| Goodwill | | | - | | | | 29,527 | |
| Risk management assets | | | 32,451 | | | | | |
| Other assets | | | 15,571 | | | | 11,145 | |
| Total assets | | $ | 1,773,061 | | | $ | 1,609,927 | |
| | | | | | | | | |
| Liabilities and Members' Equity | | | | | | | | |
| Current liabilities: | | | | | | | | |
| Accounts payable | | $ | 116,578 | | | $ | 132,485 | |
| Due to affiliate | | | 4,473 | | | | 16,964 | |
| Accrued liabilities | | | 19,565 | | | | 9,776 | |
| Taxes payable | | | 1,559 | | | | 723 | |
| Risk management liabilities | | | 13,763 | | | | 33,089 | |
| | | | 155,938 | | | | 193,037 | |
| | | | | | | | | |
| Long-term debt | | | 799,383 | | | | 567,069 | |
| Asset retirement obligations | | | 19,872 | | | | 11,337 | |
| Deferred tax liability | | | 42,349 | | | | 17,516 | |
| Risk management liabilities | | | 26,182 | | | | 94,200 | |
| Other Long-term liabilities | | | 1,622 | | | | | |
| | | | | | | | | |
| Members' equity | | | | | | | | |
| Common unitholders | | | 625,590 | | | | 617,563 | |
| Subordinated unitholders | | | 105,839 | | | | 112,360 | |
| General partner | | | (3,714 | ) | | | (3,155 | ) |
| | | | 727,715 | | | | 726,768 | |
| Total Liabilities and Members' Equity | | $ | 1,773,061 | | | $ | 1,609,927 | |
Eagle Rock Energy Partners, L.P.
Midstream Segment
Operating Income
($ in thousands)
(unaudited)
| | | Three Months Ended | | | Twelve Months Ended | | | Three Months | |
| | | Dec. 31 | | | Dec.31 | | | Ended | |
| | | 2008 | | | 2007 | | | 2008 | | | 2007 | | | Sept 30, 2008 | |
| | | | | | | | | | | | | | | | |
| Texas Panhandle | | | | | | | | | | | | | | | |
| Revenues: | | | | | | | | | | | | | | | |
| Natural gas, NGLs, oil and condensate sales | | $ | 78,547 | | | $ | 150,448 | | | $ | 592,997 | | | $ | 479,120 | | | $ | 179,608 | |
| Gathering, compression, processing, and treating services | | | 2,405 | | | | 2,255 | | | | 10,069 | | | | 8,910 | | | | 2,671 | |
| Other | | | - | | | | - | | | | - | | | | - | | | | - | |
| Total revenues | | | 80,952 | | | | 152,703 | | | | 603,066 | | | | 488,030 | | | | 182,279 | |
| Cost of natural gas and NGLs | | | 60,236 | | | | 113,629 | | | | 459,064 | | | | 372,205 | | | | 138,428 | |
| Operating costs and expenses: | | | | | | | | | | | | | | | | | | | | |
| Operations and maintenance | | | 8,616 | | | | 6,800 | | | | 34,269 | | | | 32,494 | | | | 9,190 | |
| Depreciation, depletion and amortization | | | 11,101 | | | | 12,276 | | | | 43,688 | | | | 42,308 | | | | 10,984 | |
| Total operating costs and expenses | | | 19,717 | | | | 19,076 | | | | 77,957 | | | | 74,802 | | | | 20,174 | |
| Operating income | | $ | 999 | | | $ | 19,998 | | | $ | 66,045 | | | $ | 41,023 | | | $ | 23,677 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
East Texas/Louisiana (1)(2) | | | | | | | | | | | | | | | | | | | | |
| Revenues: | | | | | | | | | | | | | | | | | | | | |
| Natural gas, NGLs, oil and condensate sales | | $ | 66,724 | | | $ | 58,252 | | | $ | 298,720 | | | $ | 153,660 | | | $ | 71,861 | |
