May 5, 2010 | EXHIBIT 99.1 |
Eagle Rock Reports First-Quarter 2010 Financial Results
HOUSTON - Eagle Rock Energy Partners, L.P. (“Eagle Rock” or the “Partnership”) (NASDAQ: EROC) today announced its unaudited financial results for the three months ended March 31, 2010. Notable events with respect to first-quarter 2010 included the following:
· | Adjusted EBITDA totaled $36.8 million, down 28% compared to the $51.4 million reported in fourth-quarter 2009 due primarily to a decrease in realized commodity hedges and lower midstream volumes. |
· | Repaid $17.0 million of outstanding borrowings during the quarter, reducing total debt outstanding under its revolving credit facility to $737.4 million as of March 31, 2010. |
· | Distributable Cash Flow totaled $21.9 million, a decrease of 36% as compared to the $34.2 million reported in fourth-quarter 2009. |
· | Reported net income of $4.0 million, as compared to a net loss of $68.7 million for fourth-quarter 2009. |
· | Announced a quarterly distribution with respect to the first quarter of 2010 of $0.025 per common and general partner unit, unchanged from the distribution paid with respect to fourth-quarter 2009. |
· | Announced deployment of high-efficiency cryogenic processing plant in Texas Panhandle to improve recoveries and accommodate increased production volumes in the Granite Wash. |
· | Announced an expansion of the ETML gas gathering system in East Texas to better serve producers in the growing Haynesville and Middle Bossier shale plays. |
First-quarter 2010 results, relative to those reported in 2009, were negatively impacted by the Partnership’s commodities derivative portfolio. For example, the weighted average strike price on Eagle Rock’s crude hedges in the first quarter of 2010 was $75.48 per barrel, as compared to $101.06 per barrel in the fourth quarter of 2009. As a result, cash flow from realized commodity derivative settlements fell by $15.6 million to a realized net loss of $2.7 million for the first-quarter 2010 as compared to a realized net gain of $12.9 million in fourth-quarter 2009.
First-quarter 2010 Adjusted EBITDA and Distributable Cash Flow excluded $2.6 million in amortization of commodity hedge costs for the period, primarily related to hedge reset transactions. Including the amortization costs, first-quarter 2010 Adjusted EBITDA would have been $34.2 million and Distributable Cash Flow would have been $19.3 million, representing a decrease of 8% and 2%, respectively, compared to the fourth quarter of 2009 (presented on same basis).
“Our first quarter financial results highlight the opportunities and challenges we currently face. We continue to benefit from our diversified business model. While our Midstream operating income, excluding impairment, fell by approximately 4%, our Upstream and Minerals operating income, excluding impairment, increased by 53% and 12%, respectively. We initiated a robust drilling plan in the Permian Basin, with one well drilled and completed, two wells completing, and one well in the process of drilling as of March 31st. We continue to be excited about the areas in which we operate and are looking forward to expanding our current footprint in the Texas Panhandle through the deployment of our new Phoenix Plant and in East Texas / Louisiana through our recently announced ETML expansion project. Despite these positive developments, throughput volumes in our Midstream Business continue to be impacted by the low natural gas price environment, emphasizing the importance of our efforts to improve our liquidity,” said Joseph A. Mills, Chairman and Chief Executive Officer.
Mr. Mills added, “We continue to make preparations for our May 14th unitholder meeting where we will seek to gain approval of our proposed recapitalization and related transactions, as outlined in the definitive proxy we filed with the Securities and Exchange Commission on March 30th and mailed to our unitholders on April 9th.”
First-Quarter 2010 Financial and Operating Results
Eagle Rock analyzes and manages its operations under seven distinct segments: four segments in its Midstream Business - the Texas Panhandle, East Texas/Louisiana, South Texas and Gulf of Mexico Segments - and the Upstream, Minerals and Corporate Segments. The Corporate Segment includes the Partnership’s risk management (derivatives) and other corporate activities. The following discussion of Eagle Rock’s operating income by business segment compares the Partnership’s financial results in the first quarter of 2010 to those of the fourth quarter of 2009. The Partnership believes comparing these periods is more illustrative of current operating trends than comparing the current quarter to results achieved in the first quarter of 2009. Please refer to the financial tables at the end of this release for further detailed information.
Midstream Business – Operating income, excluding impairment, for the Midstream Business in the first quarter of 2010 decreased by $0.5 million, or 3.9%, compared to the fourth quarter of 2009. The decrease was driven by 5.4% lower gathering volumes and 12.9% lower equity volumes of NGLs and condensate, offset by higher NGL and condensate prices and a $1.6 million deficiency payment received from a producer for under-delivered volumes. The Partnership realized higher NGL and condensate prices in its Texas Panhandle, South Texas and Gulf of Mexico segments.
In the Texas Panhandle, gathered volumes were down 2.4%, with combined equity NGL and condensate volumes down 13.4% compared to the fourth quarter of 2009. The decline in the Partnership’s equity NGL and condensate gallons was caused in part by the continued natural decline in the West Panhandle fields and severe cold weather in the area. Also contributing to the decrease in NGL and condensate volumes was a negative adjustment to December estimates and fewer calendar days in the quarter. Taking these two factors into account, equity NGL and condensate volumes declined sequentially by approximately 2% in the first quarter of 2010. In addition, installation of additional measurement facilities in January of 2010 has improved the measurement of NGLs and condensate volumes resulting in increased equity condensate volumes and a corresponding decrease in equity NGL volumes.
In East Texas, gathered volumes were down 3.5% with equity NGL and condensate volumes down 12.1% compared to the fourth quarter of 2009. Equity NGL and equity condensate volumes were down in part due to a negative adjustment to December estimates and fewer calendar days in the quarter. Adjusting for these two factors, combined equity NGL and condensate volumes were down sequentially by approximately 7% in the first quarter of 2010 due to the lower gathered volumes and to a higher percentage of dry gas gathered in the first quarter of 2010.
