| August 4, 2010 | EXHIBIT 99.1 |
| | |
Eagle Rock Reports Second-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 June 30, 2010. Financial highlights with respect to second-quarter 2010 included the following (all current and historical financial results for the Partnership’s Minerals Business, which was sold during the quarter, have been removed from the operating financial results and are reflected in Discontinued Operations):
| · | Adjusted EBITDA totaled $32.1 million, up slightly from the $31.7 million reported in first-quarter 2010. |
| · | Repaid $172.0 million of outstanding borrowings during the quarter, reducing total debt outstanding under its revolving credit facility to $565.4 million as of June 30, 2010. |
| · | Distributable Cash Flow totaled $15.5 million, a decrease of 8% as compared to the $16.8 million reported in first-quarter 2010 due primarily to higher maintenance capital expenditures. |
| · | Reported net income of $68.1 million, as compared to net income of $4.0 million for first-quarter 2010. The increase is primarily due to unrealized gains on commodity derivatives and the gain on the sale of the Minerals Business. |
| · | Announced a quarterly distribution with respect to the second quarter of 2010 of $0.025 per common unit, unchanged from the distribution paid with respect to first-quarter 2010. |
On May 21, 2010, the Partnership received unitholder approval for its Recapitalization and Related Transactions (as outlined in the Partnership’s definitive proxy statement filed with the Securities and Exchange Commission on March 30, 2010 (the “Proxy Statement”)), which resulted in the following significant events during the second quarter:
| · | The consummation of the sale of the Partnership’s Minerals Business for approximately $171.6 million in cash on May 24th. |
| · | The contribution to the Partnership and subsequent cancellation of all 20.7 million subordinated units and all outstanding incentive distribution rights on May 24th. |
| · | The issuance of approximately 4.8 million common units to an affiliate of Natural Gas Partners as payment of the transaction fee in connection with completion of the Recapitalization and Related Transactions on May 24th. |
| · | The completion of a rights offering during the month of June 2010 which generated cash proceeds of approximately $53.9 million (the offering closed on July 8, 2010 and, therefore, the financial impact is not reflected in the second quarter results). |
An additional key aspect of the Recapitalization and Related Transactions occurred following the end of the quarter with the Partnership’s exercise of its option to acquire its general partner entities from affiliates of Natural Gas Partners (the “GP Acquisition”) on July 30, 2010. In connection with the completion of the GP Acquisition, the size of Eagle Rock's board of directors was expanded from seven to nine directors. Ms. Peggy A. Heeg and Mr. Herbert C. Williamson, III were appointed by the Conflicts Committee of Eagle Rock’s Board of Directors to fill the new vacancies. Ms. Heeg and Mr. Williamson have each been determined by the Board to be “independent” in accordance with the rules and regulations of the Securities and Exchange Commission and the applicabl e NASDAQ requirements.
“We accomplished a number of important strategic initiatives during the second quarter, and we appreciate the support shown by our unitholders in the successful vote approving the recapitalization transactions and in the oversubscribed rights offering,” said Joseph A. Mills, Chairman and Chief Executive Officer. “With the completion of the rights offering in July, we have further reduced borrowings outstanding under our credit facility to approximately $515 million. This represents over $320 million of debt repayment since we embarked on our program to strengthen the balance sheet in the second quarter of 2009.”
Mr. Mills added, “With the substantial completion of the Recapitalization and Related Transactions, we now are turning our full attention to delivering superior operational results in this continued challenging commodity environment. We are excited about our prospects and growth opportunities and are focused on reinstating a more meaningful distribution to our unitholders beginning with respect to the fourth quarter of 2010.”
Second-Quarter 2010 Financial and Operating Results
Second-quarter 2010 results were impacted by a number of non-recurring items. In the Upstream Business, the Partnership completed a scheduled 12-day turnaround at its Big Escambia Creek facility in April and May. The turnaround resulted in (i) approximately 185 MMcfe of deferred production which negatively impacted net revenues by approximately $1.6 million and (ii) additional operating expense in the quarter of approximately $1.3 million. In the Midstream Business, reported revenues in the second quarter of 2010 benefitted from $6.5 million of volumetric commitment payments from certain producers in the East Texas / Louisiana segment.
Second-quarter 2010 results, relative to those reported in first quarter of 2010, were negatively impacted by the Partnership’s commodities derivative portfolio. The weighted average strike price on Eagle Rock’s crude hedges in the second quarter of 2010 was $61.96 per barrel, as compared to $75.48 per barrel in the first quarter of 2010. As a result, cash flow from realized commodity derivative settlements fell by $3.1 million to a realized net loss of $5.8 million in second-quarter 2010 as compared to a realized net loss of $2.7 million in first-quarter 2010. The weighted average strike price on the Partnership’s crude hedges for the remainder of 2010 increases to $69.10 per barrel, which represents an 11.5% increase from the average strike price in the second quarter.
Eagle Rock analyzes and manages its operations under six distinct segments: four segments in its Midstream Business - the Texas Panhandle, East Texas/Louisiana, South Texas and Gulf of Mexico Segments - and the Upstream and Corporate 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 second quarter of 2010 to those of the first quarter of 2010. The Partnership believes comparing these periods is more illustrative of current operating trends than comparing the current quarter to results achieved in the second quarter of 2009. Please refer to the financial tables at the end of this release for further det ailed information.
Midstream Business – Operating income, excluding the impact of impairments, for the Midstream Business in the second quarter of 2010 increased by $3.9 million, or 31%, compared to the first quarter of 2010. The increase was due primarily to a 9% increase in equity liquids and condensate volumes as well as $6.5 million of volume deficiency payments from the Partnership’s producer customers in its East Texas / Louisiana segment during the second quarter as compared to $1.6 million of volume deficiency payments during the first quarter. These factors were partially offset by lower realized prices in the quarter.
In the Texas Panhandle, gathered volumes were up 3.2%, with combined equity NGL and condensate volumes up 15.8%, compared to the first quarter of 2010. The increase in the Partnership’s equity NGL and condensate gallons was due primarily to inclement weather which negatively impacted recoveries in the first quarter of 2010, as well as certain accounting adjustments made in the first quarter of 2010.
In East Texas, gathered volumes were slightly down 0.8% with equity NGL and condensate volumes down 10.7% compared to the first quarter of 2010. Equity NGL and equity condensate volumes were down primarily due to certain accounting adjustments made in the first quarter of 2010 as well as reduced drilling activity and a higher percentage of dry gas gathered in the second quarter of 2010. Specifically, a portion of the “liquids-rich” gas that has typically been gathered from the Austin Chalk in the Partnership’s East Texas segment has been replaced with new “dry” gas from the Deep Bossier, Haynesville Shale and Angelina River Trend basins. The Partnership anticipates increased drilling activity in the liquids-rich Austin Chalk in the upcoming months.
