Exhibit 99.1
August 5, 2008 | CONTACTS: | |
Elizabeth Wilkinson – Investor Relations Phone: 281-408-1329 | ||
Eagle Rock Energy Partners, L.P. Reports Second Quarter 2008 Results; Adjusted EBITDA of $57.5 million, Up 9.0% from $52.8 Million in the First Quarter
HOUSTON, TEXAS - Eagle Rock Energy Partners, L.P. (“Eagle Rock” or the “Partnership”) (NASDAQ GS: EROC) today announced its financial results for the three and six months ended June 30, 2008.
Highlights:
The Partnership highlighted the following achievements for the second quarter of 2008 as compared to the first quarter of 2008:
| • | Increased Adjusted EBITDA by 9.0% to $57.5 million from $52.8 million |
| • | Increased quarterly distribution rate to $0.41 per unit from $0.40 per unit while maintaining a 122% coverage on all outstanding units (excluding non-recurring items) |
| • | Increased daily gathering volumes in the midstream business by 4.5% to 414 MMcf/d from 396 MMcf/d |
| • | Completed the upstream acquisition of Stanolind Oil and Gas Corp. on April 30, 2008 (two months contribution to second quarter of 2008 earnings) |
The following are significant achievements for the second quarter of 2008 as compared to the second quarter of 2007:
| • | Increased Adjusted EBITDA by 160% to $57.5 million from $22.2 million |
| • | Increased quarterly distribution rate by 13.1% to $0.41 per common unit from $0.3625 per common unit |
| • | Increased Revenues (excluding unrealized, non-cash, mark-to-market commodity derivative losses) by 118%, to $442.5 million from $203.2 million |
| • | Increased daily gathering volumes in the midstream business by 22.8%, to 414 MMcf/d from 337 MMcf/d |
For the second quarter of 2008, the Partnership reported (excluding unrealized, non-cash, mark-to-market commodity derivative losses) $442.5 million in revenues versus $203.2 million for the second quarter of 2007 and $358.6 million for the first quarter of 2008.
Adjusted EBITDA (see “Use of Non-GAAP Financial Measures” below) for the second quarter of 2008 was $57.5 million as compared to $22.2 million in the same quarter of 2007 and $52.8 million in the first quarter of 2008. The dramatic 160% improvement in Adjusted EBITDA in the second quarter of 2008 over the second quarter of 2007 is a direct result of the transformation that has occurred in the Partnership over the last year. This transformation was driven by the introduction of the Upstream and Minerals segments to our business and the significant improvements in the Partnership’s Midstream segments related to the Laser acquisition and the Red Deer and Tyler County Pipeline Extension organic growth projects. A strong commodity price environment has also favorably impacted the Partnership’s results during this period. However, these gains in operating performance were partially offset by a $4.9 million increase in general and administrative expenses in the second quarter of 2008, as compared to the second quarter of 2007. This increase in G&A expenses is primarily due to the growth in our number of employees, which accompanied the growth of our asset base, and increased outside professional fees and other expenses associated with our public partnership status.
The increase in Adjusted EBITDA reported in the second quarter of 2008 over the first quarter of 2008 reflects higher realized prices, an increase in gathering volumes in the midstream business, and increased production in the minerals business. Upstream volumes were lower as compared to first quarter of 2008 due to a shut-in and curtailed production in the Big Escambia Creek (“BEC”) field as a result of our scheduled turnaround of the facility in April and damage that was sustained at the treating facility in May due to a lightning strike. The reduction in upstream volumes was partially offset by two strong months of production contributed by the Permian assets acquired in the Stanolind acquisition and higher realized sulfur prices. Eagle Rock believes the BEC treating facility turnaround and the lightning strike negatively impacted Adjusted EBITDA for the second quarter of 2008 by $8 million to $9 million.
Distributable Cash Flow (see “Use of Non-GAAP Financial Measures” below) for the second quarter of 2008 (prior to any cash reserves established by Eagle Rock’s Board and excluding non-recurring items) totaled $36.7 million compared to $38.7 million for the first quarter of 2008, a decrease of 5.1%. The decrease in Distributable Cash Flow is primarily related to increased maintenance capital expenditures related to increased well connections in the midstream business, the BEC treating facility turnaround and an increase in well recompletions and workovers in the upstream business, which were partially offset by an increase in Adjusted EBITDA. In the second quarter of 2008, Distributable Cash Flow (excluding non-recurring items) represents 122% coverage of the announced second quarter of 2008 distribution of $0.41 per unit based on total units outstanding.