In the Gulf of Mexico, gathered volumes were down 14.2% with equity NGL volumes down 26.9%. The reduced gathering volumes and equity NGL volumes in the Gulf of Mexico segment were a result of downtime at both the North Terrebonne Plant and Yscloskey Plant to perform mechanical repairs, fewer calendar days in the quarter, and a downward adjustment in the Partnership’s ownership percentage at the North Terrebonne Plant. Eagle Rock’s ownership percentage in the North Terrebonne Plant adjusts up or down annually based upon the Partnership’s volume of gas from committed leases as compared to the total volume of gas from all plant owners’ committed leases.
Upstream Business – Operating income for Eagle Rock’s Upstream Business in the first quarter of 2010, excluding the impact of impairments, increased by $1.7 million, or 53%, compared to the fourth quarter of 2009. The increase was attributable to 2.7% higher production volumes and higher realized natural gas, NGL and sulfur prices. The Partnership recorded sulfur revenues associated with its South Alabama and East Texas production of $1.1 million and realized sulfur prices of $43.87 per long ton for the three months ended March 31, 2010. Management continues to see a strengthening in sulfur demand and anticipates additional positive cash flow from its sulfur production over the next three to six months.
Minerals Business – Segment operating income from the Minerals Business in the first quarter of 2010 increased by $0.4 million, or 11.6%, compared to the fourth quarter of 2009. The increase was due to higher natural gas production and prices. Total production attributable to the Minerals Segment increased 22.5% over fourth-quarter 2009 due to initial production from wells drilled on the Partnership’s minerals interests in the Haynesville Shale.
Revenue for first-quarter 2010, including the impact of Eagle Rock’s realized and unrealized derivative gains and losses, increased 51% to $228.6 million, compared with $151.4 million reported for fourth-quarter 2009, and an increase of 14.5% over the $199.7 million reported for first-quarter 2009. The primary contributor to this increase was the Partnership’s unrealized commodity derivative gains in the quarter. Eagle Rock recorded an unrealized gain on commodity derivatives of $13.5 million in first-quarter 2010, as compared to unrealized losses on commodity derivatives of $62.0 million and $4.5 million in fourth-quarter 2009 and first-quarter 2009, respectively. The unrealized gain (loss) on commodity derivatives is a non-cash, mark-to-market amount which includes the amortization of commodity hedging costs. First-quarter 2010 revenues included a realized loss on commodity derivatives of $2.7 million, as compared to a realized gain of $12.9 million in fourth-quarter 2009.
Adjusted EBITDA was $36.8 million and Distributable Cash Flow was $21.9 million for the first quarter of 2010. The Partnership’s distribution of $0.025 per common and general partner unit with respect to the first quarter of 2010 will be paid on May 14, 2010 to the Partnership's general partner and its common unitholders who held of record at the close of business on May 7, 2010. Because the distribution paid for the quarter will be below the minimum quarterly distribution (the “MQD”), an arrearage of $0.3375 will accrue on the common units and the cumulative arrearage attributable to the common units will increase to a total of $1.6875 per unit. The Partnership is under no obligation to pay the arrearages, but all cumulative arrearages must be paid before any distributions can be made to the Partnership’s subordinated units. For a more detailed discussion of the common unit arrearages, please refer to the Eagle Rock partnership agreement (filed as part of the Partnership’s filings with the U.S. Securities and Exchange Commission (“SEC”)).
First-quarter 2010 Adjusted EBITDA and Distributable Cash Flow excluded $2.6 million in amortization of commodity hedge costs for the period (including costs of hedge reset transactions – transactions undertaken by the Partnership to increase the strike prices on commodity swaps and/or collars that settled in the period). Including the amortization costs, first-quarter 2010 Adjusted EBITDA would have been $34.2 million, and Distributable Cash Flow would have been $19.3 million.
Capitalization and Liquidity Update
Total debt outstanding under the Partnership’s revolving credit facility as of March 31, 2010 was approximately $737.4 million. Outstanding borrowings were reduced by $17 million during the first quarter of 2010. The Partnership has reduced outstanding borrowings by a total of $100 million from April 30, 2009 to March 31, 2010 as a result of the reduction in the quarterly distribution. This $100 million of debt repayment was achieved slightly ahead of management’s original timeframe of 12 months.
The revolving credit facility has aggregate commitments of approximately $971 million after adjusting for the unfunded portion of Lehman Brothers’ commitment. The Partnership is in compliance with its financial covenants and has no maturities under its credit facility until December 2012. Availability under the credit facility is a function of undrawn commitments and the limitations imposed by the borrowing base for the Upstream Business and traditional cash-flow based covenants for the Midstream and Minerals Businesses. The borrowing base for the Upstream Business was set at $130 million effective April 1, 2010 as part of the Partnership’s regularly scheduled semi-annual redetermination, with no increase in fees or borrowing costs. Unused capacity available under the credit facility, based on financial covenants, was approximately $61 million as of March 31, 2010.
Recapitalization and Related Transactions
Eagle Rock has entered into certain agreements to further enhance its liquidity. These agreements, which the Partnership calls its Recapitalization and Related Transactions, are contingent upon the affirmative vote of a majority of the Partnership’s common units held by unaffiliated unitholders. Should the agreements not be consummated, management will consider other alternatives to enhance the Partnership’s liquidity and address concerns surrounding its ability to remain in compliance with the financial covenants under its credit facility. These alternatives may include potential asset sales, accessing external capital, if available, and additional adjustments to the Partnership’s hedging portfolio.