In South Texas, gathered volumes were down 5.9%, with equity NGL and condensate volumes up 6.5%, compared to the first quarter of 2010. Equity NGL and equity condensate volumes were up despite the lower gathering volumes due to scheduled pipeline “pigging” operations during the quarter which resulted in increased NGL and condensate recoveries.
In the Gulf of Mexico, gathered volumes were down 4.3%, with equity NGL volumes down 7.0%. The reduced gathering volumes and equity NGL volumes in the Gulf of Mexico segment were primarily a result of reduced drilling and workover activity on the leases committed to Eagle Rock’s gathering systems. New shallow water drilling and workover activity have generally been delayed due to the uncertainty caused by the federal government’s offshore drilling moratorium.
Upstream Business – Operating income for Eagle Rock’s Upstream Business in the second quarter of 2010 increased by $1.3 million, or 25%, compared to the first quarter of 2010. The increase was attributable to higher realized crude oil, condensate and sulfur prices and 6.7% higher production volumes, despite approximately 185 MMcfe of deferred production due to the Big Escambia Creek (“BEC”) facility turnaround in the second quarter. Management continues to see strength in sulfur demand and anticipates positive cash flow from its sulfur production over the next three to six months.
The Partnership completed a scheduled 12-day turnaround at its Big Escambia Creek facility in April and May. The total impact lowered operating income during the second quarter by approximately $2.9 million. The Partnership also conducted a reallocation of plant products and pricing at the BEC facility during the second quarter which lowered reported revenues by approximately $1.3 million. This amount was offset by a reversal of an accrual related to a revenue sharing arrangement at the Partnership’s Flomaton field because the required minimum volumes, pursuant to the contract, were not met.
Total revenue for second-quarter 2010, including the impact of Eagle Rock’s realized and unrealized derivative gains and losses, remained flat at $222.9 million, compared with $223.0 million reported for first-quarter 2010. While revenues associated with the sale of crude oil, natural gas, NGLs, condensate and sulfur were down relative to the first quarter of 2010 largely due to lower average realized prices and reduced drilling activity, these decreases were partially offset by the Partnership’s unrealized gain on commodity derivates. Eagle Rock recorded an unrealized gain on commodity derivatives of $41.4 million in second-quarter 2010, as compared to $13.5 million of an unrealized gain on commodity derivatives in first-quarter 2010. The unrealized gain (loss) on commodity derivatives is a no n-cash, mark-to-market amount which includes the amortization of commodity hedging costs. Second-quarter 2010 revenues included a realized loss on commodity derivatives of $5.8 million, as compared to a realized loss of $2.7 million in first-quarter 2010.
Adjusted EBITDA was $32.1 million and Distributable Cash Flow was $15.5 million for the second quarter of 2010. The Partnership’s distribution of $0.025 per common unit with respect to the second quarter of 2010 will be paid on August 13, 2010 to the Partnership’s common unitholders of record at the close of business on August 9, 2010.
Capitalization and Liquidity Update
Total debt outstanding under the Partnership’s revolving credit facility as of June 30, 2010 was approximately $565.4 million. Outstanding borrowings were reduced by $172 million during the second quarter of 2010 from proceeds from the sale of its Minerals Business. The Partnership has repaid an additional $50 million since June 30, 2010 using proceeds from the rights offering, increasing the total debt reduction since April 30, 2009 to $322 million.
As of June 30, 2010, the revolving credit facility had aggregate commitments of approximately $871 million after adjusting for the unfunded portion of Lehman Brothers’ commitment and the Second Amendment to the credit facility which obligated the Partnership to use $100 million of the proceeds from the sale of its Mineral Business to make a mandatory prepayment towards its outstanding borrowings and reduced the Partnership’s borrowing capacity under the facility by $100 million. 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 Business. 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. Unused capacity available under the credit facility, based on financial covenants, was approximately $178 million as of June 30, 2010.
Update Regarding Distribution Policy
Currently, management intends to recommend to the board of directors of Eagle Rock a distribution increase to an annualized rate of $0.60 per unit commencing with respect to the fourth quarter of 2010 (payable in February 2011). This annualized distribution level would be at the high end of the $0.40 - $0.60 per unit range contemplated in the Proxy Statement.
Management expects this distribution level will allow the Partnership to retain a meaningful percentage of its available cash (i.e., in excess of management’s intended long-term coverage ratio of 1.20x – 1.30x) to fund potential organic growth projects or to further strengthen its balance sheet through debt repayment. Future increases in the distribution level, if any, will be driven by market conditions, future commodity prices, the Partnership's leverage levels, the performance of the Partnership's underlying assets and the Partnership's ability to consummate accretive growth projects or acquisitions.
The board of directors has revised the Partnership's distribution policy as described in the Proxy Statement in that the distribution policy will not include a variable component to the distribution based on movements in commodity prices.
Management's distribution recommendation is subject to change should factors affecting the general business climate or the Partnership's specific operations differ from current expectations. All actual distributions paid will be determined and declared at the discretion of the Eagle Rock board of directors.
Update Regarding Announced Organic Growth Projects
In February 2010, the Partnership announced its intention to deploy a currently idle high-efficiency cryogenic plant to the Texas Panhandle in order to increase efficiency and accommodate volume growth from the Granite Wash Play. Deployment of the cryogenic plant (the “Phoenix Plant”), in replacement of an aging facility, is phase two of the Partnership’s Texas Panhandle consolidation and processing capacity expansion project originally announced in February 2008. The project is on schedule, within its budget and anticipated to be completed in late third quarter 2010. Initial capacity of the Phoenix Plant will be 50 MMcf/d with the ability to expand to 80 MMcf/d through additional compression.
In April 2010, the Partnership announced 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 Haynesville and Middle Bossier shale plays in Nacogdoches and San Augustine Counties. The Partnership has elected not to initiate construction of the pipeline at this time due to the lack of firm volume commitments at fees that provide what Eagle Rock believes is an acceptable rate of return. As the shale play continues to move west, the Partnership will take advantage of its existing asset base along with life-of-lease dedicated acreage that will benefit from the future drilling. The Partnership remains committed to servicing its customers in this area and will continue to evaluate growth opportunities in the area that m eet its rate of return and accretion targets.