In July 2008, Eagle Rock partially exercised the accordion feature under its revolving credit facility to increase its aggregate commitments by $100 million to a total of $900 million in commitments. The partial exercise of the accordion is to provide additional financial resources as part of Eagle Rock’s growth strategy.
Chairman and Chief Executive Officer, Joseph A. Mills said, “Eagle Rock continues to deliver record cash flows for the benefit of our unitholders while maintaining strong performance levels. Our diversified asset base once again delivered strong financial results and operating performance. Our midstream business experienced a 4.5% improvement in its gathering volumes compared to the first quarter of 2008 driven largely by continued drilling activity in our East Texas / Louisiana segment. Our minerals business continues to deliver strong, steadily improving results as it enjoyed continued leasing and drilling activity across the mineral holdings, as well as increases in both realized prices and volumes. Our upstream business experienced a reduction in volumes as compared to the first quarter of 2008 due to downtime experienced at our BEC field. This reduction in volumes was related to the previously-announced, scheduled turnaround of our BEC treating facility in April and curtailed production in late May and early June related to a direct lightning strike sustained by the facility. We have made all necessary repairs and the facility has been operating at normal levels since mid-June. Offsetting the reduced volumes at our BEC field has been the favorable commodity price environment, as well as the strong performance of the recently acquired Stanolind assets in the Permian Basin of Texas. With a full quarter of Stanolind’s operations and normalized operations across all of our assets, we expect to recommend a further increase to our third quarter 2008 distribution to our Board of Directors.”
Unit Distributions
The Partnership recently announced another increase in its cash unit distribution. The next distribution, which will be paid August 14, 2008, to all holders of record as of August 8, 2008, will be paid at the rate of $0.41 per unit, or a $1.64 per unit annualized rate.
Net Income (Loss)
The Partnership also reported a net loss for the second quarter of 2008 of $227.0 million versus a net loss of $23.8 million in the second quarter of 2007 and a net loss of $28.3 million in the first quarter of 2008. Included in the net loss for the second quarter of 2008 were $242.6 million of unrealized, non-cash, mark-to-market derivative losses versus $22.3 million in the second quarter of 2007 and $46.7 million in the first quarter of 2008. Also affecting our second quarter of 2008 net loss is the recording of a $6.2 million bad debt reserve against receivables associated with the bankruptcy of SemGroup, L.P. and certain related subsidiaries disclosed in our press release issued on July 30, 2008.
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 second quarter financial results and recent developments on Wednesday, August 6, 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 888-713-4214, confirmation code 40471280. 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 clickhttps://www.theconferencingservice.com/prereg/key.process?key=PDLYW7C7J. (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 61605687. 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 crude oil and natural gas interests; and c) minerals, which includes acquiring and managing fee minerals and royalty interests. Its corporate office is located in Houston, Texas.
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, 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 its 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).
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.
Eagle Rock Energy Partners, L.P.
Consolidated Statements of Operations
($ in thousands)
(unaudited)
| Three Months Ended June 30, | Six Months Ended June 30, | Three Months Ended March 31, 2008 | ||||||||||||||||||
| 2008 | 2007 | 2008 | 2007 | |||||||||||||||||