The Partnership filed a copy of the definitive proxy statement, the Minerals Business Sale Agreement, and the Global Transaction Agreement and related ancillary agreements related to the Recapitalization and Related Transactions, on Form 8-K with the SEC on March 30, 2010, January 12, 2010 and December 21, 2009, respectively.
The Partnership will hold a special meeting of its common unitholders on May 14, 2010 for unitholders of record at the close of business on March 29, 2010, to vote on certain of the proposed Recapitalization and Related Transactions.
Announced Organic Growth Projects
On April 21, 2010, the Partnership announced its plans to begin construction on an expansion of its ETML gas gathering system in East Texas to provide multi-market capability for producers in the growing Haynesville and Middle Bossier shale plays in Nacogdoches and San Augustine Counties.
The expansion includes the construction of a nine-mile, 20-inch diameter pipeline and associated treating facilities in Nacogdoches County, Texas with an initial pipeline capacity of 200 MMcf/d, and the expansion of existing ETML pipeline interconnects into NGPL, TETCO and Gulf South interstate pipelines and the HPL intrastate pipeline. The project, with an estimated total cost of $11.9 million, will expand the Partnership's interconnect delivery capabilities through its ETML pipeline by 300 MMcf/d and will allow the tie-in of its existing BGS gathering system. The Partnership has purchased the required 20-inch pipe, acquired substantially all of the necessary rights-of-way and expects the project to be completed and operational by early third-quarter 2010. Final approval to initiate construction is dependent upon many variables, including the Partnership’s ability to secure producer commitments to the project. Based on continued drilling activity and success in the area, the Partnership also is evaluating subsequent expansion phases which could result in a total of over 50 miles of primarily 20-inch diameter pipe extending east / west into Nacogdoches, Angelina, San Augustine and Sabine Counties, Texas, at a total estimated cost of approximately $49 million.
On February 15, 2010, the Partnership announced its intention to deploy a currently idle high-efficiency cryogenic processing plant to the Texas Panhandle in order to increase efficiency and accommodate volume growth from the Granite Wash Play. Deployment of the cryogenic plant (to be named the “Phoenix Plant”) is phase two of the Partnership’s Texas Panhandle consolidation and processing capacity expansion project originally announced in February 2008.
Hedging Update
On April 19, 2010, Eagle Rock added to its commodity derivative portfolio by establishing hedges on a portion of its expected 2013 Midstream and Upstream volumes. Specifically, the Partnership entered into a swap for 60,000 barrels per month of NYMEX WTI crude oil for the twelve months ended December 31, 2013. The swap price for the transaction is $89.85 per barrel.
In addition, on April 9, 2010, the Partnership added to its commodity derivative portfolio by establishing hedges on a portion of its expected 2013 Midstream volumes. Specifically, the Partnership entered into a swap for 20,000 barrels per month of NYMEX WTI crude oil for the twelve months ended December 31, 2013. The swap price for the transaction is $90.20 per barrel.
On April 27, 2010, Eagle Rock posted an update to its Commodity Hedging Overview presentation on its website to describe the details of its latest hedge transactions and its existing hedge portfolio. The presentation can be accessed by going to www.eaglerockenergy.com, select Investor Relations, then select Presentations.
Conference Call
Eagle Rock will hold a conference call to discuss its first-quarter financial and operating results on Thursday, May 6, 2010 at 2:00 p.m. Eastern Time (1:00 p.m. Central Time).
Interested parties may listen live over the internet or via telephone. To listen live over the internet, log on to the Partnership’s web site at www.eaglerockenergy.com. To participate by telephone, the call-in number is 888-713-4213, confirmation code 96342598. Investors are advised to dial into the call at least 15 minutes prior to the call to register. Participants may pre-register for the call by using the following link: https://www.theconferencingservice.com/prereg/key.process?key=P938CJ6UR. Interested parties can also view important information about the Partnership’s conference call by following this link. Pre-registering is not mandatory but is recommended as it will provide you immediate entry to the call and will facilitate the timely start of the call. Pre-registration only takes a few minutes and you may pre-register at any time, including up to and after the call start. An audio replay of the conference call will also be available for thirty days by dialing 888-286-8010, confirmation code 56962069. In addition, a replay of the audio webcast will be available by accessing the Partnership’s website after the call is concluded.
About the Partnership
The Partnership is a growth-oriented master limited partnership engaged in 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 hydrocarbons 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” and “Board of Directors” in this press release refer to the Board of Directors of the general partner of the general partner of the Partnership.
Contacts:
Eagle Rock Energy Partners, L.P.
Jeff Wood, 281-408-1203
Senior Vice President and Chief Financial Officer
Adam Altsuler, 281-408-1350
Senior Financial Analyst
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; (gains) losses on discontinued operations and other (income) expense.
Eagle Rock uses Adjusted EBITDA as a measure of its core profitability to assess the financial performance of its assets. Adjusted EBITDA also is used as a supplemental financial measure by external users of Eagle Rock’s financial statements such as investors, commercial banks and research analysts. For example, the Partnership’s lenders under its revolving credit facility use a variant of its Adjusted EBITDA in a compliance covenant designed to measure the viability of Eagle Rock and its ability to perform under the terms of the revolving credit facility; Eagle Rock, therefore, uses Adjusted EBITDA to measure its compliance with its revolving credit facility. Eagle Rock believes that investors benefit from having access to the same financial measures that its management uses in evaluating performance. Adjusted EBITDA is useful in determining Eagle Rock’s ability to sustain or increase distributions. By excluding unrealized derivative gains (losses), a non-cash, mark-to-market benefit (charge) which represents the change in fair market value of the Partnership executed derivative instruments and is independent of its assets’ performance or cash flow generating ability, Eagle Rock believes Adjusted EBITDA reflects more accurately the Partnership’s ability to generate cash sufficient to pay interest costs, support its level of indebtedness, make cash distributions to its unitholders and general partner and finance its maintenance capital expenditures. Eagle Rock further believes that Adjusted EBITDA also describes more accurately the underlying performance of its operating assets by isolating the performance of its operating assets from the impact of an unrealized, non-cash measure designed to describe the fluctuating inherent value of a financial asset. Similarly, by excluding the impact of non-recurring discontinued operations, Adjusted EBITDA provides users of the Partnership’s financial statements a more accurate picture of its current assets’ cash generation ability, independently from that of assets which are no longer a part of its operations.