| Gathering, compression, processing, and treating services | | | 6,264 | | | | 3,341 | | | | 23,320 | | | | 13,547 | | | | 8,908 | |
| Other | | | | | | | | | | | | | | | (21 | ) | | | | |
| Total revenues | | | 72,988 | | | | 61,593 | | | | 322,040 | | | | 167,186 | | | | 80,769 | |
| Cost of natural gas and NGLs | | | 59,093 | | | | 50,859 | | | | 269,030 | | | | 133,350 | | | | 66,007 | |
| Operating costs and expenses: | | | | | | | | | | | | | | | - | | | | | |
| Operations and maintenance | | | 5,058 | | | | 3,053 | | | | 16,569 | | | | 10,929 | | | | 4,194 | |
| Impairment | | | 26,994 | | | | - | | | | 26,994 | | | | - | | | | | |
| Depreciation, depletion and amortization | | | 4,713 | | | | 3,568 | | | | 13,559 | | | | 10,781 | | | | 2,989 | |
| Total operating costs and expenses | | | 36,765 | | | | 6,621 | | | | 57,122 | | | | 21,710 | | | | 7,183 | |
| Operating income | | $ | (22,870 | ) | | $ | 4,113 | | | $ | (4,112 | ) | | $ | 12,126 | | | $ | 7,579 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
South Texas (1)(2) | | | | | | | | | | | | | | | | | | | | |
| Revenues: | | | | | | | | | | | | | | | | | | | | |
| Natural gas, NGLs, oil and condensate sales | | $ | 90,046 | | | $ | 71,958 | | | $ | 433,978 | | | $ | 184,634 | | | $ | 114,899 | |
| Gathering, compression, processing, and treating services | | | 1,758 | | | | 1,602 | | | | 4,779 | | | | 4,012 | | | | 934 | |
| Other | | | 13 | | | | 1 | | | | 15 | | | | 1 | | | | - | |
| Total revenues | | | 91,817 | | | | 73,561 | | | | 438,772 | | | | 188,647 | | | | 115,833 | |
| Cost of natural gas and NGLs | | | 87,825 | | | | 70,555 | | | | 425,237 | | | | 181,327 | | | | 112,353 | |
| Operating costs and expenses: | | | | | | | | | | | | | | | | | | | | |
| Operations and maintenance | | | 1,062 | | | | 419 | | | | 2,924 | | | | 1,058 | | | | 635 | |
| Impairment | | | 8,105 | | | | | | | | 8,105 | | | | | | | | | |
| Depreciation, depletion and amortization | | | 1,616 | | | | 1,164 | | | | 4,428 | | | | 2,453 | | | | 939 | |
| Total operating costs and expenses | | | 10,783 | | | | 1,583 | | | | 15,457 | | | | 3,511 | | | | 1,574 | |
| Operating income | | $ | (6,791 | ) | | $ | 1,423 | | | $ | (1,922 | ) | | $ | 3,809 | | | $ | 1,906 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Gulf of Mexico | | | | | | | | | | | | | | | | | | | | |
| Revenues: | | | | | | | | | | | | | | | | | | | | |
| Natural gas, NGLs, oil and condensate sales | | $ | 952 | | | $ | - | | | $ | 952 | | | $ | - | | | $ | - | |
| Gathering, compression, processing, and treating services | | | 703 | | | | - | | | | 703 | | | | - | | | | - | |
| Other | | | - | | | | - | | | | - | | | | - | | | | - | |
| Total revenues | | | 1,655 | | | | - | | | | 1,655 | | | | - | | | | - | |
| Cost of natural gas and NGLs | | | 1,376 | | | | - | | | | 1,376 | | | | - | | | | - | |
| Operating costs and expenses: | | | | | | | | | | | | | | | | | | | | |
| Operations and maintenance | | | 605 | | | | - | | | | 605 | | | | - | | | | - | |
