Exhibit 99.1
| November 4, 2008 | CONTACT: |
Elizabeth Wilkinson–Investor Relations Phone: 281-408-1329 |
Eagle Rock Energy Partners, L.P. Reports Record Third Quarter 2008 Results; Adjusted EBITDA of $75.5 million, Up 31.3% from $57.5 million in the Second Quarter; Resets Crude Oil Derivative Contracts
HOUSTON, TEXAS - Eagle Rock Energy Partners, L.P. (“Eagle Rock” or the “Partnership”) (NASDAQ: EROC) today announced its financial results for the three and nine months ended September 30, 2008.
Highlights:
The following are significant achievements for the third quarter of 2008 as compared to the second quarter of 2008:
| · | Adjusted EBITDA increased 31.3% to $75.5 million from $57.5 million. |
| · | Distributable Cash Flow increased 63.4% to $60.0 million representing a 200% coverage of the announced Q3 2008 distribution of $0.41 per unit. |
| · | Upstream asset base expanded – third quarter of 2008 results reflect first full-quarter impact of Permian Basin assets acquired in the Stanolind acquisition, closed April 30, 2008, whereas second quarter of 2008 included only two months impact of Permian Basin assets. |
| · | Commitments to senior secured credit facility increased by $180 million to $980 million, as previously announced. |
| · | Operating Income increased for all three lines of business: Midstream increased 2%; Upstream increased 20%; and Minerals increased 78%. |
The following are significant achievements for the third quarter of 2008 as compared to the third quarter of 2007:
| · | Adjusted EBITDA increased by 67.2% to $75.5 million from $45.2 million. |
| · | Distributable Cash Flow increased 87.9% to $60.0 million. |
| · | Quarterly distribution rate increased by 11.6% to $0.41 per common unit from $0.3675 per common unit. |
| · | Upstream asset base expanded – third quarter of 2008 results include full-quarter financial results for assets acquired in the Escambia, Redman and Stanolind acquisitions, whereas third quarter of 2007 included only two months of Escambia and Redman assets. |
| · | Operating income from the Minerals Business increased 503% due to record leasing activity and higher commodity prices. |
| · | Increased the Midstream Business’s equity share of natural gas liquid (“NGL”) and condensate production by 5.4%. |
For the third quarter of 2008, the Partnership reported revenues (excluding unrealized, non-cash, mark-to-market commodity derivative gains and losses) of $427.6 million versus $268.0 million for the third quarter of 2007 and $442.5 million for the second quarter of 2008. Adjusted EBITDA (see “Use of Non-GAAP Financial Measures” below) for the third quarter of 2008 was $75.5 million as compared to $45.2 million in the same quarter of 2007 and $57.5 million in the second quarter of 2008.
The 59.5% improvement in revenues (excluding unrealized, non-cash, mark-to-market commodity derivative gains) and the 67.2% improvement in Adjusted EBITDA in the third quarter of 2008 over the third quarter of 2007 are the result of the Partnership’s expanded upstream asset base, the positive impact of organic growth projects in the Partnership’s Midstream Business, higher commodity prices, and a significant gross lease bonus of $8.5 million recorded by the Partnership’s Minerals Business. Upstream revenues of $55.4 million were up 191% over the third quarter of 2007 due to the full-quarter impact of the Escambia, Redman and Stanolind acquisitions and higher commodity prices. Midstream NGL and condensate equity volumes were up 5.4% as compared to the third quarter of 2007 primarily due to increased gathered volumes under an attractive contract in the East Texas/Louisiana Segment. In addition, the lease bonus recorded by the Minerals Business in the third quarter of 2008 was related to the leasing of substantial acreage in the Haynesville play of East Texas and North Louisiana by a third-party partnership in which the Partnership’s Minerals Business has an investment.
Revenues (excluding unrealized, non-cash, mark-to-market commodity derivative gains and losses) of $427.6 million were essentially flat in the third quarter of 2008 versus the second quarter of 2008. Increased midstream and upstream volumes and the minerals lease bonus (mentioned above) were offset by lower realized prices, as well as the impact of Hurricane Ike on the East Texas/Louisiana and South Texas Segments. Specifically, the Brookeland processing facility located in East Texas was shut down for 9 days during and following Hurricane Ike due to mandatory evacuations in the area and damage to third-party downstream liquid pipeline infrastructure. The South Texas Segment was also affected by the complete shutdown of the Phase 1 20” pipeline due to the disruption of NGL pipeline infrastructure from the third-party plants in which the Partnership processes natural gas. Midstream NGL and condensate volumes were up 12.9% due to increased gathered volumes under an attractive contract in the East Texas/Louisiana Segment and the completion of the consolidation of the Stinnett and Cargray Plants in the Texas Panhandle Segment. Upstream volumes resumed normal levels in the third quarter of 2008 following the downtime experienced during the second quarter of 2008 related to the scheduled Big Escambia Creek (“BEC”) treating plant turnaround and subsequent lightning strike, as previously disclosed, and were further enhanced by the first full-quarter impact of the Permian Basin assets acquired in the Stanolind acquisition. Adjusted EBITDA increased 31.3% to $75.5 million primarily due to the combined impact of the increases in Upstream production, the significant lease bonus recorded by the Minerals Segment, and lower realized losses on commodity derivatives.