REVENUE: | ||||||||||||||||||||
Natural gas, natural gas liquids, condensate, oil and sulfur sales | $ | 451,769 | $ | 191,621 | $ | 808,788 | $ | 301,742 | $ | 357,019 | ||||||||||
Gathering, compression and processing fees | 8,085 | 6,883 | 15,228 | 11,166 | 7,143 | |||||||||||||||
Minerals and royalty income | 10,255 | 3,192 | 17,213 | 3,192 | 6,958 | |||||||||||||||
Unrealized commodity derivative losses | (256,265 | ) | (28,757 | ) | (289,337 | ) | (39,398 | ) | (33,072 | ) | ||||||||||
Realized commodity derivative gains (losses) | (27,708 | ) | 1,502 | (40,283 | ) | 4,501 | (12,575 | ) | ||||||||||||
Other income | 122 | — | 182 | — | 60 | |||||||||||||||
Total Revenue | 186,258 | 174,441 | 511,791 | 281,203 | 325,533 | |||||||||||||||
COSTS AND EXPENSES: | ||||||||||||||||||||
Cost of natural gas and natural gas liquids | 353,558 | 164,364 | 629,389 | 255,000 | 275,831 | |||||||||||||||
Operations and maintenance | 17,731 | 11,396 | 33,297 | 19,320 | 15,566 | |||||||||||||||
Taxes other than income | 5,263 | 728 | 9,610 | 1,430 | 4,347 | |||||||||||||||
General and administrative | 10,026 | 5,171 | 21,268 | 9,391 | 11,242 | |||||||||||||||
Other operating | 6,214 | — | 6,214 | 1,711 | — | |||||||||||||||
Impairment | — | — | — | — | — | |||||||||||||||
Depreciation, depletion and amortization | 26,457 | 14,149 | 52,202 | 25,779 | 25,745 | |||||||||||||||
Total Costs and Expenses | 419,249 | 195,808 | 751,980 | 312,631 | 332,731 | |||||||||||||||
OPERATING LOSS | (232,991 | ) | (21,367 | ) | (240,189 | ) | (31,428 | ) | (7,198 | ) | ||||||||||
Other Income (Expense): | ||||||||||||||||||||
Interest income | 160 | 176 | 461 | 300 | 301 | |||||||||||||||
Other income | 886 | 91 | 2,433 | 91 | 1,547 | |||||||||||||||
Interest expense, net | (6,974 | ) | (8,519 | ) | (16,078 | ) | (16,399 | ) | (9,104 | ) | ||||||||||
Unrealized interest rate derivative gains (losses) | 13,689 | 6,485 | 29 | 4,874 | (13,660 | ) | ||||||||||||||
Realized interest rate derivative gains (losses) | (2,444 | ) | 318 | (2,545 | ) | 534 | (101 | ) | ||||||||||||
Other expense | (232 | ) | (711 | ) | (447 | ) | (1,003 | ) | (215 | ) | ||||||||||
Total Other Income (Expense) | 5,085 | (2,160 | ) | (16,147 | ) | (11,603 | ) | (21,232 | ) | |||||||||||
LOSS BEFORE INCOME TAXES | (227,906 | ) | (23,527 | ) | (256,336 | ) | (43,031 | ) | (28,430 | ) | ||||||||||
Income tax (benefit) provision | (886 | ) | 256 | (988 | ) | 420 | (102 | ) | ||||||||||||
NET LOSS | $ | (227,020 | ) | $ | (23,783 | ) | $ | (255,348 | ) | $ | (43,451 | ) | $ | (28,328 | ) | |||||
Eagle Rock Energy Partners, L.P.
Consolidated Balance Sheets
($ in thousands)
(unaudited)
| June 30, 2008 | December 31, 2007 | |||||||
Assets | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 64,586 | $ | 68,552 | ||||
Accounts receivable | 186,182 | 135,633 | ||||||
Risk management assets | 4,528 | — | ||||||
Prepayments and other current assets | 5,603 | 3,992 | ||||||
| 260,899 | 208,177 | |||||||
Property plant and equipment - net | 1,315,440 | 1,207,130 | ||||||
Intangible assets - net | 145,634 | 153,948 | ||||||
Goodwill | 30,513 | 29,527 | ||||||
Other assets | 12,497 | 11,145 | ||||||
Total assets | $ | 1,764,983 | $ | 1,609,927 | ||||
Liabilities and Members’ Equity | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 203,699 | $ | 132,485 | ||||
Due to affiliate | 21,069 | 16,964 | ||||||
Accrued liabilities | 16,893 | 9,776 | ||||||
Taxes payable | 316 | 723 | ||||||
Risk management liabilities | 164,006 | 33,089 | ||||||
| 405,983 | 193,037 | |||||||
Long-term debt | 623,000 | 567,069 | ||||||
Asset retirement obligations | 16,773 | 11,337 | ||||||
Deferred tax liability | 43,585 | 17,516 | ||||||
Risk management liabilities | 259,985 | 94,200 | ||||||
Members’ equity | ||||||||
Common unit holders | 398,886 | 617,563 | ||||||
Subordinated unit holders | 23,556 | 112,360 | ||||||
General partner | (6,785 | ) | (3,155 | ) | ||||
| 415,657 | 726,768 | |||||||
Total Liabilities and Members’ Equity | $ | 1,764,983 | $ | 1,609,927 | ||||
Eagle Rock Energy Partners, L.P.