| Depreciation, depletion and amortization | | | 1,521 | | | | - | | | | 1,521 | | | | - | | | | - | |
| Total operating costs and expenses | | | 2,126 | | | | - | | | | 2,126 | | | | - | | | | - | |
| Operating income | | $ | (1,847 | ) | | $ | - | | | $ | (1,847 | ) | | $ | - | | | $ | - | |
| (1) | Includes operations related to the Laser Acquisition beginning on May 3, 2007. |
| (2) | Includes operations related to the Millennium Acquisition beginning October 2, 2008 |
Eagle Rock Energy Partners, L.P.Segment Summary
Operating Income
($ in thousands)
(unaudited)
| | | Three Months Ended | | | Twelve Months Ended | | | Three Months | |
| | | Dec 31, | | | Dec. 31, | | | Ended | |
| | | 2008 | | | 2007 | | | 2008 | | | 2007 | | | Sept 30, 2008 | |
| | | | | | | | | | | | | | | | |
| Midstream | | | | | | | | | | | | | | | |
| Revenues: | | | | | | | | | | | | | | | |
| Natural gas, NGLs, oil and condensate sales | | $ | 236,269 | | | $ | 280,658 | | | $ | 1,326,647 | | | $ | 817,414 | | | $ | 366,368 | |
| Gathering, compression, processing and treating services | | | 11,130 | | | | 7,198 | | | | 38,871 | | | | 26,469 | | | | 12,513 | |
| Other | | | 13 | | | | - | | | | 15 | | | | (20 | ) | | | - | |
| Total revenues | | | 247,412 | | | | 287,856 | | | | 1,365,533 | | | | 843,863 | | | | 378,881 | |
| Cost of natural gas and NGLs | | | 208,530 | | | | 235,043 | | | | 1,154,707 | | | | 686,882 | | | | 316,788 | |
| Operating costs and expenses: | | | | | | | | | | | | | | | | | | | | |
| Operations and maintenance | | | 15,341 | | | | 10,272 | | | | 54,367 | | | | 44,481 | | | | 14,019 | |
| Impairment | | | 35,099 | | | | - | | | | 35,099 | | | | - | | | | - | |
| Depletion, depreciation and amortization | | | 18,951 | | | | 17,008 | | | | 63,196 | | | | 55,542 | | | | 14,912 | |
| Total operating costs and expenses | | | 69,391 | | | | 27,280 | | | | 152,662 | | | | 100,023 | | | | 28,931 | |
| Operating income | | $ | (30,509 | ) | | $ | 25,533 | | | $ | 58,164 | | | $ | 56,958 | | | $ | 33,162 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
Upstream (1) | | | | | | | | | | | | | | | | | | | | |
| Revenues: | | | | | | | | | | | | | | | | | | | | |
| Oil and condensate | | $ | 10,373 | | | $ | 15,286 | | | $ | 72,526 | | | $ | 24,874 | | | $ | 22,694 | |
| Natural gas | | | 8,159 | | | | 6,835 | | | | 32,513 | | | | 11,210 | | | | 11,168 | |
| NGLs | | | 4,006 | | | | 7,649 | | | | 29,530 | | | | 12,015 | | | | 8,059 | |
| Sulfur | | | 10,034 | | | | 1,848 | | | | 37,759 | | | | 2,588 | | | | 13,057 | |
| Other | | | 93 | | | | 1,078 | | | | 701 | | | | 1,078 | | | | 428 | |
| Total revenues | | | 32,665 | | | | 32,696 | | | | 173,029 | | | | 51,765 | | | | 55,406 | |
| Operating costs and expenses: | | | | | | | | | | | | | | | | | | | | |
| Operations and maintenance | | | 8,112 | | | | 10,059 | | | | 37,481 | | | | 15,881 | | | | 12,394 | |
| Impairment | | | 107,017 | | | | - | | | | 107,017 | | | | - | | | | - | |
