Eagle Rock Reports Third Quarter 2012 Financial Results HOUSTON, Oct. 31, 2012 (GLOBE NEWSWIRE) -- Eagle Rock Energy Partners, L.P. (together with its subsidiaries, "Eagle Rock" or the "Partnership") (Nasdaq:EROC) today announced its unaudited financial results for the three months ended September 30, 2012. Key financial results with respect to third quarter 2012 included the following: *Reported Adjusted EBITDA of $59.1 million, up from the $57.7 million reported for the second quarter of 2012, despite lower quarter-over-quarter crude oil and natural gas liquids (NGL) prices. *Reported Distributable Cash Flow of $27.0 million, a decrease as compared to the $31.6 million reported for the second quarter of 2012, primarily resulting from higher maintenance capital expenditures and higher interest expense during the quarter. *Announced a quarterly distribution with respect to the third quarter of 2012 of $0.22 per common unit, equivalent to $0.88 per unit on an annualized basis.This distribution is equal to the distribution paid for the second quarter 2012 and represents a 10% increase over that paid for the third quarter of 2011. *Reported a Net Loss of $106.9 million compared to Net Income of $61.8 million reported for the second quarter of 2012; the decrease was driven almost entirely by unrealized mark-to-market losses on commodity hedges and impairments, both of which are non-cash charges to earnings. Other notable financial and operational activities of the Partnership since June 30, 2012, included the following: *Closed the acquisition of BP America Production Company's ("BP") midstream assets in the Texas Panhandle (the "BP Acquisition") on October 1, 2012, for total consideration of $230.6 million in cash. In conjunction with the acquisition, Eagle Rock entered into a 20-year, fixed-fee gas gathering and processing agreement with BP covering a dedicated acreage area. *Announced an amendment to Eagle Rock's existing gas gathering and processing agreement with Anadarko E&P Company LP to, among other things, (i) expand the original dedication area by adding a 10-year dedication for any new wells drilled in an additional area of approximately 800,000 acres in western Louisiana and (ii) provide for a fixed-fee gathering arrangement for all new wells spud on or after April 1, 2012 in either the original or additional dedication areas. *Announced the Upstream component of the borrowing base under the Partnership's senior secured credit facility was increased by 17% to $400 million by its commercial lenders as part of its regularly scheduled semi-annual redetermination. *Completed a public offering of 10,120,000 common units for total net proceeds of approximately $84.5 million on August 17, 2012. The Partnership used the proceeds to repay a portion of the outstanding borrowings under its revolving credit facility in advance of funding the BP Acquisition on October 1, 2012. *Completed a private offering of $250 million of 8.375% senior unsecured notes on July 13, 2012, due 2019.The Partnership used the proceeds to repay outstanding borrowings under its revolving credit facility. "We posted a solid quarter despite a continuing challenging commodity price environment," said Joseph A. Mills, Eagle Rock's Chairman and Chief Executive Officer. "We have further positioned Eagle Rock for future growth and greater cash flow stability with the BP Acquisition and the expansion of our relationship with Anadarko in western Louisiana, both of which are meaningfully based on fixed-fee contract structures. In addition, we continue to focus our Upstream capital activity in the Golden Trend and the Southeast Cana Woodford plays and to further evaluate the full resource potential of our acreage position in the South Central Oklahoma Oil Province ("SCOOP") area." Update Regarding BP Acquisition and Integration On October 1, 2012, the Partnership completed the acquisition of BP's Sunray and Hemphill processing plants and associated 2,500 mile gathering system serving the liquids-rich Texas Panhandle (the "BP Panhandle System") for $230.6 million, as adjusted under the Purchase and Sale Agreement. As of September 30, 2012, $22.8 million was held as a deposit on the acquisition. The remaining purchase price was funded on October 1, 2012, through borrowings on the Partnership's revolving credit facility. In addition, Eagle Rock and BP entered into a 20-year, fixed-fee gas gathering and processing agreement.Under the agreement, Eagle Rock is gathering and processing BP's natural gas production from existing connected wells, and BP has committed itself