Distributable Cash Flow (see “Use of Non-GAAP Financial Measures” below) for the third quarter of 2008 totaled $60.0 million compared to $36.7 million for the second quarter of 2008, an increase of 63.4%. The increase in Distributable Cash Flow is primarily related to increased Adjusted EBITDA, the resumption of a normalized level of maintenance capital expenditures following completion of the BEC treating facility turnaround in the second quarter of 2008 and lower well recompletion and workover costs in the Upstream Segment. In the third quarter of 2008, Distributable Cash Flow represents 200% coverage of the announced third quarter of 2008 distribution of $0.41 per unit based on total units outstanding. The Board of Directors has established a reserve against Available Cash (as defined in the Partnership’s partnership agreement) for the third quarter of 2008, for expenditures in future periods.
On October 31, 2008, the Partnership used a portion of the reserve against Available Cash to reset two existing crude oil swap derivative contracts. The first swap was reset from $73.90 to $100 per barrel on 80,000 barrels per month for the months of November and December, 2008. The second swap was reset from $80.25 to $100 per barrel on 50,000 barrels per month for all of calendar year 2009. The total cost of these reset swaps was $15.9 million to the Partnership. The strike prices of these swaps were reset to stabilize overall cash flows for the balance of 2008 and all of 2009 and to provide further assurance of the Partnership’s ability to maintain its current rate of distribution in the face of declining commodity prices and industry activity.
Chairman and Chief Executive Officer, Joseph A. Mills said, “Eagle Rock delivered another record quarter of financial performance, including the first full-quarter financial impact of our new Permian Basin assets. In light of the significant deterioration of the commodity price environment, anticipated reduced drilling activity by our producers, and difficult credit and capital markets, the Partnership’s management and the Board of Directors determined it prudent to hold our quarterly distribution flat for the current quarter in order to preserve our liquidity going forward and to provide further assurances of our ability to maintain our quarterly distributions. As an example, we recently reset two crude oil swap derivative contracts related to the months of November and December of 2008 and the entire calendar 2009, respectively, to $100 per barrel with a total cost to the Partnership of $15.9 million, which we funded through the cash reserve established by the Board of Directors from the excess coverage in the third quarter. In addition, we upsized our credit facility during the quarter from $800 million to the current $980 million. Today, we have approximately $175 million of unused capacity in our senior revolver facility (adjusted for Lehman’s Brother’s $5.5 million remaining commitment which we anticipate will not be funded when called) to fund future capital and operating expenses, if necessary. Further, we are carefully reevaluating our slate of organic growth capital projects to ensure that our capital and liquidity are put to their best and most profitable use, and we are meticulously reviewing and trimming our operating and general and administrative cost structures. With these initiatives and our improved hedging positions, we feel confident in our ability to maintain the distribution level until we see a return to normalized conditions in the commodity and capital markets and improvement in our customers’ drilling plans.”
Unit Distributions
The Partnership recently announced its cash distribution for the third quarter of 2008. Such distribution will be paid November 14, 2008 at the rate of $0.41 per unit, or a $1.64 per unit annualized rate, to all holders of record as of November 7, 2008, and such distribution will be paid on all units outstanding except for the 4,000,000 units issued on October 1, 2008 to the sellers in the Millennium acquisition.
Net Income (Loss)
The Partnership also reported net income for the third quarter of 2008 of $288.1 million versus net income of $9.4 million in the third quarter of 2007 and a net loss of $227.0 million in the second quarter of 2008. Included in the net income for the third quarter of 2008 were $256.0 million of unrealized, non-cash, mark-to-market derivative gains versus $8.9 million of gains in the third quarter of 2007 and $256.3 million of unrealized, non-cash, mark-to-market derivative losses in the second quarter of 2008. The change from a loss of $256.3 million to a gain of $256.0 million in the Partnership’s unrealized, non-cash, mark-to-market derivative positions from the second quarter of 2008 to the third quarter of 2008 accounts for the bulk of the difference in net income (loss) between those periods and is a direct result of the volatility in commodity prices experienced in the last two quarters, with an overall movement downward in commodity prices from the second quarter to the third quarter. Also affecting our third quarter 2008 net income is the recording of a $3.9 million bad debt reserve against receivables associated with the bankruptcy of SemGroup, L.P. and certain related subsidiaries and a $1.4 million non-cash charge related to prior period adjustments in our Upstream Business.
Mark-to-Market Accounting and Derivative Collateral
The Partnership does not designate its derivatives as “hedges” for accounting purposes but utilizes mark-to-market accounting for its derivatives. Mark-to-market accounting requires the changes in the fair value of derivatives, both positive and negative, to be included in the statement of operations for the respective periods. All of the Partnership's derivatives have been entered into by the Partnership in order to reduce the Partnership's underlying exposure to commodity prices and interest rates. The Partnership does not speculate on commodity prices or interest rates, as it anticipates having, based on its forecasts, the physical volumes and debt outstanding to support its outstanding commodity and interest rate derivatives, respectively. Substantially all of the Partnership’s counterparties to its derivatives are participating lenders in its revolving credit facility and have their outstanding debt commitment and derivative exposure collateralized pursuant to the revolving credit facility. The Partnership does not have any exposure to “margin calls” on its derivative instruments while its counterparties are participating lenders in its revolving credit facility.