| Goodwill Impairment | | | 30,994 | | | | - | | | | 30,994 | | | | - | | | | - | |
| Depreciation, depletion and amortization | | | 15,488 | | | | 9,339 | | | | 44,997 | | | | 16,235 | | | | 11,170 | |
| Total operating costs and expenses | | | 161,611 | | | | 19,398 | | | | 220,489 | | | | 32,116 | | | | 23,564 | |
| Operating income | | $ | (128,946 | ) | | $ | 13,298 | | | $ | (47,460 | ) | | $ | 19,649 | | | $ | 31,842 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | �� | | | | | | | | | | | |
Minerals (2) | | | | | | | | | | | | | | | | | | | | |
| Revenues: | | | | | | | | | | | | | | | | | | | | |
| Oil and condensate | | $ | 1,848 | | | $ | 2,916 | | | $ | 14,337 | | | $ | 7,529 | | | $ | 4,390 | |
| Natural gas | | | 1,633 | | | | 2,153 | | | | 10,451 | | | | 5,493 | | | | 3,044 | |
| NGLs | | | 317 | | | | 68 | | | | 1,376 | | | | 693 | | | | 413 | |
| Lease bonus, rentals and other | | | 4,590 | | | | 666 | | | | 16,830 | | | | 1,289 | | | | 9,546 | |
| Total revenues | | | 8,388 | | | | 5,803 | | | | 42,994 | | | | 15,004 | | | | 17,393 | |
| Operating costs and expenses: | | | | | | | | | | | | | | | | | | | | |
| Operations and maintenance | | | 356 | | | | 423 | | | | 1,708 | | | | 771 | | | | 427 | |
| Impairment | | | 1,741 | | | | 5,749 | | | | 1,741 | | | | 5,749 | | | | | |
| Depreciation, depletion and amortization | | | 1,314 | | | | 3,137 | | | | 7,774 | | | | 8,028 | | | | 2,321 | |
| Total operating costs and expenses | | | 3,411 | | | | 9,309 | | | | 11,223 | | | | 14,548 | | | | 2,748 | |
| Operating income | | $ | 4,977 | | | $ | (3,506 | ) | | $ | 31,771 | | | $ | 456 | | | $ | 14,645 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Corporate | | | | | | | | | | | | | | | | | | | | |
| Revenues: | | | | | | | | | | | | | | | | | | | | |
| Unrealized commodity derivative gains (losses) | | $ | 241,205 | | | $ | (100,240 | ) | | $ | 207,824 | | | $ | (130,773 | ) | | $ | 255,956 | |
| Realized commodity derivative gains ( losses) | | | 18,329 | | | | (7,385 | ) | | | (46,059 | ) | | | (3,061 | ) | | | (24,105 | ) |
| Total revenues | | | 259,534 | | | | (107,625 | ) | | | 161,765 | | | | (133,834 | ) | | | 231,851 | |
| General and administrative | | | 14,540 | | | | 11,212 | | | | 45,701 | | | | 27,799 | | | | 9,893 | |
| Depreciation, depletion and amortization | | | 202 | | | | 190 | | | | 787 | | | | 754 | | | | 194 | |
| Other operating expense | | | 565 | | | | 916 | | | | 10,699 | | | | 2,847 | | | | 3,920 | |
| Operating income (loss) | | $ | 244,227 | | | $ | (119,943 | ) | | $ | 104,578 | | | $ | (165,234 | ) | | $ | 217,844 | |
______________________________________________
| (1) | Includes operations from the EAC and Redman acquisitions beginning on August 1, 2007 and from the Stanolind acquisition beginning on May 1, 2008. |
| (2) | Includes operations from the Montierra acquisition beginning on May 1, 2007 and from the MacLondon acquisition beginning July 1, 2007. |
Eagle Rock Energy Partners, L.P.