and its farmees to Eagle Rock for the term of the agreement, under substantially the same gas gathering and processing terms, for all future natural gas production from new wells drilled within an initial two-year period from closing, subject to mutually-agreed extensions, and within a two-mile radius of the BP Panhandle System. The BP Panhandle System gathering volumes in the first half of 2012 averaged approximately 180 MMcf/d, and the Partnership expects to continue to grow its overall gathering volumes from the Texas Panhandle area based on expected drilling programs of BP and third party producers active in the area. Eagle Rock is currently in the process of integrating the BP Panhandle System with its existing system in the area, which will result in approximately 6,463 miles of combined gathering pipelines serving over 5,000 wells and over 480 MMcf/d of combined processing capacity in the Texas Panhandle; an additional 60 MMcf/d of capacity is expected to come on-line in the first half of 2013 following the completion of Eagle Rock's Wheeler Plant. The combined system will strengthen Eagle Rock's position in the growing Granite Wash, Cleveland, Tonkawa and Hogshooter plays and provide increased flexibility and capacity in serving its producer customers. As anticipated at the time of the announcement of the acquisition, Eagle Rock expects the integration of the two systems, including the planned interconnects, to be completed in the second quarter of 2013 and to result in future cost savings and an enhanced ability to optimize the total gathering and processing capacity. Activity in the Texas Panhandle remains robust with approximately 10 active rigs in the area dedicated to the combined Eagle Rock and BP Panhandle systems and over 400 wells permitted over the past six months in the Texas Panhandle region. Update Regarding Construction of the Wheeler Processing Plant In 2011, the Partnership announced plans for an additional high-efficiency cryogenic processing plant to be installed in the Texas Panhandle – the Wheeler Plant. Construction of the 60 MMcf/d Wheeler Plant, located in Wheeler County, and associated gathering and compression infrastructure is expected to be completed in the first half of 2013 at a cost of approximately $67 million, of which $32.4 million was spent through September 30, 2012. The addition of the Wheeler Plant to the Partnership's existing processing infrastructure in the Texas Panhandle Segment is in response to incremental processing demand driven by continued drilling activity in the Granite Wash, Cleveland and Tonkawa plays. Amendment to Existing Gathering and Processing Agreement with Anadarko E&P Company LP On October 3rd, the Partnership announced that it had entered into an Amendment (the "Amendment") to its existing Gas Gathering and Processing Agreement (the "Agreement") with Anadarko E&P Company LP ("Anadarko") to support Anadarko's drilling program in western Louisiana.The Amendment, among other things, (i) expands the original dedication area of approximately 1.1 million acres (which remains life-of-lease dedicated) by adding a 10-year dedication for any new wells drilled in an additional area of approximately 800,000 acres in western Louisiana, (ii) provides for a fixed gathering fee arrangement (rather than a commodity-price sensitive processing fee) for all wells spud on or after April 1, 2012 in either the original or additional dedication areas, and (iii) revises the mechanism that provides for Eagle Rock's recovery of capital expenditures for connecting its pipelines to Anadarko-operated wells spud on or after April 1, 2012. Update Regarding the Partnership's Position in the South Central Oklahoma Oil Province ("SCOOP") Eagle Rock's Golden Trend field and Southeast Cana leasehold are located in the heart of the South Central Oklahoma Oil Province ("SCOOP") in Grady, McClain and Garvin Counties, Oklahoma recently highlighted by Continental Resources Inc. and other producers. The Partnership owns approximately 14,000 net acres in the "SCOOP" area that produce from multiple formations including horizontal completions in the Woodford shale. During most of 2012, the Partnership has operated three drilling rigs and participated in third party operated wells in the Golden Trend and Southeast Cana, drilling both vertical tests through multiple formations and horizontal Woodford wells.Eagle Rock'sinitial operated Southeast Cana horizontal Woodford well, the Beckham 1-27H, is producing to sales and averaged 4.3 MMcfd and 197 Bopd in its first thirty days of production.A second