Conference Call
Eagle Rock will hold a conference call to discuss its third quarter financial results and recent developments on Wednesday, November 5, 2008, at 9 a.m. Central Time (10 a.m. Eastern 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 888-713-4215, confirmation code 15166443. 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 moments 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=PNJYTT6CL. (Due to its length, this URL may need to be copied/pasted into your internet browser’s address field. Remove the extra space if one exists.) An audio replay of the conference call will also be available for seven days by dialing 888-286-8010, confirmation code 23540278. In addition, a replay of the audio webcast will be available by accessing the Partnership's website after the call is concluded.
The Partnership is a growth-oriented master limited partnership engaged in three businesses: a) midstream, which includes (i) gathering, compressing, treating, processing, transporting and selling natural gas, and (ii) fractionating and transporting natural gas liquids; b) upstream, which includes acquiring, exploiting, developing, and producing 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 uses non-GAAP financial measures as measures of its core profitability or to assess the financial performance of its assets. Eagle Rock believes that investors benefit from having access to the same financial measures that its management uses in evaluating 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). Adjusted EBITDA is used as a supplemental financial measure by external users of Eagle Rock’s financial statements such as investors, commercial banks and research analysts. 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. Eagle Rock has reconciled Adjusted EBITDA to net income (loss).
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 basic cash flows generated by the Partnership (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. Distributable Cash Flow is also an important non-GAAP financial measure for unitholders since it serves as an indicator of the Partnership’s success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not the Partnership is generating cash flow at a level that can sustain or support an increase in quarterly distribution rates. Distributable Cash Flow is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies because the value of a unit of such an entity generally is related to the amount of cash distributions the entity can pay to its unitholders. 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 Distributed Cash Flow (and Adjusted EBITDA, on which it builds) in the same manner as Eagle Rock. Eagle Rock has reconciled Distributable Cash Flow to net income/(loss).
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.
Eagle Rock Energy Partners, L.P.
Consolidated Statements of Operations
($ in thousands)
(unaudited)
| Three Months | Nine Months | Three Months | ||||||||||||||||||
| Ended Sept. 30, | Ended Sept. 30, | Ended | ||||||||||||||||||
| 2008 | 2007 | 2008 | 2007 | June 30, 2008 | ||||||||||||||||
| REVENUE: | ||||||||||||||||||||
Natural gas, natural gas liquids, condensate, oil and sulfur sales | $ | 421,346 | $ | 254,084 | $ | 1,230,134 | $ | 555,826 | $ | 451,769 | ||||||||||
| Gathering, compression and processing fees | 12,513 | 8,103 | 27,741 | 19,269 | 8,085 | |||||||||||||||
| Minerals and royalty income | 17,393 | 6,009 | 34,606 | 9,201 | 10,255 | |||||||||||||||
| Unrealized commodity derivative gains (losses) | 255,956 | 8,865 | (33,381 | ) | (30,533 | ) | (256,265 | ) | ||||||||||||
| Realized commodity derivative gains (losses) | (24,105 | ) | (177 | ) | (64,388 | ) | 4,324 | (27,708 | ) | |||||||||||
| Other income | 428 | (20 | ) | 610 | (20 | ) | 122 | |||||||||||||
| Total Revenue | 683,531 | 276,864 | 1,195,322 | 558,067 | 186,258 | |||||||||||||||
| COSTS AND EXPENSES: | ||||||||||||||||||||
| Cost of natural gas and natural gas liquids | 316,788 | 196,839 | 946,177 | 451,840 | 353,558 | |||||||||||||||
| Operations and maintenance | 21,475 | 16,883 | 54,772 | 36,015 | 17,731 | |||||||||||||||