Midstream Operations Information
(unaudited)
| | | Three Months Ended | | | Twelve Months Ended | | | Three Months | |
| | | Dec. 31, | | | Dec.31, | | | Ended | |
| | | 2008 | | | 2007 | | | 2008 | | | 2007 | | | Sept 30, 2008 | |
| | | | | | | | | | | | | | | | |
| Gas gathering volumes - (Average Mcf/d) | | | | | | | | | | | | | | | |
| Texas Panhandle | | | 144,155 | | | | 163,411 | | | | 151,964 | | | | 151,260 | | | | 159,254 | |
| East Texas/Louisiana | | | 275,592 | | | | 157,450 | | | | 198,365 | | | | 134,007 | | | | 173,728 | |
| South Texas | | | 111,111 | | | | 92,345 | | | | 88,488 | | | | 63,435 | | | | 80,097 | |
| Gulf of Mexico | | | 47,796 | | | | | | | | 12,014 | | | | | | | | | |
| Total | | | 578,654 | | | | 413,206 | | | | 450,831 | | | | 348,702 | | | | 413,079 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| NGLs and condensate - (Net equity gallons) | | | | | | | | | | | | | | | | | | | | |
| Texas Panhandle | | | 22,227,210 | | | | 23,694,310 | | | | 86,514,543 | | | | 88,973,113 | | | | 22,752,290 | |
| East Texas/Louisiana | | | 9,923,292 | | | | 5,746,483 | | | | 28,619,378 | | | | 18,320,082 | | | | 6,768,037 | |
| South Texas | | | 1,014,300 | | | | 246,668 | | | | 2,413,483 | | | | 436,490 | | | | 571,615 | |
| Gulf of Mexico | | | 176,962 | | | | - | | | | 176,962 | | | | - | | | | - | |
| Total | | | 33,341,764 | | | | 29,687,461 | | | | 117,547,404 | | | | 107,729,685 | | | | 30,091,942 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Natural gas short position - (Average MMbtu/d) | | | | | | | | | | | | | | | | | |
| Texas Panhandle | | | (6,054 | ) | | | (6,570 | ) | | | (5,607 | ) | | | (7,184 | ) | | | (4,150 | ) |
| East Texas/Louisiana | | | 3,041 | | | | (382 | ) | | | 1,427 | | | | 1,077 | | | | 747 | |
| South Texas | | | 500 | | | | 500 | | | | 500 | | | | 250 | | | | 500 | |
| Total | | | (2,513 | ) | | | (6,452 | ) | | | (3,680 | ) | | | (5,857 | ) | | | (2,903 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Average realized NGL price - per Bbl | | | | | | | | | | | | | | | | | | | | |
| Texas Panhandle | | $ | 28.89 | | | $ | 61.74 | | | $ | 58.34 | | | $ | 51.24 | | | $ | 66.36 | |
| East Texas/Louisiana | | $ | 29.37 | | | $ | 55.44 | | | $ | 54.66 | | | $ | 44.94 | | | $ | 57.54 | |
| South Texas | | $ | 32.52 | | | $ | 60.06 | | | $ | 52.66 | | | $ | 55.44 | | | $ | 83.16 | |
| Gulf of Mexico | | $ | 20.58 | | | $ | - | | | $ | 20.58 | | | $ | - | | | $ | - | |
| Weighted average | | $ | 29.34 | | | $ | 59.64 | | | $ | 56.77 | | | $ | 48.30 | | | $ | 64.26 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Average realized condensate price - per Bbl | | | | | | | | | | | | | | | | | | | | |
| Texas Panhandle | | $ | 64.53 | | | $ | 80.31 | | | $ | 94.27 | | | $ | 63.51 | | | $ | 106.43 | |
| East Texas/Louisiana | | $ | 63.18 | | | $ | 94.14 | | | $ | 101.62 | | | $ | 73.33 | | | $ | 125.29 | |
| South Texas | | $ | 53.40 | | | $ | 86.34 | | | $ | 92.10 | | | $ | 78.89 | | | $ | 112.20 | |
| Gulf of Mexico | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
| Weighted average | | $ | 64.00 | | | $ | 81.21 | | | $ | 94.82 | | | $ | 64.31 | | | $ | 108.23 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Average realized natural gas price - per MMbtu | | | | | | | | | | | | | | | | | |
| Texas Panhandle | | $ | 4.08 | | | $ | 6.60 | | | $ | 7.44 | | | $ | 6.08 | | | $ | 8.81 | |
| East Texas/Louisiana | | $ | 6.59 | | | $ | 6.62 | | | $ | 8.75 | | | $ | 6.54 | | | $ | 9.69 | |
| South Texas | | $ | 6.08 | | | $ | 6.46 | | | $ | 8.99 | | | $ | 6.38 | | | $ | 9.42 | |
| Gulf of Mexico | | $ | 6.64 | | | $ | - | | | $ | 6.64 | | | $ | - | | | $ | - | |
| Weighted average | | $ | 6.75 | | | $ | 6.31 | | | $ | 8.76 | | | $ | 6.25 | | | $ | 9.22 | |
Eagle Rock Energy Partners, L.P.