Eagle Rock’s Adjusted EBITDA definition may not be comparable to Adjusted EBITDA or similarly titled measures of other entities, as other entities may not calculate Adjusted EBITDA in the same manner as Eagle Rock. For example, the Partnership includes in Adjusted EBITDA the actual settlement revenue created from its commodity hedges by virtue of transactions undertaken by it to reset commodity hedges to higher prices or purchase puts or other similar floors despite the fact that the Partnership excludes from Adjusted EBITDA any charge for amortization of the cost of such commodity hedge reset transactions or puts. Eagle Rock has reconciled Adjusted EBITDA to the GAAP financial measure of net income (loss) at the end of this release.
Distributable Cash Flow is defined as Adjusted EBITDA minus: (i) maintenance capital expenditures; (ii) cash interest expense; (iii) cash income taxes; and (iv) the addition of losses or subtraction of gains relating to other miscellaneous non-cash amounts affecting net income (loss) for the period. Maintenance capital expenditures represent: a) in our Midstream Business, capital expenditures made to replace partially or fully depreciated assets, to meet regulatory requirements, to maintain the existing operating capacity of our assets and extend their useful lives, or to connect wells to maintain existing system volumes and related cash flows; and b) in our Upstream Business, capital which is expended to maintain our production and cash flow levels in the near future.
Distributable Cash Flow is a significant performance metric used by senior management to compare cash flows generated by the Partnership (excluding growth capital expenditures and prior to the establishment of any retained cash reserves by the Board of Directors) to the cash distributions expected to be paid to unitholders. Using this metric, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. This financial measure also is important to investors as an indicator of whether the Partnership is generating cash flow at a level that can sustain or support an increase in quarterly distribution rates. Actual distributions are set by the Board of Directors.
The GAAP measure most directly comparable to Distributable Cash Flow is net income (loss). Eagle Rock’s Distributable Cash Flow definition may not be comparable to Distributable Cash Flow or similarly titled measures of other entities, as other entities may not calculate Distributable Cash Flow (and Adjusted EBITDA, on which it builds) in the same manner as Eagle Rock. See the example given above for Adjusted EBITDA related to amortization of costs of commodity hedges, including costs of hedge reset transactions. Eagle Rock has reconciled Distributable Cash Flow to the GAAP financial measure of net income/(loss) at the end of this release.
This news release may include “forward-looking statements.” All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Partnership expects, believes or anticipates will or may occur in the future are forward-looking statements and speak only as of the date on which such statement is made. These statements are based on certain assumptions made by the Partnership based on its experience and perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate under the circumstances. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Partnership, which may cause the Partnership’s actual results to differ materially from those implied or expressed by the forward-looking statements. The Partnership assumes no obligation to update any forward-looking statement as of any future date. For a detailed list of the Partnership’s risk factors, please consult the Partnership’s Form 10-K, filed with the Securities and Exchange Commission for the year ended December 31, 2009, as well as any other public filings and press releases.
Consolidated Statements of Operations | |||||||||||||
($ in thousands) | |||||||||||||
(unaudited) | |||||||||||||
Three Months | Three Months | ||||||||||||
Ended March 31, | Ended | ||||||||||||
2010 | 2009 | December 31, 2009 | |||||||||||
REVENUE: | |||||||||||||
Natural gas, NGLs, condensate, oil and sulfur sales | $ | 199,296 | $ | 158,490 | $ | 185,123 | |||||||
Gathering, compression, processing and treating fees | 12,833 | 11,667 | 10,433 | ||||||||||
Minerals and royalty income | 5,649 | 3,239 | 4,920 | ||||||||||
Unrealized commodity derivative gains (losses) | 13,478 | (4,522 | ) | (62,022 | ) | ||||||||
Realized commodity derivative gains (losses) | (2,683 | ) | 30,778 | 12,869 | |||||||||
Other income | 36 | 42 | 88 | ||||||||||
Total Revenue | 228,609 | 199,694 | 151,411 | ||||||||||
COSTS AND EXPENSES: | |||||||||||||
Cost of natural gas and NGLs | 144,278 | 133,217 | 129,428 | ||||||||||