operated well and two non-operated wells are currently drilling, and a third non-operated well is waiting on completion. "We are excited about both our and the industry's production results from the Woodford horizontal drilling in Southeast Cana," said Joseph A. Mills, Eagle Rock's Chairman and Chief Executive Officer."Our Golden Trend field and primary term leasehold in Southeast Cana are extremely well-positioned in the de-risked portion of this extended Woodford horizontal drilling play." Third Quarter 2012 Financial and Operating Results During the fourth quarter of 2011, the East Texas/Louisiana, South Texas and Gulf of Mexico segments were collapsed into a single reporting segment and a new Marketing and Trading reporting segment was created.The Midstream Business's financial results are now reported in the following segments: (i) Texas Panhandle, which no longer includes the results of the Partnership's Marketing and Trading operations, (ii) East Texas and Other Midstream, which consolidates Eagle Rock's former East Texas/Louisiana, South Texas and Gulf of Mexico segments, and (iii) Marketing and Trading, which is a new reporting segment. Operating results for the reportable segments have been recast for 2011 to reflect these changes.The Partnership's Upstream segment and functional (Corporate) segments were not affected. The following discussion of Eagle Rock's operating income by business segment compares the Partnership's financial results in the third quarter of 2012 to those of the second quarter of 2012. The Partnership believes comparing these periods is more illustrative of current operating trends than comparing the current quarter to results achieved in the third quarter of 2011. Please refer to the financial tables at the end of this release for further detailed information. Midstream Business – Operating income from continuing operations, excluding the impact of impairments, for the Midstream Business in the third quarter of 2012 decreased by approximately $3.8 million compared to the second quarter of 2012.This decrease was due to lower average NGL and condensate realized prices and a 13% decrease in combined equity NGL and condensate volumes. Midstream gathered volumes rose compared to the second quarter as a result of increased volumes in the Partnership's Texas Panhandle segment, which were attributable to a full quarter of service from the Woodall and Phoenix-Arrington Ranch Plants and higher gathering volumes resulting from increased drilling in the area as compared to the second quarter. These gains were offset by lower gathering volumes in the Partnership's East Texas and Other segment, primarily associated with loss of production in the Gulf of Mexico due to Hurricane Isaac, which formed on August 21, 2012, and continued production declines in South Texas. In the Texas Panhandle, gathered volumes were up approximately 37%, with combined equity NGL and condensate volumes down approximately 15%, compared to the second quarter of 2012.The decline in combined equity NGL and condensate volumes was partially attributable to reduced efficiencies at the Partnership's Phoenix-Arrington Ranch Plant, which was placed back into service on July 2, 2012 after an incident in April 2012 caused the plant to be shut down. Due to re-start issues, however, the Phoenix-Arrington Ranch Plant continues to operate at reduced NGL recovery rates. Equity volumes were also negatively impacted by constrained processing capacity at the 60 MMcf/d Woodall Plant, located in Hemphill County, Texas, which was placed into service on May 30, 2012. Throughput at the plant peaked at over 45 MMcf/d in early June before Woodall Plant throughput was constrained as a result of a third-party incident on June 5, 2012 involving the residue gas pipeline downstream ofEagle Rock'splant tailgate. The Partnership mitigated this reduced flow by utilizing capacity on a back-up residue outlet but constraints remained on the ability to flow at full capacity. In September, the Partnership connected into a new residue outlet, which has fully alleviated the processing restrictions, and the Woodall Plant is currently running at full capacity. Eagle Rock estimates that its results were negatively impacted by this downstream incident by approximately $2.5 million during the quarter. The Partnership's Texas Panhandle segment is currently gathering approximately 420 MMcf/d, which consists of 225 MMcf/d attributable to legacy Eagle Rock processing facilities and approximately 195 MMcf/d attributable to the recently acquired BP Texas Panhandle assets. In the