Hedging Update
On July 23, 2010, Eagle Rock enhanced its commodity derivative portfolio by adjusting the strike price of certain hedges to the forward market prices as of the date the hedges were executed. Specifically, the Partnership paid $5.9 million to adjust the strike price from $53.55 to $79.80 per barrel on existing NYMEX WTI crude oil swaps of 45,000 barrels per month for the five months ended December 31, 2010.
On August 3, 2010, the Partnership entered into a forward NYMEX WTI swap covering 29,000 barrels per month for the first half of calendar 2011 and 23,000 barrels per month for the second half of calendar 2011 with a strike price of $86.20 per barrel. On the same day, the Partnership entered into a forward NYMEX WTI swap covering 10,000 barrels per month for the full calendar year 2013 with a strike price of $88.20 per barrel.
On August 4, 2010, the Partnership entered into a forward NYMEX Henry Hub swap covering 50,000 MMBtu per month for the full calendar year 2013 with a strike price of $5.645 per MMBtu.
On August 4, 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 second-quarter financial and operating results on Thursday, August 5, 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 888-679-8033, confirmation code 76430184. 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=PUL4FD4R9. Interested parties can also view important information about the Partnership’s conference call by following this link. Pre-registering is not mandatory but is recommended as it will provide you immediate entry to the call and will facilitate the timely start of the call. Pre-registration only takes a few minutes and you may pre-register at any time, including up to and after the start of the call. An audio replay of the conference call will also be available for thirty days by dialing 888-286-8010, confirmation code 35041285. In addition, a replay of the audio webcast will be available by accessing the Partnership’s website after the call is concluded.
About the Partnership
The Partnership is a growth-oriented master limited partnership engaged in two businesses: a) midstream, which includes (i) gathering, compressing, treating, processing and transporting natural gas; (ii) fractionating and transporting natural gas liquids; and (iii) marketing natural gas, condensate and NGLs; b) upstream, which includes acquiring, exploiting, developing, and producing hydrocarbons in oil and natural gas properties. Its corporate office is located in Houston, Texas.
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 usefu l in determining Eagle Rock’s ability to sustain or increase distributions. By excluding unrealized derivative gains (losses), a non-cash, mark-to-market benefit (charge) which represents the change in fair market value of the Partnership’s executed derivative instruments and is independent of its assets’ performance or cash flow generating ability, Eagle Rock believes Adjusted EBITDA reflects more accurately the Partnership’s ability to generate cash sufficient to pay interest costs, support its level of indebtedness, make cash distributions to its unitholders and 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 prices higher than those reflected in the forward curve at the time of the transaction or to purchase puts or other similar floors despite the fact that the Partnership excludes from Adjusted EBITDA any charge for amortization of the cost of such commodity hedge reset transactions or puts. Eagle Rock has reconciled Adjusted EBITDA to the GAAP financial measure of net income (loss) at the end of this release.
Distributable Cash Flow is defined as Adjusted EBITDA minus: (i) maintenance capital expenditures; (ii) cash interest expense; (iii) cash income taxes; and (iv) the addition of losses or subtraction of gains relating to other miscellaneous non-cash amounts affecting net income (loss) for the period. Maintenance capital expenditures represent: 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 t o 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.
Eagle Rock Energy Partners, L.P. | | | | |
| Consolidated Statements of Operations | | | | |
| ($ in thousands) | | | | |
| (unaudited) | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | Three Months | | | Six Months | | | Three Months | |
| | | Ended June 30, | | | Ended June 30, | | | Ended | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | | | March 31, 2010 | |
| | | | | | | | | | | | | | | | |
| REVENUE: | | | | | | | | | | | | | | | |
| Natural gas, NGLs, condensate, oil | | | | | | | | | | | | | | | |
| and sulfur sales | | $ | 170,998 | | | $ | 153,320 | | | $ | 370,294 | | | $ | 311,810 | | | $ | 199,296 | |
| Gathering, compression, processing and treating fees | | | 16,541 | | | | 11,562 | | | | 29,374 | | | | 23,229 | | | | 12,833 | |
| Unrealized commodity derivative gains (losses) | | | 41,405 | | | | (97,044 | ) | | | 54,883 | | | | (101,566 | ) | | | 13,478 | |
| Realized commodity derivative gains (losses) | | | (5,813 | ) | | | 22,483 | | | | (8,496 | ) | | | 53,261 | | | | (2,683 | ) |
| Other income | | | (251 | ) | | | 1,678 | | | | (215 | ) | | | 1,720 | | | | 36 | |
| Total Revenue | | | 222,880 | | | | 91,999 | | | | 445,840 | | | | 288,454 | | | | 222,960 | |
| | | | | | | | | | | | | | | | | | | | | |
| COSTS AND EXPENSES: | | | | | | | | | | | | | | | | | | | | |
| Cost of natural gas and NGLs | | | 113,926 | | | | 115,640 | | | | 258,204 | | | | 248,857 | | | | 144,278 | |
| Operations and maintenance | | | 19,176 | | | | 18,751 | | | | 43,136 | | | | 36,921 | | | | 19,235 | |