Operations and maintenance (1) | 19,235 | 18,641 | 18,572 | ||||||||||
Taxes other than income | 3,999 | 2,978 | 3,257 | ||||||||||
Impairment | - | 242 | 21,546 | ||||||||||
General and administrative | 13,088 | 12,538 | 11,306 | ||||||||||
Depreciation, depletion and amortization | 29,435 | 30,063 | 30,025 | ||||||||||
Total Costs and Expenses | 210,035 | 197,679 | 214,134 | ||||||||||
OPERATING INCOME (LOSS) | 18,574 | 2,015 | (62,723 | ) | |||||||||
Other Income (Expense): | |||||||||||||
Interest income | 2 | 32 | 5 | ||||||||||
Other income | 268 | 560 | 493 | ||||||||||
Interest expense, net | (4,145 | ) | (7,539 | ) | (4,309 | ) | |||||||
Unrealized interest rate derivative gains (losses) | (4,822 | ) | 3,099 | 2,784 | |||||||||
Realized interest rate derivative gains (losses) | (4,890 | ) | (3,482 | ) | (5,207 | ) | |||||||
Other expense | (269 | ) | (267 | ) | (269 | ) | |||||||
Total Other Income (Expense) | (13,856 | ) | (7,597 | ) | (6,503 | ) | |||||||
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | 4,718 | (5,582 | ) | (69,226 | ) | ||||||||
Income tax (benefit) provision | 765 | (2,730 | ) | (547 | ) | ||||||||
INCOME (LOSS) FROM CONTINUING OPERATIONS | 3,953 | (2,852 | ) | (68,679 | ) | ||||||||
DISCONTINUED OPERATIONS | 28 | 307 | 24 | ||||||||||
NET INCOME (LOSS) | $ | 3,981 | $ | (2,545 | ) | $ | (68,655 | ) | |||||
(1) | Includes costs of $(0.2) million, $0.4 million and $0.7 million for disposal of sulfur in our Upstream Segment for the three months ended March 31, 2010 and 2009 | ||||||||||||
and December 31, 2009, respectively. |
Eagle Rock Energy Partners, L.P. | ||||||||
Consolidated Balance Sheets | ||||||||
($ in thousands) | ||||||||
(unaudited) | ||||||||
March 31, | December 31, | |||||||
2010 | 2009 | |||||||
Assets | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 149 | $ | 2,732 | ||||
Accounts receivable | 88,935 | 91,164 | ||||||
Risk management assets | 6,349 | 2,479 | ||||||
Prepayments and other current assets | 3,513 | 2,790 | ||||||
98,946 | 99,165 | |||||||
Property plant and equipment - net | 1,260,745 | 1,275,881 | ||||||
Intangible assets - net | 127,157 | 132,343 | ||||||
Deferred tax asset | 2,159 | 1,562 | ||||||
Risk management assets | 7,566 | 3,410 | ||||||
Other assets | 22,648 | 21,967 | ||||||
Total assets | $ | 1,519,221 | $ | 1,534,328 | ||||
Liabilities and Members' Equity | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 78,089 | $ | 78,096 | ||||
Due to affiliate | 12,883 | 12,910 | ||||||
Accrued liabilities | 8,046 | 11,110 | ||||||
Taxes payable | 2,412 | 2,416 | ||||||
Risk management liabilities | 51,940 | 51,650 | ||||||
153,370 | 156,182 | |||||||
Long-term debt | 737,383 | 754,383 | ||||||
Asset retirement obligations | 20,126 | 19,829 | ||||||
Deferred tax liability | 41,192 | 40,246 | ||||||
Risk management liabilities | 31,795 | 32,715 | ||||||
Other Long-term liabilities | 575 | 575 | ||||||
Members' equity | ||||||||
Common unitholders | 487,039 | 484,282 | ||||||
Subordinated unitholders | 53,640 | 52,058 | ||||||
General partner | (5,899 | ) | (5,942 | ) | ||||
534,780 | 530,398 | |||||||
Total Liabilities and Members' Equity | $ | 1,519,221 | $ | 1,534,328 |
Eagle Rock Energy Partners, L.P. | |||||||||||||
Segment Summary | |||||||||||||
Operating Income | |||||||||||||
($ in thousands) | |||||||||||||
(unaudited) | |||||||||||||
Three Months Ended March 31, | Three Months | ||||||||||||
Ended | |||||||||||||
2010 | 2009 | December 31, 2009 | |||||||||||
Midstream | |||||||||||||
Revenues: | |||||||||||||
Natural gas, NGLs, oil and condensate sales | $ | 176,647 | $ | 148,411 | $ | 164,335 | |||||||
Gathering, compression, processing and treating services | 12,833 | 11,667 | 10,433 | ||||||||||
Other | - | 3 | - | ||||||||||
Total revenues | 189,480 | 160,081 | 174,768 | ||||||||||
Cost of natural gas and NGLs | 144,278 | 133,217 | 129,428 | ||||||||||
Operating costs and expenses: | |||||||||||||
Operations and maintenance | 13,665 | 14,176 | 12,800 | ||||||||||
Impairment | - | - | 13,674 | ||||||||||
Depletion, depreciation and amortization | 19,108 | 18,779 | 19,604 | ||||||||||
Total operating costs and expenses | 32,773 | 32,955 | 46,078 | ||||||||||
Operating income (loss) from continuing operations | 12,429 | (6,091 | ) | (738 | ) | ||||||||
Discontinued Operations | 28 | 307 | 24 | ||||||||||
Operating income | $ | 12,457 | $ | (5,784 | ) | $ | (714 | ) | |||||
Upstream (1) | |||||||||||||
Revenues: | |||||||||||||
Oil and condensate (2) | $ | 10,985 | $ | 5,958 | $ | 9,943 | |||||||
Natural gas (3) | 4,632 | 1,895 | 4,940 | ||||||||||
NGLs (4) | 5,964 | 2,226 | 5,905 | ||||||||||
Sulfur | 1,068 | - | - | ||||||||||