Midstream Segment
Operating Income
($ in thousands)
(unaudited)
| Three Months Ended June 30, | Six Months Ended June 30, | Three Months Ended March 31, 2008 | |||||||||||||
| 2008 | 2007 | 2008 | 2007 | ||||||||||||
Panhandle | |||||||||||||||
Revenues: | |||||||||||||||
Sales of natural gas, NGLs, oil and condensate | $ | 180,987 | $ | 107,884 | $ | 334,842 | $ | 200,664 | $ | 153,855 | |||||
Gathering and treating services | 2,524 | 2,206 | 4,993 | 4,342 | 2,469 | ||||||||||
Total revenues | 183,511 | 110,090 | 339,835 | 205,006 | 156,324 | ||||||||||
Cost of natural gas and natural gas liquids | 140,282 | 86,057 | 260,400 | 161,704 | 120,118 | ||||||||||
Operating costs and expenses: | |||||||||||||||
Operations and maintenance | 8,715 | 8,661 | 16,463 | 16,005 | 7,748 | ||||||||||
Depreciation, depletion and amortization | 10,894 | 9,983 | 21,603 | 19,765 | 10,709 | ||||||||||
Total operating costs and expenses | 19,609 | 18,644 | 38,066 | 35,770 | 18,457 | ||||||||||
Operating income | $ | 23,620 | $ | 5,389 | $ | 41,369 | $ | 7,532 | $ | 17,749 | |||||
East Texas/Louisiana(1) | |||||||||||||||
Revenues: | |||||||||||||||
Sales of natural gas, NGLs, oil and condensate | $ | 93,176 | $ | 33,853 | $ | 160,135 | $ | 51,194 | $ | 66,959 | |||||
Gathering and treating services | 4,700 | 3,785 | 8,148 | 5,932 | 3,448 | ||||||||||
Total revenues | 97,876 | 37,638 | 168,283 | 57,126 | 70,407 | ||||||||||
Cost of natural gas and natural gas liquids | 83,911 | 29,105 | 143,930 | 44,094 | 60,019 | ||||||||||
Operating costs and expenses: | |||||||||||||||
Operations and maintenance | 3,837 | 2,877 | 7,317 | 4,159 | 3,480 | ||||||||||
Depreciation, depletion and amortization | 2,988 | 2,056 | 5,857 | 3,731 | 2,869 | ||||||||||
Total operating costs and expenses | 6,825 | 4,933 | 13,174 | 7,890 | 6,349 | ||||||||||
Operating income | $ | 7,140 | $ | 3,600 | $ | 11,179 | $ | 5,142 | $ | 4,039 | |||||
South Texas (1) | |||||||||||||||
Revenues: | |||||||||||||||
Sales of natural gas, NGLs, oil and condensate | $ | 131,794 | $ | 49,884 | 229,033 | $ | 49,884 | $ | 97,239 | ||||||
Gathering and treating services | 861 | 892 | 2,087 | 892 | 1,226 | ||||||||||
Other | — | — | 2 | — | 2 | ||||||||||
Total revenues | 132,655 | 50,776 | 231,122 | 50,776 | 98,467 | ||||||||||
Cost of natural gas and natural gas liquids | 129,365 | 49,202 | 225,059 | 49,202 | 95,694 | ||||||||||
Operating costs and expenses: | |||||||||||||||
Operations and maintenance | 574 | 294 | 1,227 | 294 | 653 | ||||||||||
Depreciation, depletion and amortization | 934 | 379 | 1,873 | 379 | 939 | ||||||||||
Total operating costs and expenses | 1,508 | 673 | 3,100 | 673 | 1,592 | ||||||||||
Operating income | $ | 1,782 | $ | 901 | $ | 2,963 | $ | 901 | $ | 1,181 | |||||
| (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 June 30, | Six Months Ended June 30, | Three Months Ended March 31, 2008 | ||||||||||||||||||
| 2008 | 2007 | 2008 | 2007 | |||||||||||||||||
Midstream | ||||||||||||||||||||
Revenues: | ||||||||||||||||||||
Sales of natural gas, NGLs, oil and condensate | $ | 405,957 | $ | 191,621 | $ | 724,010 | $ | 301,742 | $ | 318,053 | ||||||||||
Gathering and treating services | 8,085 | 6,883 | 15,228 | 11,166 | 7,143 | |||||||||||||||
Other | — | — | 2 | — | 2 | |||||||||||||||
Total revenues | 414,042 | 198,504 | 739,240 | 312,908 | 325,198 | |||||||||||||||
Cost of natural gas and natural gas liquids | 353,558 | 164,364 | 629,389 | 255,000 | 275,831 | |||||||||||||||