| Taxes other than income | | | 3,999 | | | | 2,878 | | | | 2,811 | | | | 5,856 | | | | 3,537 | |
| Impairment | | | 3,130 | | | | - | | | | 3,130 | | | | 242 | | | | - | |
| General and administrative | | | 12,806 | | | | 11,866 | | | | 25,817 | | | | 24,379 | | | | 13,011 | |
| Other operating income | | | - | | | | (3,552 | ) | | | - | | | | (3,552 | ) | | | - | |
| Depreciation, depletion and amortization | | | 28,050 | | | | 26,136 | | | | 56,076 | | | | 54,524 | | | | 28,026 | |
| Total Costs and Expenses | | | 181,087 | | | | 171,719 | | | | 389,174 | | | | 367,227 | | | | 208,087 | |
| | | | | | | | | | | | | | | | | | | | | |
| OPERATING INCOME (LOSS) | | | 41,793 | | | | (79,720 | ) | | | 56,666 | | | | (78,773 | ) | | | 14,873 | |
| | | | | | | | | | | | | | | | | | | | | |
| Other Income (Expense): | | | | | | | | | | | | | | | | | | | | |
| Interest income | | | 173 | | | | 141 | | | | 175 | | | | 172 | | | | 2 | |
| Other income | | | (21 | ) | | | 199 | | | | 78 | | | | 283 | | | | 99 | |
| Interest expense, net | | | (3,833 | ) | | | (5,428 | ) | | | (7,978 | ) | | | (12,967 | ) | | | (4,145 | ) |
| Unrealized interest rate derivative gains (losses) | | | (4,354 | ) | | | 11,954 | | | | (9,176 | ) | | | 15,053 | | | | (4,822 | ) |
| Realized interest rate derivative gains (losses) | | | (4,952 | ) | | | (5,147 | ) | | | (9,842 | ) | | | (8,629 | ) | | | (4,890 | ) |
| Other expense | | | (551 | ) | | | (267 | ) | | | (820 | ) | | | (534 | ) | | | (269 | ) |
| Total Other Income (Expense) | | | (13,538 | ) | | | 1,452 | | | | (27,563 | ) | | | (6,622 | ) | | | (14,025 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | | | 28,255 | | | | (78,268 | ) | | | 29,103 | | | | (85,395 | ) | | | 848 | |
| | | | | | | | | | | | | | | | | | | | | |
| Income tax (benefit) provision | | | (415 | ) | | | (1,512 | ) | | | 296 | | | | (4,276 | ) | | | 711 | |
| | | | | | | | | | | | | | | | | | | | | |
| INCOME (LOSS) FROM CONTINUING OPERATIONS | | | 28,670 | | | | (76,756 | ) | | | 28,807 | | | | (81,119 | ) | | | 137 | |
| | | | | | | | | | | | | | | | | | | | | |
| DISCONTINUED OPERATIONS | | | 39,473 | | | | 1,969 | | | | 43,317 | | | | 3,787 | | | | 3,844 | |
| | | | | | | | | | | | | | | | | | | | | |
| NET INCOME (LOSS) | | $ | 68,143 | | | $ | (74,787 | ) | | $ | 72,124 | | | $ | (77,332 | ) | | $ | 3,981 | |
| Eagle Rock Energy Partners, L.P. | |
| Consolidated Balance Sheets | |
| ($ in thousands) | |
| (unaudited) | |
| | | | | | | | |
| | | | | | | | |
| | | | June 30, | | | December 31, | |
| | | | 2010 | | | 2009 | |
| | | | | | | | |
| Assets | | | | | | | |
| Current assets: | | | | | | |
| | Cash and cash equivalents | | $ | 6,321 | | | $ | 2,732 | |
| | Accounts receivable | | | 78,209 | | | | 88,122 | |
| | Risk management assets | | | 10,035 | | | | 2,479 | |
| | Prepayments and other current assets | | | 3,425 | | | | 2,790 | |
| | Assets held for sale | | | - | | | | 135,224 | |
| | | | | 97,990 | | | | 231,347 | |
| | | | | | | | | | |
| Property plant and equipment - net | | | 1,139,337 | | | | 1,155,733 | |
| Intangible assets - net | | | 121,524 | | | | 132,343 | |
| Deferred tax asset | | | 1,813 | | | | 1,562 | |
| Risk management assets | | | 16,857 | | | | 3,410 | |
| Other assets | | | 10,854 | | | | 9,933 | |
| Total assets | | $ | 1,388,375 | | | $ | 1,534,328 | |
| | | | | | | | | | |
| Liabilities and Members' Equity | | | | | | | | |
| Current liabilities: | | | | | | | | |
| | Accounts payable | | $ | 75,620 | | | $ | 77,946 | |
| | Due to affiliate | | | 9,516 | | | | 12,910 | |
| | Accrued liabilities | | | 10,206 | | | | 11,110 | |
| | Taxes payable | | | 1,989 | | | | 2,416 | |
| | Risk management liabilities | | | 34,514 | | | | 51,650 | |
| | Liabilities held for sale | | | - | | | | 150 | |
| | | | | 131,845 | | | | 156,182 | |
| | | | | | | | | | |
| Long-term debt | | | 565,383 | | | | 754,383 | |
| Asset retirement obligations | | | 20,630 | | | | 19,829 | |
| Deferred tax liability | | | 40,237 | | | | 40,246 | |
| Risk management liabilities | | | 25,146 | | | | 32,715 | |
| Other Long-term liabilities | | | 566 | | | | 575 | |
| | | | | | | | | | |
| Members' equity | | | | | | | | |
| | Common unitholders | | | 610,131 | | | | 484,282 | |
| | Subordinated unitholders | | | - | | | | 52,058 | |
| | General partner | | | (5,563 | ) | | | (5,942 | ) |
| | | | | 604,568 | | | | 530,398 | |
| Total Liabilities and Members' Equity | | $ | 1,388,375 | | | $ | 1,534,328 | |
| Eagle Rock Energy Partners, L.P. | | | | |
| Segment Summary | | | | |
| Operating Income | | | | |
| ($ in thousands) | | | | |
| (unaudited) | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | Three Months | | | Six Months | | | Three Months | |
| | | | Ended June 30, | | | Ended June 30, | | | Ended | |
| | | | 2010 | | | 2009 | | | 2010 | | | 2009 | | | March 31, 2010 | |
| | | | | | | | | | | | | | | | | |
| Midstream | | | | | | | | | | | | | | | |
| Revenues: | | | | | | | | | | | | | | | |
| | Natural gas, NGLs, oil and condensate sales | | $ | 146,486 | | | $ | 138,213 | | | $ | 323,133 | | | $ | 286,624 | | | $ | 176,647 | |
| | Gathering, compression, processing and treating services | | | 16,541 | | | | 11,562 | | | | 29,374 | | | | 23,229 | | | | 12,833 | |
| | Other | | | - | | | | 1,616 | | | | - | | | | 1,619 | | | | - | |
| | Total revenues | | | 163,027 | | | | 151,391 | | | | 352,507 | | | | 311,472 | | | | 189,480 | |
| Cost of natural gas and NGLs | | | 113,926 | | | | 115,640 | | | | 258,204 | | | | 248,857 | | | | 144,278 | |
| Operating costs and expenses: | | | | | | | | | | | | | | | | | | | | |