Other | 36 | 39 | 88 | ||||||||||
Total revenues | 22,685 | 10,118 | 20,876 | ||||||||||
Operating costs and expenses: | |||||||||||||
Operations and maintenance | 9,292 | 6,532 | 7,980 | ||||||||||
Sulfur disposal costs | (185 | ) | 440 | 740 | |||||||||
Impairment | - | 242 | 7,872 | ||||||||||
Depreciation, depletion and amortization | 8,565 | 9,396 | 8,890 | ||||||||||
Total operating costs and expenses | 17,672 | 16,610 | 25,482 | ||||||||||
Operating income | $ | 5,013 | $ | (6,492 | ) | $ | (4,606 | ) | |||||
Minerals | |||||||||||||
Revenues: | |||||||||||||
Oil and condensate | $ | 2,904 | $ | 1,676 | $ | 2,868 | |||||||
Natural gas | 2,303 | 865 | 1,400 | ||||||||||
NGLs | 231 | 129 | 215 | ||||||||||
Lease bonus, rentals and other | 211 | 569 | 437 | ||||||||||
Total revenues | 5,649 | 3,239 | 4,920 | ||||||||||
Operating costs and expenses: | |||||||||||||
Operations and maintenance | 462 | 471 | 309 | ||||||||||
Impairment | - | - | - | ||||||||||
Depreciation, depletion and amortization | 1,409 | 1,675 | 1,226 | ||||||||||
Total operating costs and expenses | 1,871 | 2,146 | 1,535 | ||||||||||
Operating income | $ | 3,778 | $ | 1,093 | $ | 3,385 | |||||||
Corporate | |||||||||||||
Revenues: | |||||||||||||
Unrealized commodity derivative gains (losses) | $ | 13,478 | $ | (4,522 | ) | $ | (62,022 | ) | |||||
Realized commodity derivative (losses) gains | (2,683 | ) | 30,778 | 12,869 | |||||||||
Total revenues | 10,795 | 26,256 | (49,153 | ) | |||||||||
General and administrative | 13,088 | 12,538 | 11,306 | ||||||||||
Depreciation, depletion and amortization | 353 | 213 | 305 | ||||||||||
Operating income (loss) | $ | (2,646 | ) | $ | 13,505 | $ | (60,764 | ) | |||||
(1) | Includes operations from the Stanolind acquisition beginning on May 1, 2008. | ||||||||||||
(2) | Revenues include a change in the value of product imbalances of $(185), $247 and $(1,104) for the three months ended March 31, 2010 and 2009 and December 31, 2009, respectively. | ||||||||||||
(3) | Revenues include a change in the value of product imbalances of $(278), $(2,112) and $(1,505) for the three months ended March 31, 2010 and 2009 and December 31, 2009, respectively. | ||||||||||||
(4) | Revenues include a change in the value of product imbalances of $0 and $(167) for the three months ended March 31, 2010 and 2009, respectively. |
Eagle Rock Energy Partners, L.P. | |||||||||||||
Midstream Segment | |||||||||||||
Operating Income | |||||||||||||
($ in thousands) | |||||||||||||
(unaudited) | |||||||||||||
Three Months | Three Months | ||||||||||||
Ended March 31, | Ended | ||||||||||||
2010 | 2009 | December 31, 2009 | |||||||||||
Texas Panhandle | |||||||||||||
Revenues: | |||||||||||||
Natural gas, NGLs, oil and condensate sales | $ | 90,733 | $ | 62,950 | $ | 86,125 | |||||||
Gathering, compression, processing, and treating services | 2,942 | 2,813 | 2,827 | ||||||||||
Total revenues | 93,675 | 65,763 | 88,952 | ||||||||||
Cost of natural gas and NGLs | 66,970 | 51,947 | 59,091 | ||||||||||
Operating costs and expenses: | |||||||||||||
Operations and maintenance | 8,098 | 8,145 | 7,466 | ||||||||||
Depreciation, depletion and amortization | 11,590 | 11,096 | 12,425 | ||||||||||
Total operating costs and expenses | 19,688 | 19,241 | 19,891 | ||||||||||
Operating income | $ | 7,017 | $ | (5,425 | ) | $ | 9,970 | ||||||
East Texas/Louisiana (1) | |||||||||||||
Revenues: | |||||||||||||
Natural gas, NGLs, oil and condensate sales | $ | 51,841 | $ | 47,451 | $ | 46,601 | |||||||
Gathering, compression, processing, and treating services | 8,522 | 7,209 | 6,017 | ||||||||||
Total revenues | 60,363 | 54,660 | 52,618 | ||||||||||
Cost of natural gas and NGLs | 46,205 | 45,009 | 41,050 | ||||||||||
Operating costs and expenses: | |||||||||||||
Operations and maintenance | 4,209 | 4,552 | 4,098 | ||||||||||
Impairment | - | - | 5,941 | ||||||||||
Depreciation, depletion and amortization | 4,428 | 4,771 | 3,719 | ||||||||||
Total operating costs and expenses | 8,637 | 9,323 | 13,758 | ||||||||||
Operating income | $ | 5,521 | $ | 328 | $ | (2,190 | ) | ||||||
South Texas (1) | |||||||||||||
Revenues: | |||||||||||||
Natural gas, NGLs, oil and condensate sales | $ | 25,649 | $ | 31,788 | $ | 20,828 | |||||||
Gathering, compression, processing, and treating services | 934 | 1,557 | 1,397 | ||||||||||
Other | - | 3 | - | ||||||||||
Total revenues | 26,583 | 33,348 | 22,225 | ||||||||||
Cost of natural gas and NGLs | 23,638 | 31,069 | 20,186 | ||||||||||
Operating costs and expenses: | |||||||||||||
Operations and maintenance | 853 | 1,061 | 715 | ||||||||||
Impairment | - | - | 7,733 | ||||||||||
Depreciation, depletion and amortization | 1,487 | 1,424 | 1,329 | ||||||||||