Upstream and Minerals Operations Information
(unaudited)
| | | Three Months Ended | | | Twelve Months Ended | | | Three Months | |
| | | Dec. 31, | | | Dec. 31, | | | Ended | |
| | | 2008 | | | 2007 | | | 2008 | | | 2007 | | | Sept. 30, 2008 | |
| | | | | | | | | | | | | | | | |
| Upstream | | | | | | | | | | | | | | | |
| Production: | | | | | | | | | | | | | | | |
| Oil and condensate (Bbl) | | | 214,988 | | | | 195,229 | | | | 831,631 | | | | 336,028 | | | | 230,727 | |
| Gas (Mcf) | | | 1,173,756 | | | | 917,981 | | | | 4,122,997 | | | | 1,584,279 | | | | 1,233,951 | |
| NGLs (Bbl) | | | 115,497 | | | | 123,833 | | | | 481,259 | | | | 212,061 | | | | 119,664 | |
| Total Mcfe | | | 3,156,666 | | | | 2,832,353 | | | | 12,000,337 | | | | 4,872,813 | | | | 3,336,297 | |
| | | | | | | | | | | | | | | | | | | | | |
| Sulfur (Long ton) | | | 33,024 | | | | 31,742 | | | | 104,795 | | | | 44,201 | | | | 25,816 | |
| | | | | | | | | | | | | | | | | | | | | |
| Realized prices, excluding derivatives: | | | | | | | | | | | | | | | | | | | | |
| Oil and condensate (per Bbl) | | $ | 48.25 | | | $ | 78.30 | | | $ | 87.21 | | | $ | 74.02 | | | $ | 98.36 | |
| Gas (per Mcf) | | $ | 6.95 | | | $ | 7.45 | | | $ | 7.89 | | | $ | 7.08 | | | $ | 9.05 | |
| NGLs (per Bbl) | | $ | 34.68 | | | $ | 61.77 | | | $ | 61.36 | | | $ | 56.66 | | | $ | 67.35 | |
| Sulfur (per Long ton) | | $ | 303.84 | | | $ | 58.22 | | | $ | 360.31 | | | $ | 58.55 | | | $ | 505.77 | |
| | | | - | | | | | | | | | | | | | | | | | |
| Operating statistics: | | | | | | | | | | | | | | | | | | | | |
| Operating costs per Mcfe (incl production taxes) | | $ | 2.57 | | | $ | 3.55 | | | $ | 3.12 | | | $ | 3.26 | | | $ | 3.71 | |
| Operating costs per Mcfe (excl production taxes) | | $ | 1.40 | | | $ | 2.64 | | | $ | 1.85 | | | $ | 2.35 | | | $ | 2.46 | |
| Operating Income per Mcfe | | $ | (40.85 | ) | | $ | 4.70 | | | $ | (3.95 | ) | | $ | 4.03 | | | $ | 9.54 | |
| | | | | | | | | | | | | | | | | | | | | |
| Drilling program (gross wells): | | | | | | | | | | | | | | | | | | | | |
| Development wells | | | 6 | | | | 2 | | | | 24 | | | | 2 | | | | 6 | |
| Completions | | | 5 | | | | 2 | | | | 23 | | | | 2 | | | | 6 | |
| Workovers | | | 1 | | | | 2 | | | | 13 | | | | 4 | | | | 11 | |
| Recompletions | | | 1 | | | | 1 | | | | 13 | | | | 1 | | | | 5 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Minerals | | | | | | | | | | | | | | | | | | | | |
| Production: | | | | | | | | | | | | | | | | | | | | |
| Oil and condensate (Bbl) | | | 35,407 | | | | 34,367 | | | | 156,118 | | | | 106,275 | | | | 42,004 | |
| Gas (Mcf) | | | 298,414 | | | | 323,576 | | | | 1,277,046 | | | | 872,176 | | | | 336,060 | |
| NGLs (Bbl) | | | 8,917 | | | | (762 | ) | | | 26,298 | | | | 14,862 | | | | 6,981 | |
| Total Mcfe | | | 564,358 | | | | 525,208 | | | | 2,371,542 | | | | 1,599,001 | | | | 629,970 | |
| | | | | | | | | | | | | | | | | | | | | |
| Realized prices, excluding derivatives: | | | | | | | | | | | | | | | | | | | | |
| Oil and condensate (per Bbl) | | $ | 52.19 | | | $ | 84.85 | | | $ | 91.83 | | | $ | 70.84 | | | $ | 104.62 | |
| Gas (per Mcf) | | $ | 5.47 | | | $ | 6.65 | | | $ | 8.18 | | | $ | 6.30 | | | $ | 9.36 | |
| NGLs (per Bbl) | | $ | 35.55 | | | $ | - | | | $ | 52.32 | | | $ | 46.63 | | | $ | 59.16 | |
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)