Segment gross profit | 60,484 | 34,140 | 109,851 | 57,908 | 49,367 | |||||||||||||||
Operating costs and expenses: | ||||||||||||||||||||
Operations and maintenance | 13,126 | 11,832 | 25,007 | 20,458 | 11,881 | |||||||||||||||
Depletion, depreciation and amortization | 14,816 | 12,418 | 29,333 | 23,875 | 14,517 | |||||||||||||||
Total operating costs and expenses | 27,942 | 24,250 | 54,340 | 44,333 | 26,398 | |||||||||||||||
Operating income | $ | 32,542 | $ | 9,890 | $ | 55,511 | $ | 13,575 | $ | 22,969 | ||||||||||
Upstream (1) | ||||||||||||||||||||
Revenues: | ||||||||||||||||||||
Oil and condensate | $ | 21,126 | $ | — | $ | 39,459 | $ | — | $ | 18,333 | ||||||||||
Natural gas | 9,431 | — | 16,557 | — | 7,126 | |||||||||||||||
NGLs | 8,155 | — | 16,295 | — | 8,140 | |||||||||||||||
Sulfur | 7,100 | — | 12,467 | — | 5,367 | |||||||||||||||
Other | 122 | 180 | 58 | |||||||||||||||||
Total revenues | 45,934 | — | 84,958 | — | 39,024 | |||||||||||||||
Operating costs and expenses: | ||||||||||||||||||||
Operations and maintenance | 9,386 | — | 16,975 | — | 7,589 | |||||||||||||||
Depreciation, depletion and amortization | 9,914 | — | 18,339 | — | 8,425 | |||||||||||||||
Total operating costs and expenses | 19,300 | — | 35,314 | — | 16,014 | |||||||||||||||
Operating income | $ | 26,634 | $ | — | $ | 49,644 | $ | — | $ | 23,010 | ||||||||||
Minerals (2) | ||||||||||||||||||||
Revenues: | ||||||||||||||||||||
Oil and condensate | $ | 4,732 | $ | 1,533 | $ | 8,099 | $ | 1,533 | $ | 3,367 | ||||||||||
Natural gas | 3,565 | 1,490 | 5,774 | 1,490 | 2,209 | |||||||||||||||
NGLs | 411 | 98 | 646 | 98 | 235 | |||||||||||||||
Lease bonus, rentals and other | 1,547 | 71 | 2,694 | 71 | 1,147 | |||||||||||||||
Total revenues | 10,255 | 3,192 | 17,213 | 3,192 | 6,958 | |||||||||||||||
Operating costs and expenses: | ||||||||||||||||||||
Operations and maintenance | 482 | 292 | 925 | 292 | 443 | |||||||||||||||
Depreciation, depletion and amortization | 1,528 | 1,532 | 4,139 | 1,532 | 2,611 | |||||||||||||||
Total operating costs and expenses | 2,010 | 1,824 | 5,064 | 1,824 | 3,054 | |||||||||||||||
Operating income | $ | 8,245 | $ | 1,368 | $ | 12,149 | $ | 1,368 | $ | 3,904 | ||||||||||
Corporate | ||||||||||||||||||||
Revenues: | ||||||||||||||||||||
Realized commodity derivative gains (losses) | $ | (27,708 | ) | $ | 1,502 | $ | (40,283 | ) | $ | 4,501 | $ | (12,575 | ) | |||||||
Unrealized commodity derivative losses | (256,265 | ) | (28,757 | ) | (289,337 | ) | (39,398 | ) | (33,072 | ) | ||||||||||
Total revenues | (283,973 | ) | (27,255 | ) | (329,620 | ) | (34,897 | ) | (45,647 | ) | ||||||||||
General and administrative | 10,026 | 5,171 | 21,268 | 9,391 | 11,242 | |||||||||||||||
Depreciation, depletion and amortization | 199 | 199 | 391 | 372 | 192 | |||||||||||||||
Other operating expense | 6,214 | — | 6,214 | 1,711 | — | |||||||||||||||
Operating income | $ | (300,412 | ) | $ | (32,625 | ) | $ | (357,493 | ) | $ | (46,371 | ) | $ | (57,081 | ) | |||||
| (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 June 30, | Six Months Ended June 30, | Three Months Ended March 31, 2008 | ||||||||||||||||||
| 2008 | 2007 | 2008 | 2007 | |||||||||||||||||
Total | ||||||||||||||||||||
Revenues: | ||||||||||||||||||||
Sales of natural gas, NGLs, oil, condensate and sulfur | $ | 451,769 | $ | 191,621 | $ | 808,788 | $ | 301,742 | $ | 357,019 | ||||||||||