| | Operations and maintenance | | | 14,251 | | | | 14,311 | | | | 27,916 | | | | 28,487 | | | | 13,665 | |
| | Impairment | | | 3,130 | | | | - | | | | 3,130 | | | | - | | | | - | |
| | Depletion, depreciation and amortization | | | 18,510 | | | | 17,963 | | | | 37,618 | | | | 36,742 | | | | 19,108 | |
| | Total operating costs and expenses | | | 35,891 | | | | 32,274 | | | | 68,664 | | | | 65,229 | | | | 32,773 | |
| Operating income (loss) from continuing operations | | | 13,210 | | | | 3,477 | | | | 25,639 | | | | (2,614 | ) | | | 12,429 | |
| Discontinued Operations | | | - | | | | (67 | ) | | | 28 | | | | 240 | | | | 28 | |
| Operating income | | $ | 13,210 | | | $ | 3,410 | | | $ | 25,667 | | | $ | (2,374 | ) | | $ | 12,457 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| Upstream | | | | | | | | | | | | | | | | | | | | |
| Revenues: | | | | | | | | | | | | | | | | | | | | |
| | Oil and condensate (1) | | $ | 12,377 | | | $ | 8,598 | | | $ | 23,362 | | | $ | 14,556 | | | $ | 10,985 | |
| | Natural gas (2) | | | 4,733 | | | | 2,965 | | | | 9,365 | | | | 4,860 | | | | 4,632 | |
| | NGLs (3) | | | 5,290 | | | | 3,544 | | | | 11,254 | | | | 5,770 | | | | 5,964 | |
| | Sulfur | | | 2,112 | | | | - | | | | 3,180 | | | | - | | | | 1,068 | |
| | Other | | | (251 | ) | | | 62 | | | | (215 | ) | | | 101 | | | | 36 | |
| | Total revenues | | | 24,261 | | | | 15,169 | | | | 46,946 | | | | 25,287 | | | | 22,685 | |
| Operating costs and expenses: | | | | | | | | | | | | | | | | | | | | |
| | Operations and maintenance | | | 8,010 | | | | 6,601 | | | | 17,302 | | | | 13,133 | | | | 9,292 | |
| | Sulfur disposal costs | | | 914 | | | | 717 | | | | 729 | | | | 1,157 | | | | (185 | ) |
| | Impairment | | | - | | | | - | | | | - | | | | 242 | | | | - | |
| | Other operating income | | | - | | | | (3,552 | ) | | | - | | | | (3,552 | ) | | | - | |
| | Depreciation, depletion and amortization | | | 9,058 | | | | 7,955 | | | | 17,623 | | | | 17,351 | | | | 8,565 | |
| | Total operating costs and expenses | | | 17,982 | | | | 11,721 | | | | 35,654 | | | | 28,331 | | | | 17,672 | |
| Operating income | | $ | 6,279 | | | $ | 3,448 | | | $ | 11,292 | | | $ | (3,044 | ) | | $ | 5,013 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| Corporate | | | | | | | | | | | | | | | | | | | | |
| Revenues: | | | | | | | | | | | | | | | | | | | | |
| | Unrealized commodity derivative gains (losses) | | $ | 41,405 | | | $ | (97,044 | ) | | $ | 54,883 | | | $ | (101,566 | ) | | $ | 13,478 | |
| | Realized commodity derivative (losses) gains | | | (5,813 | ) | | | 22,483 | | | | (8,496 | ) | | | 53,261 | | | | (2,683 | ) |
| | Total revenues | | | 35,592 | | | | (74,561 | ) | | | 46,387 | | | | (48,305 | ) | | | 10,795 | |
| General and administrative | | | 12,806 | | | | 11,866 | | | | 25,817 | | | | 24,379 | | | | 13,011 | |
| Depreciation, depletion and amortization | | | 482 | | | | 218 | | | | 835 | | | | 431 | | | | 353 | |
| Operating income (loss) | | $ | 22,304 | | | $ | (86,645 | ) | | $ | 19,735 | | | $ | (73,115 | ) | | $ | (2,569 | ) |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| (1) | Revenues include a change in the value of product imbalances of $181, $0, $(247), $(260) and $(185) for the three and six months ended June 30, 2010 and 2009 and the three months ended March 31, 2010, respectively. | | | | | |
| (2) | Revenues include a change in the value of product imbalances of $845, $567, $284, $(1,563) and $(278) for the three and six months ended June 30, 2010 and 2009 and the three months ended March 31, 2010, respectively. | | | | | |
| (3) | Revenues include a change in the value of product imbalances of $167and $28 for the three and six months ended June 30, 2009, respectively. | | | | | |
| Eagle Rock Energy Partners, L.P. | | | | |
| Midstream Segment | | | | |
| Operating Income | | | | |
| ($ in thousands) | | | | |
| (unaudited) | | | | |
| | | | | | | | | | | | | | | | |
| | | Three Months | | | Six Months | | | Three Months | |
| | | Ended June 30, | | | Ended June 30, | | | Ended | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | | | March 31, 2010 | |
| | | | | | | | | | | | | | | | |
| Texas Panhandle | | | | | | | | | | | | | | | |
| Revenues: | | | | | | | | | | | | | | | |
| Natural gas, NGLs, oil and condensate sales | | $ | 80,955 | | | | 66,373 | | | $ | 171,688 | | | $ | 129,323 | | | $ | 90,733 | |
| Gathering, compression, processing, and treating services | | | 3,048 | | | | 2,601 | | | | 5,990 | | | | 5,414 | | | | 2,942 | |
| Total revenues | | | 84,003 | | | | 68,974 | | | | 177,678 | | | | 134,737 | | | | 93,675 | |
| Cost of natural gas and NGLs | | | 54,732 | | | | 49,407 | | | | 121,702 | | | | 101,354 | | | | 66,970 | |
| Operating costs and expenses: | | | | | | | | | | | | | | | | | | | | |
| Operations and maintenance | | | 8,413 | | | | 8,056 | | | | 16,511 | | | | 16,201 | | | | 8,098 | |
| Depreciation, depletion and amortization | | | 11,639 | | | | 10,962 | | | | 23,229 | | | | 22,058 | | | | 11,590 | |
| Total operating costs and expenses | | | 20,052 | | | | 19,018 | | | | 39,740 | | | | 38,259 | | | | 19,688 | |
| Operating income | | $ | 9,219 | | | $ | 549 | | | $ | 16,236 | | | $ | (4,876 | ) | | $ | 7,017 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| East Texas/Louisiana | | | | | | | | | | | | | | | | | | | | |
| Revenues: | | | | | | | | | | | | | | | | | | | | |
| Natural gas, NGLs, oil and condensate sales | | $ | 38,623 | | | $ | 41,245 | | | $ | 90,464 | | | $ | 88,696 | | | $ | 51,841 | |
| Gathering, compression, processing, and treating services | | | 12,156 | | | | 7,375 | | | | 20,678 | | | | 14,584 | | | | 8,522 | |