| Taxes other than income | 5,365 | 2,746 | 14,975 | 4,364 | 5,263 | |||||||||||||||
| General and administrative | 9,893 | 7,196 | 31,161 | 16,587 | 10,026 | |||||||||||||||
| Other operating | 3,920 | 220 | 10,134 | 1,931 | 6,214 | |||||||||||||||
| Depreciation, depletion and amortization | 28,597 | 25,105 | 80,799 | 50,883 | 26,457 | |||||||||||||||
| Total Costs and Expenses | 386,038 | 248,989 | 1,138,018 | 561,620 | 419,249 | |||||||||||||||
| OPERATING INCOME ( LOSS) | 297,493 | 27,875 | 57,304 | (3,553 | ) | (232,991 | ) | |||||||||||||
| Other Income (Expense): | ||||||||||||||||||||
| Interest income | 212 | 231 | 673 | 530 | 160 | |||||||||||||||
| Other income | 434 | 767 | 2,867 | 879 | 886 | |||||||||||||||
| Interest expense, net | (7,498 | ) | (10,633 | ) | (23,576 | ) | (27,031 | ) | (6,974 | ) | ||||||||||
| Unrealized interest rate derivative gains (losses) | (501 | ) | (8,429 | ) | (472 | ) | (3,555 | ) | 13,689 | |||||||||||
| Realized interest rate derivative gains (losses) | (2,358 | ) | 327 | (4,903 | ) | 967 | (2,444 | ) | ||||||||||||
| Other expense | (205 | ) | (415 | ) | (652 | ) | (1,545 | ) | (232 | ) | ||||||||||
| Total Other Income (Expense) | (9,916 | ) | (18,152 | ) | (26,063 | ) | (29,755 | ) | 5,085 | |||||||||||
| INCOME (LOSS) BEFORE INCOME TAXES | 287,577 | 9,723 | 31,241 | (33,308 | ) | (227,906 | ) | |||||||||||||
| Income tax (benefit) provision | (494 | ) | 352 | (1,482 | ) | 772 | (886 | ) | ||||||||||||
| NET INCOME ( LOSS) | $ | 288,071 | $ | 9,371 | $ | 32,723 | $ | (34,080 | ) | $ | (227,020 | ) | ||||||||
| Eagle Rock Energy Partners, L.P. | ||||||||
| Consolidated Balance Sheets | ||||||||
| ($ in thousands) | ||||||||
| (unaudited) | ||||||||
| Sept 30, | December 31, | |||||||
| 2008 | 2007 | |||||||
| Assets | ||||||||
| Current assets: | ||||||||
| Cash and cash equivalents | $ | 229,104 | $ | 68,552 | ||||
| Accounts receivable | 138,146 | 135,633 | ||||||
| Risk management assets | 5,239 | - | ||||||
| Prepayments and other current assets | 2,344 | 3,992 | ||||||
| 374,833 | 208,177 | |||||||
| Property plant and equipment - net | 1,310,422 | 1,207,130 | ||||||
| Intangible assets - net | 141,414 | 153,948 | ||||||
| Goodwill | 29,890 | 29,527 | ||||||
| Risk management assets | 2,589 | |||||||
| Other assets | 13,938 | 11,145 | ||||||
| Total assets | $ | 1,873,086 | $ | 1,609,927 | ||||
| Liabilities and Members' Equity | ||||||||
| Current liabilities: | ||||||||
| Accounts payable | $ | 137,893 | $ | 132,485 | ||||
| Due to affiliate | 16,405 | 16,964 | ||||||
| Accrued liabilities | 15,074 | 9,776 | ||||||
| Taxes payable | 1,009 | 723 | ||||||
| Risk management liabilities | 60,823 | 33,089 | ||||||
| 231,204 | 193,037 | |||||||
| Long-term debt | 799,383 | 567,069 | ||||||
| Asset retirement obligations | 17,062 | 11,337 | ||||||
| Deferred tax liability | 42,508 | 17,516 | ||||||
| Risk management liabilities | 107,750 | 94,200 | ||||||
| Members' equity | ||||||||
| Common unitholders | 580,888 | 617,563 | ||||||
| Subordinated unitholders | 98,040 | 112,360 | ||||||
| General partner | (3,749 | ) | (3,155 | ) | ||||
| 675,179 | 726,768 | |||||||
| Total Liabilities and Members' Equity | $ | 1,873,086 | $ | 1,609,927 | ||||
Eagle Rock Energy Partners, L.P.
Midstream Segment
Operating Income
($ in thousands)
(unaudited)
| Three Months Ended | Nine Months Ended | Three Months | ||||||||||||||||||
| Sept 30, | Sept 30, | Ended | ||||||||||||||||||
| 2008 | 2007 | 2008 | 2007 | June 30, 2008 | ||||||||||||||||
| Texas Panhandle | ||||||||||||||||||||
| Revenues: | ||||||||||||||||||||
| Sales of natural gas, NGLs, oil and condensate | $ | 179,608 | $ | 128,008 | $ | 514,450 | $ | 328,672 | $ | 180,987 | ||||||||||
| Gathering and treating services | 2,671 | 2,234 | 7,664 | 6,536 | 2,524 | |||||||||||||||
| Other | - | (20 | ) | - | (20 | ) | - | |||||||||||||
| Total revenues | 182,279 | 130,222 | 522,114 | 335,188 | 183,511 | |||||||||||||||
| Cost of natural gas and natural gas liquids | 138,428 | 96,872 | 398,828 | 258,577 | 140,282 | |||||||||||||||
| Operating costs and expenses: | ||||||||||||||||||||
| Operations and maintenance | 9,190 | 9,603 | 25,653 | 25,608 | 8,715 | |||||||||||||||