| Net income (loss) to adjusted EBITDA | | | | | | | | | |
| | | Three Months Ended | | | Twelve Months Ended | | | Three Months | |
| | | Dec. 31, | | | Dec. 31, | | | Ended | |
| | | 2008 | | | 2007 | | | 2008 | | | 2007 | | | Sept 30, 2008 | |
| | | | | | | | | | | | | | | | |
| Net income (loss), as reported | | $ | 54,797 | | | $ | (111,554 | ) | | $ | 87,520 | | | $ | (145,634 | ) | | $ | 288,071 | |
| | | | | | | | | | | | | | | | | | | | | |
| Depreciation, depletion and amortization expense | | | 35,955 | | | | 29,675 | | | | 116,754 | | | | 80,559 | | | | 28,597 | |
| Impairment | | | 174,851 | | | | 5,749 | | | | 174,851 | | | | 5,749 | | | | | |
| Risk management interest related instruments-unrealized | | | 27,245 | | | | 9,848 | | | | 27,717 | | | | 13,403 | | | | 501 | |
| Risk management commodity related instruments-unrealized, including amortization of commodity derivative costs | | | (241,205 | ) | | | 100,240 | | | | (207,824 | ) | | | 130,773 | | | | (255,956 | ) |
Other operating expenses (non-recurring) (1) | | | 565 | | | | 916 | | | | 10,699 | | | | 2,847 | | | | 3,920 | |
| Restricted units non-cash amortization expense | | | 3,547 | | | | 783 | | | | 7,694 | | | | 2,395 | | | | 1,427 | |
| Income tax provision (benefit) | | | 366 | | | | (603 | ) | | | (1,116 | ) | | | 169 | | | | (494 | ) |
| Interest - net including realized risk management instruments and other expense | | | 9,802 | | | | 17,508 | | | | 38,260 | | | | 44,587 | | | | 9,849 | |
| Non-recurring operations (1) | | | | | | | (795 | ) | | | | | | | (795 | ) | | | | |
| Other (income)/expense | | | (2,461 | ) | | | 183 | | | | (5,328 | ) | | | (696 | ) | | | (434 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Adjusted EBITDA | | $ | 63,462 | | | $ | 51,950 | | | $ | 249,227 | | | $ | 133,357 | | | $ | 75,481 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Net income (loss) to distributable cash flow | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Net income (loss), as reported | | $ | 54,797 | | | $ | (111,554 | ) | | $ | 87,520 | | | $ | (145,634 | ) | | $ | 288,071 | |
| | | | | | | | | | | | | | | | | | | | | |
| Depreciation, depletion and amortization expense | | | 35,955 | | | | 29,675 | | | | 116,754 | | | | 80,559 | | | | 28,597 | |
| Impairment | | | 174,851 | | | | 5,749 | | | | 174,851 | | | | 5,749 | | | | | |
| Risk management interest related instruments-unrealized | | | 27,245 | | | | 9,848 | | | | 27,717 | | | | 13,403 | | | | 501 | |
| Risk management commodity related instruments-unrealized, including amortization of commodity derivative costs | | | (241,205 | ) | | | 100,240 | | | | (207,824 | ) | | | 130,773 | | | | (255,956 | ) |
| Capital expenditures-maintenance related | | | (6,038 | ) | | | (6,406 | ) | | | (27,485 | ) | | | (15,627 | ) | | | (5,434 | ) |
| Write off bad debt | | | | | | | 6,215 | | | | | | | | 6,215 | | | | | |
| Loss on sale of investment | | | - | | | | | | | | - | | | | | | | | | |
| Restricted units non-cash amortization expense | | | 3,547 | | | | 782 | | | | 7,694 | | | | 2,395 | | | | 1,427 | |
Other operating expenses (non-recurring) (1) | | | 565 | | | | 121 | | | | 10,699 | | | | 2,052 | | | | - | |
| Income tax provision (benefit) | | | 366 | | | | (603 | ) | | | (1,116 | ) | | | 169 | | | | (494 | ) |
| Other (income)/expense | | | (2,461 | ) | | | 183 | | | | (5,328 | ) | | | (696 | ) | | | (434 | ) |