Gathering and treating services | 8,085 | 6,883 | 15,228 | 11,166 | 7,143 | |||||||||||||||
Minerals and royalty income | 10,255 | 3,192 | 17,213 | 3,192 | 6,958 | |||||||||||||||
Unrealized commodity derivative losses | (256,265 | ) | (28,757 | ) | (289,337 | ) | (39,398 | ) | (33,072 | ) | ||||||||||
Realized commodity derivative gains (losses) | (27,708 | ) | 1,502 | (40,283 | ) | 4,501 | (12,575 | ) | ||||||||||||
Other | 122 | — | 182 | — | 60 | |||||||||||||||
Total revenues | 186,258 | 174,441 | 511,791 | 281,203 | 325,533 | |||||||||||||||
Cost of natural gas and natural gas liquids | 353,558 | 164,364 | 629,389 | 255,000 | 275,831 | |||||||||||||||
Costs and expenses: | ||||||||||||||||||||
Operating | 17,731 | 11,396 | 33,297 | 19,320 | 15,566 | |||||||||||||||
Taxes other than income | 5,263 | 728 | 9,610 | 1,430 | 4,347 | |||||||||||||||
General and administrative | 10,026 | 5,171 | 21,268 | 9,391 | 11,242 | |||||||||||||||
Other expense | 6,214 | — | 6,214 | 1,711 | — | |||||||||||||||
Depreciation, depletion and amortization | 26,457 | 14,149 | 52,202 | 25,779 | 25,745 | |||||||||||||||
Total costs and expenses | 65,691 | 31,444 | 122,591 | 57,631 | 56,900 | |||||||||||||||
Operating loss | (232,991 | ) | (21,367 | ) | (240,189 | ) | (31,428 | ) | (7,198 | ) | ||||||||||
Other income (expense): | ||||||||||||||||||||
Interest income | 160 | 176 | 461 | 300 | 301 | |||||||||||||||
Other income | 886 | 91 | 2,433 | 91 | 1,547 | |||||||||||||||
Interest expense | (6,974 | ) | (8,519 | ) | (16,078 | ) | (16,399 | ) | (9,104 | ) | ||||||||||
Unrealized interest rate derivative gains (losses) | 13,689 | 6,485 | 29 | 4,874 | (13,660 | ) | ||||||||||||||
Realized interest rate derivative gains (losses) | (2,444 | ) | 318 | (2,545 | ) | 534 | (101 | ) | ||||||||||||
Other income (expense) | (232 | ) | (711 | ) | (447 | ) | (1,003 | ) | (215 | ) | ||||||||||
Total other income (expense) | 5,085 | (2,160 | ) | (16,147 | ) | (11,603 | ) | (21,232 | ) | |||||||||||
Loss before income taxes | (227,906 | ) | (23,527 | ) | (256,336 | ) | (43,031 | ) | (28,430 | ) | ||||||||||
Income tax (benefit) provision | (886 | ) | 256 | (988 | ) | 420 | (102 | ) | ||||||||||||
Net loss | $ | (227,020 | ) | $ | (23,783 | ) | $ | (255,348 | ) | $ | (43,451 | ) | $ | (28,328 | ) | |||||
Adjusted EBITDA | $ | 57,504 | $ | 22,159 | $ | 110,282 | $ | 36,252 | $ | 52,778 | ||||||||||
Eagle Rock Energy Partners, L.P.
Midstream Operations Information
(unaudited)
| Three Months Ended June 30, | Six Months Ended June 30, | Three Months Ended March 31, 2008 | ||||||||||||||||||
| 2008 | 2007 | 2008 | 2007 | |||||||||||||||||
Gas gathering volumes—(Average Mcf/d) | ||||||||||||||||||||
Texas Panhandle | 149,881 | 138,032 | 152,225 | 138,544 | 154,570 | |||||||||||||||
East Texas/Louisiana | 179,744 | 131,535 | 171,824 | 111,519 | 163,817 | |||||||||||||||
South Texas | 84,514 | 67,574 | 81,312 | 33,787 | 78,075 | |||||||||||||||
Total | 414,139 | 337,141 | 405,361 | 283,850 | 396,462 | |||||||||||||||
NGLs and condensate—(Net equity gallons) | ||||||||||||||||||||
Texas Panhandle | 19,650,791 | 21,641,964 | 41,535,043 | 41,634,155 | 21,884,252 | |||||||||||||||
East Texas/Louisiana | 6,624,451 | 4,823,502 | 11,928,049 | 7,930,684 | 5,303,598 | |||||||||||||||
South Texas | 377,706 | 155,904 | 827,568 | 155,904 | 449,862 | |||||||||||||||
Total | 26,652,948 | 26,621,370 | 54,290,660 | 49,720,743 | 27,637,712 | |||||||||||||||