| Depreciation, depletion and amortization | 10,984 | 10,466 | 32,587 | 30,231 | 10,894 | |||||||||||||||
| Total operating costs and expenses | 20,174 | 20,069 | 58,240 | 55,839 | 19,609 | |||||||||||||||
| Operating income | $ | 23,677 | $ | 13,281 | $ | 65,046 | $ | 20,772 | $ | 23,620 | ||||||||||
East Texas/Louisiana (1) | ||||||||||||||||||||
| Revenues: | ||||||||||||||||||||
| Sales of natural gas, NGLs, oil and condensate | $ | 71,861 | $ | 44,215 | $ | 231,996 | $ | 95,409 | $ | 93,176 | ||||||||||
| Gathering and treating services | 8,908 | 4,352 | 17,056 | 10,284 | 4,700 | |||||||||||||||
| Total revenues | 80,769 | 48,567 | 249,052 | 105,693 | 97,876 | |||||||||||||||
| Cost of natural gas and natural gas liquids | 66,007 | 38,397 | 209,937 | 82,491 | 83,911 | |||||||||||||||
| Operating costs and expenses: | - | |||||||||||||||||||
| Operations and maintenance | 4,194 | 3,619 | 11,511 | 7,778 | 3,837 | |||||||||||||||
| Depreciation, depletion and amortization | 2,989 | 3,281 | 8,846 | 7,213 | 2,988 | |||||||||||||||
| Total operating costs and expenses | 7,183 | 6,900 | 20,357 | 14,991 | 6,825 | |||||||||||||||
| Operating income | $ | 7,579 | $ | 3,270 | $ | 18,758 | $ | 8,211 | $ | 7,140 | ||||||||||
South Texas (1) | ||||||||||||||||||||
| Revenues: | ||||||||||||||||||||
| Sales of natural gas, NGLs, oil and condensate | $ | 114,899 | $ | 62,792 | 343,932 | $ | 112,676 | $ | 131,794 | |||||||||||
| Gathering and treating services | 934 | 1,517 | 3,021 | 2,409 | 861 | |||||||||||||||
| Other | - | - | 2 | - | - | |||||||||||||||
| Total revenues | 115,833 | 64,309 | 346,955 | 115,085 | 132,655 | |||||||||||||||
| Cost of natural gas and natural gas liquids | 112,353 | 61,570 | 337,412 | 110,772 | 129,365 | |||||||||||||||
| Operating costs and expenses: | ||||||||||||||||||||
| Operations and maintenance | 635 | 394 | 1,862 | 688 | 574 | |||||||||||||||
| Depreciation, depletion and amortization | 939 | 910 | 2,812 | 1,289 | 934 | |||||||||||||||
| Total operating costs and expenses | 1,574 | 1,304 | 4,674 | 1,977 | 1,508 | |||||||||||||||
| Operating income | $ | 1,906 | $ | 1,435 | $ | 4,869 | $ | 2,336 | $ | 1,782 | ||||||||||
_________________________________________________
(1) Includes operations related to the Laser Acquisition starting on May 3, 2007.
Eagle Rock Energy Partners, L.P.
Segment Summary
Operating Income
($ in thousands)
(unaudited)
| Three Months Ended | Nine Months Ended | Three Months | ||||||||||||||||||
| Sept 30, | Sept 30, | Ended | ||||||||||||||||||
| 2008 | 2007 | 2008 | 2007 | June 30, 2008 | ||||||||||||||||
| Midstream | ||||||||||||||||||||
| Revenues: | ||||||||||||||||||||
| Sales of natural gas, NGLs, oil and condensate | $ | 366,368 | $ | 235,015 | $ | 1,090,378 | $ | 536,757 | $ | 405,957 | ||||||||||
| Gathering and treating services | 12,513 | 8,103 | 27,741 | 19,269 | 8,085 | |||||||||||||||
| Other | - | (20 | ) | 2 | (20 | ) | - | |||||||||||||
| Total revenues | 378,881 | 243,098 | 1,118,121 | 556,006 | 414,042 | |||||||||||||||
| Cost of natural gas and natural gas liquids | 316,788 | 196,839 | 946,177 | 451,840 | 353,558 | |||||||||||||||
| Operating costs and expenses: | ||||||||||||||||||||
| Operations and maintenance | 14,019 | 13,616 | 39,026 | 34,074 | 13,126 | |||||||||||||||
| Depletion, depreciation and amortization | 14,912 | 14,657 | 44,245 | 38,733 | 14,816 | |||||||||||||||
| Total operating costs and expenses | 28,931 | 28,273 | 83,271 | 72,807 | 27,942 | |||||||||||||||
| Operating income | $ | 33,162 | $ | 17,986 | $ | 88,673 | $ | 31,359 | $ | 32,542 | ||||||||||
Upstream (1) | ||||||||||||||||||||
| Revenues: | ||||||||||||||||||||
| Oil and condensate | $ | 22,694 | $ | 9,588 | $ | 62,153 | $ | 9,588 | $ | 21,126 | ||||||||||
| Natural gas | 11,168 | 4,375 | 27,725 | 4,375 | 9,431 | |||||||||||||||
| NGLs | 8,059 | 4,366 | 24,354 | 4,366 | 8,155 | |||||||||||||||
| Sulfur | 13,057 | 740 | 25,524 | 740 | 7,100 | |||||||||||||||
| Income fees and other | - | - | - | - | - | |||||||||||||||
| Other | 428 | - | 608 | - | 122 | |||||||||||||||
| Total revenues | 55,406 | 19,069 | 140,364 | 19,069 | 45,934 | |||||||||||||||