| Total revenues | | | 50,779 | | | | 48,620 | | | | 111,142 | | | | 103,280 | | | | 60,363 | |
| Cost of natural gas and NGLs | | | 34,477 | | | | 37,233 | | | | 80,682 | | | | 82,242 | | | | 46,205 | |
| Operating costs and expenses: | | | | | | | | | | | | | | | | | | | | |
| Operations and maintenance | | | 4,210 | | | | 4,608 | | | | 8,419 | | | | 9,160 | | | | 4,209 | |
| Depreciation, depletion and amortization | | | 4,112 | | | | 4,240 | | | | 8,540 | | | | 9,011 | | | | 4,428 | |
| Total operating costs and expenses | | | 8,322 | | | | 8,848 | | | | 16,959 | | | | 18,171 | | | | 8,637 | |
| Operating income | | $ | 7,980 | | | $ | 2,539 | | | $ | 13,501 | | | $ | 2,867 | | | $ | 5,521 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| South Texas | | | | | | | | | | | | | | | | | | | | |
| Revenues: | | | | | | | | | | | | | | | | | | | | |
| Natural gas, NGLs, oil and condensate sales | | $ | 19,653 | | | $ | 24,751 | | | $ | 45,302 | | | $ | 56,539 | | | $ | 25,649 | |
| Gathering, compression, processing, and treating services | | | 1,164 | | | | 1,306 | | | | 2,098 | | | | 2,863 | | | | 934 | |
| Other | | | .- | | | | - | | | | - | | | | 3 | | | | - | |
| Total revenues | | | 20,817 | | | | 26,057 | | | | 47,400 | | | | 59,405 | | | | 26,583 | |
| Cost of natural gas and NGLs | | | 18,324 | | | | 23,819 | | | | 41,962 | | | | 54,888 | | | | 23,638 | |
| Operating costs and expenses: | | | | | | | | | | | | | | | | | | | | |
| Operations and maintenance | | | 1,097 | | | | 989 | | | | 1,950 | | | | 2,050 | | | | 853 | |
| Impairment | | | 3,130 | | | | - | | | | 3,130 | | | | - | | | | - | |
| Depreciation, depletion and amortization | | | 1,192 | | | | 1,284 | | | | 2,679 | | | | 2,708 | | | | 1,487 | |
| Total operating costs and expenses | | | 5,419 | | | | 2,273 | | | | 7,759 | | | | 4,758 | | | | 2,340 | |
| Operating income (loss) from continuing operations | | | (2,926 | ) | | | (35 | ) | | | (2,321 | ) | | | (241 | ) | | | 605 | |
| Discontinued Operations | | | - | | | | (67 | ) | | | 28 | | | | 240 | | | | 28 | |
| Operating income | | $ | (2,926 | ) | | $ | (102 | ) | | $ | (2,293 | ) | | $ | (1 | ) | | $ | 633 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Gulf of Mexico | | | | | | | | | | | | | | | | | | | | |
| Revenues: | | | | | | | | | | | | | | | | | | | | |
| Natural gas, NGLs, oil and condensate sales | | $ | 7,255 | | | $ | 5,844 | | | $ | 15,679 | | | $ | 12,066 | | | $ | 8,424 | |
| Gathering, compression, processing, and treating services | | | 173 | | | | 280 | | | | 608 | | | | 368 | | | | 435 | |
| Other | | | - | | | | 1,616 | | | | - | | | | 1,616 | | | | - | |
| Total revenues | | | 7,428 | | | | 7,740 | | | | 16,287 | | | | 14,050 | | | | 8,859 | |
| Cost of natural gas and NGLs | | | 6,393 | | | | 5,181 | | | | 13,858 | | | | 10,373 | | | | 7,465 | |
| Operating costs and expenses: | | | | | | | | | | | | | | | | | | | | |
| Operations and maintenance | | | 531 | | | | 658 | | | | 1,036 | | | | 1,076 | | | | 505 | |
| Depreciation, depletion and amortization | | | 1,567 | | | | 1,477 | | | | 3,170 | | | | 2,965 | | | | 1,603 | |
| Total operating costs and expenses | | | 2,098 | | | | 2,135 | | | | 4,206 | | | | 4,041 | | | | 2,108 | |
| Operating income | | $ | (1,063 | ) | | $ | 424 | | | $ | (1,777 | ) | | $ | (364 | ) | | $ | (714 | ) |
Eagle Rock Energy Partners, L.P. | |
| Midstream Operations Information | |
| (unaudited) | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | Three Months | | | Six Months | | | Three Months | |
| | | Ended June 30, | | | Ended June 30, | | | Ended | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | | | March 31, 2010 | |
| | | | | | | | | | | | | | | | |
| Gas gathering volumes - (Average Mcf/d) | | | | | | | | | | | | | | | |
| Texas Panhandle | | | 132,625 | | | | 143,281 | | | | 130,570 | | | | 143,740 | | | | 128,493 | |
| East Texas/Louisiana | | | 211,157 | | | | 265,740 | | | | 212,027 | | | | 268,654 | | | | 212,907 | |
| South Texas | | | 69,786 | | | | 90,395 | | | | 71,943 | | | | 93,885 | | | | 74,124 | |
| Gulf of Mexico | | | 97,926 | | | | 98,619 | | | | 100,096 | | | | 107,559 | | | | 102,291 | |
| Total | | | 511,494 | | | | 598,035 | | | | 514,636 | | | | 613,838 | | | | 517,815 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| NGLs - (Net equity gallons) | | | | | | | | | | | | | | | | | | | | |
| Texas Panhandle | | | 9,856,420 | | | | 11,815,414 | | | | 19,412,403 | | | | 22,450,463 | | | | 9,555,983 | |
| East Texas/Louisiana | | | 4,246,347 | | | | 6,166,467 | | | | 8,925,929 | | | | 8,842,886 | | | | 4,679,582 | |
| South Texas | | | 313,271 | | | | 452,942 | | | | 618,970 | | | | 677,447 | | | | 305,698 | |
| Gulf of Mexico | | | 1,011,256 | | | | 1,192,008 | | | | 2,098,573 | | | | 2,904,158 | | | | 1,087,316 | |
| Total | | | 15,427,294 | | | | 19,626,831 | | | | 31,055,875 | | | | 34,874,954 | | | | 15,628,579 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Condensate - (Net equity gallons) | | | | | | | | | | | | | | | | | | | | |
| Texas Panhandle | | | 11,312,296 | | | | 9,813,579 | | | | 20,013,928 | | | | 16,006,005 | | | | 8,719,633 | |
| East Texas/Louisiana | | | 352,446 | | | | 466,348 | | | | 823,739 | | | | 901,639 | | | | 471,293 | |
| South Texas | | | 528,120 | | | | 309,186 | | | | 1,012,186 | | | | 956,646 | | | | 484,066 | |
| Total | | | 12,192,862 | | | | 10,589,113 | | | | 21,849,853 | | | | 17,864,290 | | | | 9,674,992 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Natural gas short position - (Average MMbtu/d) | | | | | | | | | | | | | | | | | | | | |