| Cash income taxes | | | (456 | ) | | | (288 | ) | | | (989 | ) | | | (724 | ) | | | (229 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Distributable cash flow | | $ | 47,166 | | | $ | 33,962 | | | $ | 182,493 | | | $ | 78,634 | | | $ | 56,049 | |
______________________________________________
| (1) | Includes: SemGroup bad debt expense for the three months and year ended December 31, 2008, a settlement of arbitration for $1.4 million and severance to a former executive of $0.3 million for the year ended December 31, 2007, and $0.9 million and $1.1 million of liquidated damages related to related to the late registration of our common units for the three months and year ended December 31, 2007, respectively, and other miscellaneous items of $0.8 million for the three months and year ended December 31, 2007. |
Supplemental Information
($ in thousands)
| | | Three Months Ended | | | Twelve Months Ended | | | Three Months | |
| | | Dec. 31, | | | Dec. 31, | | | Ended | |
| | | 2008 | | | 2007 | | | 2008 | | | 2007 | | | Sept 30, 2008 | |
| | | | | | | | | | | | | | | | |
| Amortization of commodity derivative costs | | | 6,510 | | | | 2,029 | | | | 13,288 | | | | 8,224 | | | | 2,259 | |
Oil and Natural Gas Reserves
Estimates of proved reserves at December 31, 2008, were prepared by Cawley, Gillespie & Associates, Inc. (“Cawley Gillespie”), the Partnership’s independent consulting petroleum engineers. All proved reserves are located in the United States of America.
The following table illustrates the Partnership’s estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by Cawley Gillespie. Natural gas liquids are included in oil reserves. Oil and natural gas liquids are based on the December 31, 2008 West Texas Intermediate posted price of $44.60 per barrel and are adjusted by lease for quality, transportation fees, and regional price differentials. Gas prices are based on a December 31, 2008 Henry Hub spot market price of $5.63 per MMBtu and are adjusted by lease for energy content, transportation fees, and regional price differentials. All prices are held constant in accordance with SEC guidelines.
| | | Proved Reserves | |
| | | | | | | | | | |
| | | | | | | | | Natural Gas | |
| | | Oil | | | Gas | | | Liquids | |
| | | (MBbls) | | | (MMcf) | | | (MBbls) | |
| | | | | | | | | | |
| Proved reserves, January 1, 2008 | | | 10,081 | | | | 44,643 | | | | 5,743 | |
| | | | | | | | | | | | | |
| Extensions and discoveries | | | 189 | | | | 3,566 | | | | 45 | |
| | | | | | | | | | | | | |
| Purchase of minerals in place | | | 3,512 | | | | 8,157 | | | | 1,432 | |
| | | | | | | | | | | | | |
| Production | | | 988 | | | | 5,400 | | | | 508 | |
| | | | | | | | | | | | | |
| Sale of minerals in place | | | 0 | | | | 0 | | | | 0 | |
| | | | | | | | | | | | | |
| Revision of previous estimates | | | (2,789 | ) | | | (6,378 | ) | | | (1,073 | ) |
| | | | | | | | | | | | | |
| Proved reserves, December 31, 2008 | | | 10,006 | | | | 44,588 | | | | 5,639 | |
| | | | | | | | | | | | | |
| | | Proved Developed Reserves | |
| | | | | | | | | | | | | |
| | | | | | | | | | | Natural Gas | |
| | | Oil | | | Gas | | | Liquids | |
| | | (MBbls) | | | (MMcf) | | | (MBbls) | |
| | | | | | | | | | | | | |
| December 31, 2008 | | | 9,200 | | | | 36,157 | | | | 4,883 | |
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