Natural gas short position—(Average MMBtu/d) | ||||||||||||||||||||
Texas Panhandle | (4,974 | ) | (9,320 | ) | (6,112 | ) | (7,919 | ) | (7,263 | ) | ||||||||||
East Texas/Louisiana | 1,543 | 668 | 958 | 1,664 | 367 | |||||||||||||||
South Texas | 500 | 333 | 500 | 167 | 500 | |||||||||||||||
Total | (2,931 | ) | (8,319 | ) | (4,654 | ) | (6,088 | ) | (6,396 | ) | ||||||||||
Average realized NGL price—per gallon | ||||||||||||||||||||
Texas Panhandle | $ | 1.78 | $ | 1.19 | $ | 1.63 | $ | 0.93 | $ | 1.50 | ||||||||||
East Texas/Louisiana | $ | 1.40 | $ | 0.97 | $ | 1.33 | $ | 0.94 | $ | 1.25 | ||||||||||
South Texas | $ | 1.73 | $ | 1.51 | $ | 1.74 | $ | 1.51 | $ | 2.05 | ||||||||||
Weighted average | $ | 1.65 | $ | 1.14 | $ | 1.53 | $ | 1.05 | $ | 1.42 | ||||||||||
Average realized condensate price—per Bbl | ||||||||||||||||||||
Texas Panhandle | $ | 117.93 | $ | 54.43 | $ | 104.15 | $ | 50.27 | $ | 90.80 | ||||||||||
East Texas/Louisiana | $ | 116.33 | $ | 72.82 | $ | 111.37 | $ | 62.04 | $ | 102.59 | ||||||||||
South Texas | $ | 123.16 | $ | 62.17 | $ | 105.12 | $ | 62.17 | $ | 90.18 | ||||||||||
Weighted average | $ | 117.99 | $ | 55.65 | $ | 104.76 | $ | 51.08 | $ | 91.44 | ||||||||||
Average realized natural gas price—per MMbtu | ||||||||||||||||||||
Texas Panhandle | $ | 9.44 | $ | 6.64 | $ | 8.42 | $ | 6.39 | $ | 7.41 | ||||||||||
East Texas/Louisiana | $ | 12.32 | $ | 7.24 | $ | 10.67 | $ | 7.04 | $ | 8.61 | ||||||||||
South Texas | $ | 10.88 | $ | 6.62 | $ | 9.67 | $ | 6.62 | $ | 8.24 | ||||||||||
Weighted average | $ | 10.57 | $ | 6.64 | $ | 9.32 | $ | 6.73 | $ | 7.95 | ||||||||||
Eagle Rock Energy Partners, L.P.
Upstream and Minerals Operations Information
(unaudited)
| Three Months Ended June 30, | Six Months Ended June 30, | Three Months Ended March 31, 2008 | |||||||||||||
| 2008 | 2007 | 2008 | 2007 | ||||||||||||
Upstream | |||||||||||||||
Production: | |||||||||||||||
Oil and condensate (Bbl) | 184,511 | N/A | 385,916 | N/A | 201,405 | ||||||||||
Gas (Mcf) | 873,093 | N/A | 1,715,290 | N/A | 842,197 | ||||||||||
NGLs (Bbl) | 118,644 | N/A | 246,097 | N/A | 127,453 | ||||||||||
Total Mcfe | 2,692,023 | N/A | 5,507,368 | N/A | 2,815,345 | ||||||||||
Sulfur (Long ton) | 19,724 | N/A | 45,956 | N/A | 26,232 | ||||||||||
Realized prices, excluding derivatives: | |||||||||||||||
Oil and condensate (per Bbl) | $ | 114.50 | N/A | $ | 102.25 | N/A | $ | 91.03 | |||||||
Gas (per Mcf) | $ | 10.80 | N/A | $ | 9.65 | N/A | $ | 8.46 | |||||||
NGLs (per Bbl) | $ | 68.74 | N/A | $ | 66.21 | N/A | $ | 63.87 | |||||||
Sulfur (per Long ton) | $ | 359.97 | N/A | $ | 271.28 | N/A | $ | 204.60 | |||||||
Operating statistics: | |||||||||||||||
Operating costs per Mcfe (incl production taxes) | $ | 3.49 | N/A | $ | 3.08 | N/A | $ | 2.70 | |||||||
Operating Income per Mcfe | $ | 9.89 | N/A | $ | 9.01 | N/A | $ | 8.17 | |||||||
Drilling program (gross wells): | |||||||||||||||
Development wells | 6 | N/A | 12 | N/A | 6 | ||||||||||
Completions | 6 | N/A | 12 | N/A | 6 | ||||||||||
Workovers | 1 | N/A | 1 | N/A | — | ||||||||||
Recompletions | 3 | N/A | 7 | N/A | 4 | ||||||||||
Minerals | |||||||||||||||
Production: | |||||||||||||||
Oil and condensate (Bbl) | 40,907 | 24,412 | 78,740 | 24,412 | 37,833 | ||||||||||
Gas (Mcf) | 339,518 | 172,212 | 655,474 | 172,212 | 315,956 | ||||||||||
NGLs (Bbl) | 6,215 | 2,895 | 10,400 | 2,895 | 4,185 | ||||||||||