| Operating costs and expenses: | ||||||||||||||||||||
| Operations and maintenance | 12,394 | 5,792 | 29,369 | 5,792 | 9,386 | |||||||||||||||
| Depreciation, depletion and amortization | 11,170 | 6,897 | 29,509 | 6,897 | 9,914 | |||||||||||||||
| Total operating costs and expenses | 23,564 | 12,689 | 58,878 | 12,689 | 19,300 | |||||||||||||||
| Operating income | $ | 31,842 | $ | 6,380 | $ | 81,486 | $ | 6,380 | $ | 26,634 | ||||||||||
Minerals (2) | ||||||||||||||||||||
| Revenues: | ||||||||||||||||||||
| Oil and condensate | $ | 4,390 | $ | 3,080 | $ | 12,489 | $ | 4,613 | $ | 4,732 | ||||||||||
| Natural gas | 3,044 | 1,850 | 8,818 | 3,340 | 3,565 | |||||||||||||||
| NGLs | 413 | 527 | 1,059 | 625 | 411 | |||||||||||||||
| Lease bonus, rentals and other | 9,546 | 552 | 12,240 | 623 | 1,547 | |||||||||||||||
| Total revenues | 17,393 | 6,009 | 34,606 | 9,201 | 10,255 | |||||||||||||||
| Operating costs and expenses: | ||||||||||||||||||||
| Operations and maintenance | 427 | 221 | 1,352 | 513 | 482 | |||||||||||||||
| Depreciation, depletion and amortization | 2,321 | 3,358 | 6,460 | 4,890 | 1,528 | |||||||||||||||
| Total operating costs and expenses | 2,748 | 3,579 | 7,812 | 5,403 | 2,010 | |||||||||||||||
| Operating income | $ | 14,645 | $ | 2,430 | $ | 26,794 | $ | 3,798 | $ | 8,245 | ||||||||||
| Corporate | ||||||||||||||||||||
| Revenues: | ||||||||||||||||||||
| Unrealized commodity derivative gains (losses) | $ | 255,956 | $ | 8,865 | $ | (33,381 | ) | $ | (30,533 | ) | $ | (256,265 | ) | |||||||
| Realized commodity derivative gains ( losses) | (24,105 | ) | (177 | ) | (64,388 | ) | 4,324 | (27,708 | ) | |||||||||||
| Total revenues | 231,851 | 8,688 | (97,769 | ) | (26,209 | ) | (283,973 | ) | ||||||||||||
| General and administrative | 9,893 | 7,196 | 31,161 | 16,587 | 10,026 | |||||||||||||||
| Depreciation, depletion and amortization | 194 | 193 | 585 | 564 | 199 | |||||||||||||||
| Other operating expense | 3,920 | 220 | 10,134 | 1,931 | 6,214 | |||||||||||||||
| Operating income (loss) | $ | 217,844 | $ | 1,079 | $ | (139,649 | ) | $ | (45,291 | ) | $ | (300,412 | ) | |||||||
______________________________________________________
| (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 starting July 1, 2007. |
Eagle Rock Energy Partners, L.P.
Consolidated Segment Summary
($ in thousands)
(unaudited)
| Three Months Ended | Nine Months Ended | Three Months | ||||||||||||||||||
| Sept 30, | Sept 30, | Ended | ||||||||||||||||||
| 2008 | 2007 | 2008 | 2007 | June 30, 2008 | ||||||||||||||||
| Total | ||||||||||||||||||||
| Revenues: | ||||||||||||||||||||
| Sales of natural gas, NGLs, oil, condensate and sulfur | $ | 421,346 | $ | 254,084 | $ | 1,230,134 | $ | 555,826 | $ | 451,769 | ||||||||||
| Gathering and treating services | 12,513 | 8,103 | 27,741 | 19,269 | 8,085 | |||||||||||||||
| Minerals and royalty income | 17,393 | 6,009 | 34,606 | 9,201 | 10,255 | |||||||||||||||
| Unrealized commodity derivative gains (losses) | 255,956 | 8,865 | (33,381 | ) | (30,533 | ) | (256,265 | ) | ||||||||||||
| Realized commodity derivative gains (losses) | (24,105 | ) | (177 | ) | (64,388 | ) | 4,324 | (27,708 | ) | |||||||||||
| Other | 428 | (20 | ) | 610 | (20 | ) | 122 | |||||||||||||
| Total revenues | 683,531 | 276,864 | 1,195,322 | 558,067 | 186,258 | |||||||||||||||
| Cost of natural gas and natural gas liquids | 316,788 | 196,839 | 946,177 | 451,840 | 353,558 | |||||||||||||||
| Costs and expenses: | ||||||||||||||||||||
| Operating | 21,475 | 16,883 | 54,772 | 36,015 | 17,731 | |||||||||||||||
| Taxes other than income | 5,365 | 2,746 | 14,975 | 4,364 | 5,263 | |||||||||||||||
| General and administrative | 9,893 | 7,196 | 31,161 | 16,587 | 10,026 | |||||||||||||||
| Other expense | 3,920 | 220 | 10,134 | 1,931 | 6,214.00 | |||||||||||||||
| Depreciation, depletion and amortization | 28,597 | 25,105 | 80,799 | 50,883 | 26,457 | |||||||||||||||
| Total costs and expenses | 69,250 | 52,150 | 191,841 | 109,780 | 65,691 | |||||||||||||||
| Operating income (loss) | 297,493 | 27,875 | 57,304 | (3,553 | ) | (232,991 | ) | |||||||||||||
| Other income (expense): | ||||||||||||||||||||