Total operating costs and expenses | 2,340 | 2,485 | 9,777 | ||||||||||
Operating income (loss) from continuing operations | 605 | (206 | ) | (7,738 | ) | ||||||||
Discontinued Operations | 28 | 307 | 24 | ||||||||||
Operating income | $ | 633 | $ | 101 | $ | (7,714 | ) | ||||||
Gulf of Mexico(1) | |||||||||||||
Revenues: | |||||||||||||
Natural gas, NGLs, oil and condensate sales | $ | 8,424 | $ | 6,222 | $ | 10,781 | |||||||
Gathering, compression, processing, and treating services | 435 | 88 | 192 | ||||||||||
Other | - | - | - | ||||||||||
Total revenues | 8,859 | 6,310 | 10,973 | ||||||||||
Cost of natural gas and NGLs | 7,465 | 5,192 | 9,101 | ||||||||||
Operating costs and expenses: | |||||||||||||
Operations and maintenance | 505 | 418 | 521 | ||||||||||
Depreciation, depletion and amortization | 1,603 | 1,488 | 2,131 | ||||||||||
Total operating costs and expenses | 2,108 | 1,906 | 2,652 | ||||||||||
Operating income | $ | (714 | ) | $ | (788 | ) | $ | (780 | ) | ||||
(1) | Includes operations related to the Millennium Acquisition beginning October 1, 2008. | ||||||||||||
Midstream Operations Information | ||||||||||||
(unaudited) | ||||||||||||
Three Months | Three Months | |||||||||||
Ended March 31, | Ended | |||||||||||
2010 | 2009 | December 31, 2009 | ||||||||||
Gas gathering volumes - (Average Mcf/d) | ||||||||||||
Texas Panhandle | 128,493 | 144,203 | 131,626 | |||||||||
East Texas/Louisiana | 212,907 | 271,571 | 220,639 | |||||||||
South Texas | 74,124 | 97,413 | 75,661 | |||||||||
Gulf of Mexico | 102,291 | 116,627 | 119,193 | |||||||||
Total | 517,815 | 629,814 | 547,119 | |||||||||
NGLs - (Net equity gallons) | ||||||||||||
Texas Panhandle | 9,555,983 | 10,635,049 | 11,755,661 | |||||||||
East Texas/Louisiana | 4,679,582 | 2,676,419 | 5,253,365 | |||||||||
South Texas | 305,698 | 224,505 | 319,332 | |||||||||
Gulf of Mexico | 1,087,316 | 1,712,150 | 1,487,348 | |||||||||
Total | 15,628,579 | 15,248,123 | 18,815,706 | |||||||||
Condensate - (Net equity gallons) | ||||||||||||
Texas Panhandle | 8,719,633 | 6,192,426 | 9,347,564 | |||||||||
East Texas/Louisiana | 471,293 | 609,805 | 605,820 | |||||||||
South Texas | 484,066 | 647,460 | 275,430 | |||||||||
Gulf of Mexico | - | - | - | |||||||||
Total | 9,674,992 | 7,449,691 | 10,228,814 | |||||||||
Natural gas short position - (Average MMbtu/d) | ||||||||||||
Texas Panhandle | (4,301 | ) | (6,141 | ) | (7,469 | ) | ||||||
East Texas/Louisiana | 1,828 | 3,277 | 3,033 | |||||||||
South Texas | 1,063 | 500 | 822 | |||||||||
Total | (1,410 | ) | (2,364 | ) | (3,614 | ) | ||||||
Average realized NGL price - per Bbl | ||||||||||||
Texas Panhandle | $ | 48.22 | $ | 24.61 | $ | 46.58 | ||||||
East Texas/Louisiana | $ | 39.02 | $ | 18.98 | $ | 36.23 | ||||||
South Texas | $ | 49.98 | $ | 25.89 | $ | 44.86 | ||||||
Gulf of Mexico | $ | 48.50 | $ | 27.96 | $ | 45.65 | ||||||
Weighted average | $ | 46.26 | $ | 23.61 | $ | 43.91 | ||||||
Average realized condensate price - per Bbl | ||||||||||||
Texas Panhandle | $ | 68.50 | $ | 47.23 | $ | 66.85 | ||||||
East Texas/Louisiana | $ | 68.45 | $ | 50.75 | $ | 73.78 | ||||||
South Texas | $ | 78.36 | $ | 26.87 | $ | 67.33 | ||||||
Gulf of Mexico | $ | 74.50 | $ | 42.14 | $ | 71.14 | ||||||
Weighted average | $ | 69.00 | $ | 46.83 | $ | 67.50 | ||||||
Average realized natural gas price - per MMbtu | ||||||||||||
Texas Panhandle | $ | 5.20 | $ | 3.45 | $ | 4.14 | ||||||
East Texas/Louisiana | $ | 5.89 | $ | 4.29 | $ | 4.19 | ||||||
South Texas | $ | 5.44 | $ | 4.35 | $ | 4.23 | ||||||
Weighted average | $ | 5.48 | $ | 3.97 | $ | 4.18 |
Upstream and Minerals Operations Information | ||||||||||||
(unaudited) | ||||||||||||
Three Months | Three Months | |||||||||||
Ended March 31, | Ended | |||||||||||
2010 | 2009 | December 31, 2009 | ||||||||||
Upstream | ||||||||||||
Production: (1) | ||||||||||||
Oil and condensate (Bbl) | 197,465 | 207,530 | 189,988 | |||||||||
Gas (Mcf) | 942,463 | 886,284 | 893,409 | |||||||||
NGLs (Bbl) | 120,418 | 124,966 | 123,783 | |||||||||
Total Mcfe | 2,849,761 | 2,881,260 | 2,776,035 | |||||||||
Sulfur (Long ton) | 19,116 | 28,340 | 23,801 | |||||||||
Realized prices, excluding derivatives: (1) (2) | ||||||||||||
Oil and condensate (per Bbl) | $ | 56.57 | $ | 28.37 | $ | 61.22 | ||||||
Gas (per Mcf) | $ | 5.21 | $ | 4.20 | $ | 4.40 | ||||||
NGLs (per Bbl) | $ | 49.53 | $ | 19.11 | $ | 46.44 | ||||||
Sulfur (per Long ton) (4) | $ | 43.87 | $ | - | $ | - | ||||||
Operating statistics: | ||||||||||||
Operating costs per Mcfe (incl production taxes) (3) | $ | 3.26 | $ | 2.27 | $ | 2.87 | ||||||
Operating costs per Mcfe (excl production taxes) (3) | $ | 2.46 | $ | 0.98 | $ | 2.05 | ||||||