Total Mcfe | 622,250 | 336,054 | 1,129,400 | 336,054 | 568,064 | ||||||||||
Realized prices, excluding derivatives: | |||||||||||||||
Oil and condensate (per Bbl) | $ | 115.68 | $ | 62.80 | $ | 102.86 | $ | 62.80 | $ | 89.00 | |||||
Gas (per Mcf) | $ | 10.50 | $ | 8.65 | $ | 8.81 | $ | 8.65 | $ | 6.99 | |||||
NGLs (per Bbl) | $ | 66.13 | $ | 33.85 | $ | 62.12 | $ | 33.85 | $ | 56.15 | |||||
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 loss to adjusted EBITDA | ||||||||||||||||||||
| Three Months Ended June 30, | Six Months Ended June 30, | Three Months Ended March 31, 2008 | ||||||||||||||||||
| 2008 | 2007 | 2008 | 2007 | |||||||||||||||||
Net loss, as reported | $ | (227,020 | ) | $ | (23,783 | ) | $ | (255,348 | ) | $ | (43,451 | ) | $ | (28,328 | ) | |||||
Depreciation, depletion and amortization expense | 26,457 | 14,149 | 52,202 | 25,779 | 25,745 | |||||||||||||||
Risk management interest related instruments-unrealized | (13,689 | ) | (6,485 | ) | (29 | ) | (4,874 | ) | 13,660 | |||||||||||
Risk management commodity related instruments-unrealized | 256,265 | 28,757 | 289,337 | 39,398 | 33,072 | |||||||||||||||
Non-recurring operating items (1) | 6,214 | — | 6,214 | 1,711 | — | |||||||||||||||
Restricted units non-cash amortization expense | 1,559 | 620 | 2,718 | 792 | 1,159 | |||||||||||||||
Income tax provision (benefit) | (886 | ) | 256 | (988 | ) | 420 | (102 | ) | ||||||||||||
Interest—net including realized risk management instruments and other expense | 9,490 | 8,736 | 18,609 | 16,568 | 9,119 | |||||||||||||||
Other income | (886 | ) | (91 | ) | (2,433 | ) | (91 | ) | (1,547 | ) | ||||||||||
Adjusted EBITDA | $ | 57,504 | $ | 22,159 | $ | 110,282 | $ | 36,252 | $ | 52,778 | ||||||||||
Net loss to distributable cash flow | ||||||||||||||||||||
Net loss, as reported | $ | (227,020 | ) | $ | (23,783 | ) | $ | (255,348 | ) | $ | (43,451 | ) | $ | (28,328 | ) | |||||
Depreciation, depletion and amortization expense | 26,457 | 14,149 | 52,202 | 25,779 | 25,745 | |||||||||||||||
Risk management interest related instruments-unrealized | (13,689 | ) | (6,485 | ) | (29 | ) | (4,874 | ) | 13,660 | |||||||||||
Risk management commodity related instruments-unrealized | 256,265 | 28,757 | 289,337 | 39,398 | 33,072 | |||||||||||||||
Capital expenditures-maintenance related | (11,152 | ) | (4,574 | ) | (16,012 | ) | (6,728 | ) | (4,860 | ) | ||||||||||
Restricted units non-cash amortization expense | 1,559 | 620 | 2,718 | 792 | 1,159 | |||||||||||||||
Income tax provision (benefit) | (886 | ) | 256 | (988 | ) | 420 | (102 | ) | ||||||||||||
Other income | (886 | ) | (91 | ) | (2,433 | ) | (91 | ) | (1,547 | ) | ||||||||||
Cash income taxes | (166 | ) | (174 | ) | (304 | ) | (175 | ) | (138 | ) | ||||||||||
Distributable cash flow | $ | 30,482 | $ | 8,675 | $ | 69,143 | $ | 11,070 | $ | 38,661 | ||||||||||
Distributable cash flow excluding non-recurring items (2) | $ | 36,696 | $ | 8,675 | $ | 75,357 | $ | 12,781 | $ | 38,661 | ||||||||||
| (1) | Includes the SemGroup bad debt expense for the three and six months ended June 30, 2008 and a settlement of arbitration for $1.4 million and severance to a former executive of $0.3 million for the six months ended June 30, 2007. |
| (2) | Represents distributable cash flows (“DCF”) adjusted to exclude the non-recurring operating items in footnote (1) above. This presentation allows for the trend analysis of DCF with the exclusion of non-recurring items. |