| Texas Panhandle | | | (7,134 | ) | | | (5,748 | ) | | | (5,725 | ) | | | (5,943 | ) | | | (4,301 | ) |
| East Texas/Louisiana | | | 719 | | | | 2,798 | | | | 1,270 | | | | 3,036 | | | | 1,828 | |
| South Texas | | | 1,152 | | | | 500 | | | | 1,108 | | | | 500 | | | | 1,063 | |
| Total | | | (5,263 | ) | | | (2,450 | ) | | | (3,347 | ) | | | (2,407 | ) | | | (1,410 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Average realized NGL price - per Bbl | | | | | | | | | | | | | | | | | | | | |
| Texas Panhandle | | | $45.95 | | | | $29.82 | | | | $47.08 | | | | $27.26 | | | | $48.22 | |
| East Texas/Louisiana | | | $33.26 | | | | $22.23 | | | | $36.03 | | | | $20.66 | | | | $39.02 | |
| South Texas | | | $43.91 | | | | $29.68 | | | | $46.95 | | | | $27.96 | | | | $49.98 | |
| Gulf of Mexico | | | $43.86 | | | | $29.57 | | | | $46.24 | | | | $28.76 | | | | $48.50 | |
| Weighted average | | | $42.33 | | | | $27.71 | | | | $44.28 | | | | $25.72 | | | | $46.26 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Average realized condensate price - per Bbl | | | | | | | | | | | | | | | | | | | | |
| Texas Panhandle | | | $67.37 | | | | $59.08 | | | | $67.89 | | | | $53.69 | | | | $68.50 | |
| East Texas/Louisiana | | | $75.48 | | | | $60.87 | | | | $71.55 | | | | $56.13 | | | | $68.45 | |
| South Texas | | | $58.21 | | | | $55.55 | | | | $66.41 | | | | $40.80 | | | | $78.36 | |
| Weighted average | | | $67.29 | | | | $59.07 | | | | $68.08 | | | | $53.48 | | | | $69.00 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Average realized natural gas price - per MMbtu | | | | | | | | | | | | | | | | | | | | |
| Texas Panhandle | | | $3.45 | | | | $2.66 | | | | $4.28 | | | | $3.06 | | | | $5.20 | |
| East Texas/Louisiana | | | $4.94 | | | | $3.45 | | | | $5.45 | | | | $3.90 | | | | $5.89 | |
| South Texas | | | $3.85 | | | | $3.31 | | | | $4.66 | | | | $3.87 | | | | $5.44 | |
| Weighted average | | | $3.97 | | | | $3.08 | | | | $4.73 | | | | $3.55 | | | | $5.48 | |
Eagle Rock Energy Partners, L.P. | |
| Upstream Operations Information | |
| (unaudited) | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | Three Months | | | Six Months | | | Three Months | |
| | | June 30, | | | June 30, | | | Ended | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | | | March 31, 2010 | |
| | | | | | | | | | | | | | | | |
| Upstream | | | | | | | | | | | | | | | |
Production: (1) | | | | | | | | | | | | | | | |
| Oil and condensate (Bbl) | | | 203,767 | | | | 203,225 | | | | 400,553 | | | | 410,115 | | | | 196,786 | |
| Gas (Mcf) | | | 1,022,627 | | | | 918,048 | | | | 1,978,529 | | | | 1,803,957 | | | | 955,902 | |
| NGLs (Bbl) | | | 132,085 | | | | 121,783 | | | | 250,370 | | | | 247,686 | | | | 118,285 | |
| Total Mcfe | | | 3,037,739 | | | | 2,868,094 | | | | 5,884,067 | | | | 5,750,760 | | | | 2,846,328 | |
| | | | | | | | | | | | | | | | | | | | | |
| Sulfur (Long ton) | | | 33,191 | | | | 39,823 | | | | 52,168 | | | | 68,428 | | | | 18,977 | |
| | | | | | | | | | | | | | | | | | | | | |
Realized prices, excluding derivatives: (1) (2) | | | | | | | | | | | | | | | | | | | | |
| Oil and condensate (per Bbl) | | | $60.10 | | | | $43.76 | | | | $58.32 | | | | $35.99 | | | | $56.55 | |
| Gas (per Mcf) | | | $4.06 | | | | $2.91 | | | | $4.60 | | | | $3.58 | | | | $5.21 | |
| NGLs (per Bbl) | | | $43.92 | | | | $27.57 | | | | $47,28 | | | | $23.18 | | | | $48.24 | |
| Sulfur (per Long ton) (4) | | | $102.96 | | | | 0.00 | | | | $73.34 | | | | 0.00 | | | | $44.04 | |
| | | | | | | | | | | | | | | | | | | | | |
| Operating statistics: | | | | | | | | | | | | | | | | | | | | |
Operating costs per Mcfe (incl production taxes) (3) | | | $2.64 | | | | $2.30 | | | | $2.94 | | | | $2.28 | | | | $3.26 | |
Operating costs per Mcfe (excl production taxes) (3) | | | $2.01 | | | | $1.68 | | | | $2.17 | | | | $1.67 | | | | $2.46 | |
| Operating Income per Mcfe | | | $2.07 | | | | $1.20 | | | | $1.92 | | | | $(0.53 | ) | | | $1.76 | |
| | | | | | | | | | | | | | | | | | | | | |
| Drilling program (gross wells): | | | | | | | | | | | | | | | | | | | | |
| Development wells | | | 2 | | | | - | | | | 3 | | | | 5 | | | | 1 | |
| Completions | | | 2 | | | | - | | | | 3 | | | | 4 | | | | 1 | |
| Workovers | | | 1 | | | | 4 | | | | 7 | | | | 6 | | | | 6 | |
| Recompletions | | | 3 | | | | 3 | | | | 6 | | | | 4 | | | | 3 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| (1) Volumes and realized prices for the three and six months ended June 30, 2010 and the three months ended March 31, 2010 have been revised from prior reported | |
| amounts due to a reallocation of our Big Escambia Creek wells. | | | | | | | | | | | | | | | | | | | | |
| (2) Calculation does not include impact of product imbalances. | | | | | | | | | | | | | | | | | | | | |
| (3) Excludes sulfur disposal costs of $0.9 million, $0.7 million, $0.7 million, $1.2 million and $(0.2) million for the three and six months ended June 30, 2010 and 2009 | | | | | |
| and the three months ended March 31, 2010, respectively. | | | | | | | | | | | | | | | | | | | | |
| (4) During the six months ended March 31, 2010, an adjustment was made to decrease sulfur volumes by 5,230 long tons related to | | | | | | | | | |
| a prior period adjustment. This adjustment excluded from the calculation of realized prices. | | | | | | | | | | | | | |
Non-GAAP Financial Measures
The following tables present a reconciliation of the non-GAAP financial measures of Adjusted EBITDA and Distributable Cash Flow to the GAAP financial measure of net income for each of the periods indicated (in thousands).