Operating Income per Mcfe | $ | 1.76 | $ | (2.25 | ) | $ | (1.66 | ) | ||||
Drilling program (gross wells): | ||||||||||||
Development wells | 1 | 5 | 2 | |||||||||
Completions | 1 | 4 | 2 | |||||||||
Workovers | 6 | 2 | 2 | |||||||||
Recompletions | 3 | 1 | 1 | |||||||||
Minerals | ||||||||||||
Production: | ||||||||||||
Oil and condensate (Bbl) | 39,781 | 43,026 | 40,063 | |||||||||
Gas (Mcf) | 518,190 | 282,202 | 371,768 | |||||||||
NGLs (Bbl) | 5,338 | 5,711 | 5,293 | |||||||||
Total Mcfe | 788,904 | 564,358 | 643,904 | |||||||||
Realized prices, excluding derivatives: | ||||||||||||
Oil and condensate (per Bbl) | $ | 73.00 | $ | 38.95 | $ | 71.59 | ||||||
Gas (per Mcf) | $ | 4.44 | $ | 3.07 | $ | 3.77 | ||||||
NGLs (per Bbl) | $ | 43.27 | $ | 22.59 | $ | 40.62 | ||||||
(1) Volumes and realized prices for the three months ended March 31, 2009 from prior reported amounts for a | ||||||||||||
reallocation which was recorded in December 2009. | ||||||||||||
(2) Calculation does not include impact of product imbalances. | ||||||||||||
(3) Excludes sulfur disposal costs of $(0.2) million, $0.4 million and $0.7 million for the three months ended March 31, 2010 and 2009 | ||||||||||||
and December 31, 2009, respectively. | ||||||||||||
(4) During the three months ended March 31, 2010, an adjustment was made to decrease sulfur volumes by 5,230 long tons related to | ||||||||||||
a prior period adjustment. This adjustment was excluded from the calculation of realized prices. |
Non-GAAP Financial Measures
The following tables present a reconciliation of the non-GAAP financial measures of Adjusted EBITDA and Distributable Cash Flow to the GAAP financial measure of net income for each of the periods indicated (in thousands).
Eagle Rock Energy Partners, L.P. | ||||||||||||
GAAP to Non-GAAP Reconciliations | ||||||||||||
($ in thousands) | ||||||||||||
(unaudited) | ||||||||||||
Three Months | Three Months | |||||||||||
Ended March 31, | Ended | |||||||||||
Net income (loss) to adjusted EBITDA | 2010 | 2009 | December 31, 2009 | |||||||||
Net income (loss), as reported | $ | 3,981 | $ | (2,545 | ) | $ | (68,655 | ) | ||||
Depreciation, depletion and | ||||||||||||
amortization expense | 29,435 | 30,063 | 30,025 | |||||||||
Impairment | - | 242 | 21,546 | |||||||||
Risk management interest related | ||||||||||||
instruments-unrealized | 4,822 | (3,099 | ) | (2,784 | ) | |||||||
Risk management commodity related | ||||||||||||
instruments-unrealized, including amortization of | ||||||||||||
commodity derivative costs | (13,478 | ) | 4,522 | 62,022 | ||||||||
Other operating (income) expenses (non-recurring) | - | - | - | |||||||||
Non-cash mark-to-market of Upstream product imbalances | 466 | 2,032 | (1,104 | ) | ||||||||
Restricted units non-cash amortization expense | 1,808 | 2,231 | 1,661 | |||||||||
Income tax provision (benefit) | 765 | (2,730 | ) | (547 | ) | |||||||
Interest - net including realized risk | ||||||||||||
management instruments and other expense | 9,302 | 11,256 | 9,780 | |||||||||
Other (income)/expense | (268 | ) | (560 | ) | (493 | ) | ||||||
Discontinued operations | (28 | ) | (307 | ) | (24 | ) | ||||||
Adjusted EBITDA | $ | 36,805 | $ | 41,105 | $ | 51,427 | ||||||
Net income (loss) to distributable cash flow | ||||||||||||
Net income (loss), as reported | $ | 3,981 | $ | (2,545 | ) | $ | (68,655 | ) | ||||
Depreciation, depletion and | ||||||||||||
amortization expense | 29,435 | 30,063 | 30,025 | |||||||||
Impairment | - | 242 | 21,546 | |||||||||
Risk management interest related | ||||||||||||
instruments-unrealized | 4,822 | (3,099 | ) | (2,784 | ) | |||||||
Risk management commodity related | ||||||||||||
instruments-unrealized, including amortization of | ||||||||||||
commodity derivative costs | (13,478 | ) | 4,522 | 62,022 | ||||||||
Capital expenditures-maintenance related | (5,184 | ) | (3,645 | ) | (6,816 | ) | ||||||
Non-cash mark-to-market of Upstream product imbalances | 466 | 2,032 | (1,104 | ) | ||||||||
Restricted units non-cash amortization expense | 1,808 | 2,231 | 1,661 | |||||||||
Other operating (income) expenses (non-recurring) | - | - | - | |||||||||
Income tax provision (benefit) | 765 | (2,730 | ) | (547 | ) | |||||||
Other (income)/expense | (268 | ) | (560 | ) | (493 | ) | ||||||
Cash income taxes | (416 | ) | (77 | ) | (617 | ) | ||||||
Discontinued operations | (28 | ) | (307 | ) | (24 | ) | ||||||
Distributable cash flow | $ | 21,903 | $ | 26,127 | $ | 34,214 | ||||||
Supplemental Information | ||||||||||||
($ in thousands) | ||||||||||||
Three Months | Three Months | |||||||||||
Ended March 31, | Ended | |||||||||||
2010 | 2009 | December 31, 2009 | ||||||||||
Amortization of commodity derivative costs | 2,648 | 12,159 | 14,477 |