| Interest income | 212 | 231 | 673 | 530 | 160 | |||||||||||||||
| Other income | 434 | 767 | 2,867 | 879 | 886 | |||||||||||||||
| Interest expense | (7,498 | ) | (10,633 | ) | (23,576 | ) | (27,031 | ) | (6,974 | ) | ||||||||||
| Unrealized interest rate derivative gains (losses) | (501 | ) | (8,429 | ) | (472 | ) | (3,555 | ) | 13,689 | |||||||||||
| Realized interest rate derivative gains (losses) | (2,358 | ) | 327 | (4,903 | ) | 967 | (2,444 | ) | ||||||||||||
| Other income (expense) | (205 | ) | (415 | ) | (652 | ) | (1,545 | ) | (232 | ) | ||||||||||
| Total other income (expense) | (9,916 | ) | (18,152 | ) | (26,063 | ) | (29,755 | ) | 5,085 | |||||||||||
| Income (loss) before income taxes | 287,577 | 9,723 | 31,241 | (33,308 | ) | (227,906 | ) | |||||||||||||
| Income tax (benefit) provision | (494 | ) | 352 | (1,482 | ) | 772 | (886 | ) | ||||||||||||
| Net income (loss) | $ | 288,071 | $ | 9,371 | $ | 32,723 | $ | (34,080 | ) | $ | (227,020 | ) | ||||||||
| Adjusted EBITDA | $ | 75,481 | $ | 45,155 | $ | 185,765 | $ | 81,407 | $ | 57,504 | ||||||||||
Eagle Rock Energy Partners, L.P.
Midstream Operations Information
(unaudited)
| Three Months Ended | Nine Months Ended | Three Months | ||||||||||||||||||
| Sept 30, | Sept 30, | Ended | ||||||||||||||||||
| 2008 | 2007 | 2008 | 2007 | June 30, 2008 | ||||||||||||||||
| Gas gathering volumes - (Average Mcf/d) | ||||||||||||||||||||
| Texas Panhandle | 159,254 | 164,544 | 154,190 | 147,523 | 149,881 | |||||||||||||||
| East Texas/Louisiana | 173,728 | 155,540 | 172,434 | 125,590 | 179,744 | |||||||||||||||
| South Texas | 80,097 | 99,266 | 81,228 | 55,853 | 84,514 | |||||||||||||||
| Total | 413,079 | 419,350 | 407,852 | 328,966 | 414,139 | |||||||||||||||
| NGLs and condensate - (Net equity gallons) | ||||||||||||||||||||
| Texas Panhandle | 22,752,290 | 23,644,648 | 64,287,333 | 65,278,803 | 19,650,791 | |||||||||||||||
| East Texas/Louisiana | 6,768,037 | 4,742,723 | 18,696,086 | 12,573,603 | 6,624,451 | |||||||||||||||
| South Texas | 571,615 | 162,876 | 1,399,183 | 162,876 | 377,706 | |||||||||||||||
| Total | 30,091,942 | 28,550,247 | 84,382,602 | 78,015,282 | 26,652,948 | |||||||||||||||
| Natural gas short position - (Average MMBtu/d) | ||||||||||||||||||||
| Texas Panhandle | (4,150 | ) | (6,330 | ) | (5,458 | ) | (7,389 | ) | (4,974 | ) | ||||||||||
| East Texas/Louisiana | 747 | 1,116 | 885 | 1,485 | 1,543 | |||||||||||||||
| South Texas | 500 | 500 | 500 | 167 | 500 | |||||||||||||||
| Total | (2,903 | ) | (4,714 | ) | (4,073 | ) | (5,737 | ) | (2,931 | ) | ||||||||||
| Average realized NGL price - per Bbl | ||||||||||||||||||||
| Texas Panhandle | $ | 66.36 | $ | 53.34 | $ | 67.62 | $ | 48.72 | $ | 74.76 | ||||||||||
| East Texas/Louisiana | $ | 57.54 | $ | 44.52 | $ | 56.28 | $ | 41.58 | $ | 58.80 | ||||||||||
| South Texas | $ | 83.16 | $ | 63.42 | $ | 77.70 | $ | 63.42 | $ | 72.66 | ||||||||||
| Weighted average | $ | 64.26 | $ | 50.82 | $ | 64.26 | $ | 47.04 | $ | 69.30 | ||||||||||
| Average realized condensate price - per Bbl | ||||||||||||||||||||
| Texas Panhandle | $ | 106.43 | $ | 63.41 | $ | 105.03 | $ | 54.62 | $ | 117.93 | ||||||||||
| East Texas/Louisiana | $ | 125.29 | $ | 75.48 | $ | 117.16 | $ | 66.46 | $ | 116.33 | ||||||||||
| South Texas | $ | 112.20 | $ | 71.76 | $ | 106.54 | $ | 69.88 | $ | 123.16 | ||||||||||
| Weighted average | $ | 108.23 | $ | 64.34 | $ | 106.09 | $ | 55.51 | $ | 117.99 | ||||||||||
| Average realized natural gas price - per MMbtu | ||||||||||||||||||||
| Texas Panhandle | $ | 8.81 | $ | 5.45 | $ | 8.55 | $ | 6.02 | $ | 9.44 | ||||||||||
| East Texas/Louisiana | $ | 9.69 | $ | 5.86 | $ | 10.37 | $ | 6.39 | $ | 12.32 | ||||||||||
| South Texas | $ | 9.42 | $ | 5.99 | $ | 9.58 | $ | 6.62 | $ | 10.88 | ||||||||||
| Weighted average | $ | 9.22 | $ | 5.71 | $ | 9.29 | $ | 6.25 | $ | 10.57 | ||||||||||
Non-GAAP Financial Measures
The following tables present a reconciliation of the non-GAAP financial measures of (i) Adjusted EBITDA to the GAAP financial measure of net income (loss) and (ii) Distributable Cash Flow to the GAAP financial measure of net income (loss) for each of the periods indicated.