| Eagle Rock Energy Partners, L.P. | | | | |
| GAAP to Non-GAAP Reconciliations | | | | |
| ($ in thousands) | | | | |
| (unaudited) | | | | |
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| | | Three Months | | | Six Months | | | Three Months | |
| | | Ended June 30, | | | Ended June 30, | | | Ended | |
| Net income (loss) to adjusted EBITDA | | 2010 | | | 2009 | | | 2010 | | | 2009 | | | March 31, 2010 | |
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| Net income (loss), as reported | | $ | 68,143 | | | $ | (74,787 | ) | | $ | 72,124 | | | $ | (77,332 | ) | | $ | 3,981 | |
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| Depreciation, depletion and | | | | | | | | | | | | | | | | | | | | |
| amortization expense | | | 28,050 | | | | 26,136 | | | | 56,076 | | | | 54,524 | | | | 28,026 | |
| Impairment | | | 3,130 | | | | - | | | | 3,130 | | | | 242 | | | | - | |
| Risk management interest related | | | | | | | | | | | | | | | | | | | | |
| instruments-unrealized | | | 4,354 | | | | (11,954 | ) | | | 9,176 | | | | (15,053 | ) | | | 4,822 | |
| Risk management commodity related | | | | | | | | | | | | | | | | | | | | |
| instruments-unrealized, including amortization of | | | | | | | | | | | | | | | | | | | | |
| commodity derivative costs | | | (41,405 | ) | | | 97,044 | | | | (54,883 | ) | | | 101,566 | | | | (13,478 | ) |
| Other operating (income) expenses (non-recurring) | | | - | | | | (3,552 | ) | | | - | | | | (3,552 | ) | | | - | |
| Non-cash mark-to-market of Upstream product imbalances | | | (1,033 | ) | | | (203 | ) | | | (567 | ) | | | 1,829 | | | | 466 | |
| Restricted units non-cash amortization expense | | | 1,550 | | | | 1,889 | | | | 3,358 | | | | 4,120 | | | | 1,808 | |
| Income tax provision (benefit) | | | (415 | ) | | | (1,512 | ) | | | 296 | | | | (4,276 | ) | | | 711 | |
| Interest - net including realized risk | | | | | | | | | | | | | | | | | | | | |
| management instruments and other expense | | | 9,163 | | | | 10,701 | | | | 18,465 | | | | 21,958 | | | | 9,302 | |
| Other (income)/expense | | | 21 | | | | (199 | ) | | | (78 | ) | | | (283 | ) | | | (99 | ) |
| Discontinued operations | | | (39,473 | ) | | | (1,969 | ) | | | (43,317 | ) | | | (3,787 | ) | | | (3,844 | ) |
| Adjusted EBITDA | | $ | 32,085 | | | $ | 41,594 | | | $ | 63,780 | | | $ | 79,956 | | | $ | 31,695 | |
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| Net income (loss) to distributable cash flow | | | | | | | | | | | | | | | | | | | | |
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| Net income (loss), as reported | | $ | 68,143 | | | $ | (74,787 | ) | | $ | 72,124 | | | $ | (77,332 | ) | | $ | 3,981 | |
| | | | | | | | | | | | | | | | | | | | | |
| Depreciation, depletion and | | | | | | | | | | | | | | | | | | | | |
| amortization expense | | | 28,050 | | | | 26,136 | | | | 56,076 | | | | 54,524 | | | | 28,026 | |
| Impairment | | | 3,130 | | | | - | | | | 3,130 | | | | 242 | | | | - | |
| Risk management interest related | | | | | | | | | | | | | | | | | | | | |
| instruments-unrealized | | | 4,354 | | | | (11,954 | ) | | | 9,176 | | | | (15,053 | ) | | | 4,822 | |
| Risk management commodity related | | | | | | | | | | | | | | | | | | | | |
| instruments-unrealized, including amortization of | | | | | | | | | | | | | | | | | | | | |
| commodity derivative costs | | | (41,405 | ) | | | 97,044 | | | | (54,883 | ) | | | 101,566 | | | | (13,478 | ) |
| Capital expenditures-maintenance related | | | (6,883 | ) | | | (4,836 | ) | | | (12,067 | ) | | | (7,619 | ) | | | (5,184 | ) |
| Non-cash mark-to-market of Upstream product imbalances | | | (1,033 | ) | | | (203 | ) | | | (567 | ) | | | 1,829 | | | | 466 | |
| Restricted units non-cash amortization expense | | | 1,550 | | | | 1,889 | | | | 3,358 | | | | 4,120 | | | | 1,808 | |
| Other operating (income) expenses (non-recurring) | | | - | | | | (3,552 | ) | | | - | | | | (3,552 | ) | | | - | |
| Income tax provision (benefit) | | | (415 | ) | | | (1,512 | ) | | | 296 | | | | (4,276 | ) | | | 711 | |
| Other (income)/expense | | | 21 | | | | (199 | ) | | | (78 | ) | | | (283 | ) | | | (99 | ) |
| Cash income taxes | | | (565 | ) | | | (280 | ) | | | (981 | ) | | | (357 | ) | | | (416 | ) |
| Discontinued operations | | | (39,473 | ) | | | (1,969 | ) | | | (43,317 | ) | | | (3,787 | ) | | | (3,844 | ) |
| Distributable cash flow | | $ | 15,474 | | | $ | 25,777 | | | $ | 32,267 | | | $ | 50,022 | | | $ | 16,793 | |
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| Supplemental Information | | | | | |
| ($ in thousands) | | | | | |
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| | | Three Months | | | Six Months | | | Three Months | |
| | | Ended June 30, | | | Ended June 30, | | | Ended | |
| | | | 2010 | | | | 2009 | | | | 2010 | | | | 2009 | | | March 31, 2010 | |
| Amortization of commodity derivative costs | | | 430 | | | | 11,137 | | | | 3,078 | | | | 23,296 | | | | 2,648 | |
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