Eagle Rock Energy Partners, L.P.
GAAP to Non-GAAP Reconciliations
($ in thousands)
(unaudited)
| Net income (loss) to adjusted EBITDA | ||||||||||||||||||||
| Three Months Ended | Nine Months Ended | Three Months | ||||||||||||||||||
| Sept 30, | Sept 30, | Ended | ||||||||||||||||||
| 2008 | 2007 | 2008 | 2007 | June 30, 2008 | ||||||||||||||||
| Net income (loss), as reported | $ | 288,071 | $ | 9,371 | $ | 32,723 | $ | (34,080 | ) | $ | (227,020 | ) | ||||||||
| Depreciation, depletion and amortization expense | 28,597 | 25,105 | 80,799 | 50,883 | 26,457 | |||||||||||||||
| Risk management interest related instruments-unrealized | 501 | 8,429 | 472 | 3,555 | (13,689 | ) | ||||||||||||||
| Risk management commodity related instruments-unrealized | (255,956 | ) | (8,865 | ) | 33,381 | 30,533 | 256,265 | |||||||||||||
Other operating expenses (non-recurring) (1) | 3,920 | 220 | 10,134 | 1,931 | 6,214 | |||||||||||||||
| Restricted units non-cash amortization expense | 1,427 | 820 | 4,147 | 1,613 | 1,559 | |||||||||||||||
| Income tax provision (benefit) | (494 | ) | 352 | (1,482 | ) | 772 | (886 | ) | ||||||||||||
| Interest - net including realized risk management instruments and other expense | 9,849 | 10,490 | 28,458 | 27,079 | 9,490 | |||||||||||||||
| Other income | (434 | ) | (767 | ) | (2,867 | ) | (879 | ) | (886 | ) | ||||||||||
| Adjusted EBITDA | $ | 75,481 | $ | 45,155 | $ | 185,765 | $ | 81,407 | $ | 57,504 | ||||||||||
| Net income (loss) to distributable cash flow | ||||||||||||||||||||
| Net income (loss), as reported | $ | 288,071 | $ | 9,371 | $ | 32,723 | $ | (34,080 | ) | $ | (227,020 | ) | ||||||||
| Depreciation, depletion and amortization expense | 28,597 | 25,105 | 80,799 | 50,883 | 26,457 | |||||||||||||||
| Risk management interest related instruments-unrealized | 501 | 8,429 | 472 | 3,555 | (13,689 | ) | ||||||||||||||
| Risk management commodity related instruments-unrealized | (255,956 | ) | (8,865 | ) | 33,381 | 30,533 | 256,265 | |||||||||||||
| Capital expenditures-maintenance related | (5,434 | ) | (2,492 | ) | (21,447 | ) | (9,220 | ) | (11,152 | ) | ||||||||||
| Restricted units non-cash amortization expense | 1,427 | 820 | 4,147 | 1,613 | 1,559 | |||||||||||||||
Other operating expenses (non-recurring) (1) | 3,920 | 220 | 10,134 | 1,931 | 6,214 | |||||||||||||||
| Income tax provision (benefit) | (494 | ) | 352 | (1,482 | ) | 772 | (886 | ) | ||||||||||||
| Other income | (434 | ) | (767 | ) | (2,867 | ) | (879 | ) | (886 | ) | ||||||||||
| Cash income taxes | (229 | ) | (261 | ) | (533 | ) | (436 | ) | (166 | ) | ||||||||||
| Distributable cash flow | $ | 59,969 | $ | 31,912 | $ | 135,327 | $ | 44,672 | $ | 36,696 | ||||||||||
____________
| (1) | Includes the SemGroup bad debt expense for the three and nine months ended September 30, 2008 and a settlement of arbitration for $1.4 million, severance to a former executive of $0.3 million for the nine months ended September 30, 2007 and $0.2 million of liquidated damages related to the late registration of our common units during the three and nine months ended September 30, 2007. |