East Texas and Other Midstream segment, gathered volumes were down approximately 7%, with combined equity NGL and condensate volumes also down approximately 7%, compared to the second quarter of 2012. The decrease in gathered volumes and combined equity NGL and condensate volumes was due to natural declines in the production of existing wells, loss of production in the Gulf of Mexico due to Hurricane Isaac, and reduced drilling activity in South Texas.Partially offsetting the declines, gathering volumes around the Partnership's systems servicing the liquids-rich Austin Chalk play in East Texas increased approximately 3% as compared to the second quarter of 2012. The Partnership's Yscloskey Plant in Louisiana, in which Eagle Rock has a non-operated ownership interest, suffered significant damage from Hurricane Isaac in August 2012. The Yscloskey Plant has been shut down since that time. The Partnership estimates that its results were negatively impacted by approximately $250,000 during the quarter as a consequence of the Yscloskey Plant downtime. The Marketing and Trading segment includes the financial results of the Partnership's crude oil and condensate marketing, and natural gas marketing and trading operations. Eagle Rock's crude oil and condensate marketing effort was established in 2010 to develop and implement marketing uplift strategies for crude and condensate in Alabama and in the Texas Panhandle. Eagle Rock's natural gas marketing and trading operations were established in 2011 to capitalize on physical and financial natural gas marketing and trading opportunities that extend from the Partnership's upstream and midstream assets. Operating income for the Marketing and Trading segment in the third quarter of 2012, including intercompany sales and intersegment cost of sales, increased by approximately $337,000, or 52%, compared to the second quarter of 2012, primarily due to higher natural gas prices during the quarter and increased throughput. In addition, timing of the Partnership's condensate sales in Alabama were negatively impacted by Hurricane Isaac, which made landfall on the coasts of Louisiana and Alabama in August 2012. Due to the storm, all maritime commerce in the region, including barge operations into and out of oil storage and processing facilities such asthe Partnership'sleased storage at a third-party terminal in Mobile, Alabama, was halted. The storm and subsequent clean-up and repair operations caused Eagle Rock's inventory levels to increase by about 50,000 barrels, which negatively impacted the Partnership's results by approximately $2.8 million during the quarter (recorded in the Corporate Segment as an intercompany elimination). Barge operations resumed during the second week of October, and the Partnership has since sold its excess inventory.Eagle Rock expects its condensate inventory levels to return to normal levels in the fourth quarter. Upstream Business - Operating income for Eagle Rock's Upstream Business in the third quarter of 2012, excluding the impact of impairments, increased by approximately$5.0 million, or 51%, compared to the second quarter of 2012.The increase was attributable to increased production and lower unit operating costs during the quarter, which were partially offset by lower realized crude oil, NGL and sulfur prices. Production volumes in the Upstream Business averaged 85.3 MMcfe/d during the quarter, an increase of approximately 3% compared to the second quarter of 2012. The production increase was driven primarily by the Partnership's drilling program in the Mid-Continent and by improved run-times at its Big Escambia Creek facility. Total capital expenditures for the Upstream Segment in the third quarter were approximately $43.8 million, down by approximately $1.8 million as compared to the second quarter of 2012. Through the third quarter of 2012, the Partnership has spent approximately $8.6 million in capital expenditures related to previously-disclosed upgrades to its Alabama operations in order to fulfill permit obligations and comply with new environmental standards. The Partnership expects to spend a total of approximately $60 million on these upgrades through 2014, inclusive of the $8.6 million spent through the third quarter of 2012. Corporate Segment – Operating loss for the Corporate segment, excluding the impact of unrealized derivative gains and losses, was $4.3 million for the third quarter of 2012 as compared to a loss of $2.6 million for the second quarter of 2012. The decrease was attributable to lower realized commodity derivative gains and intercompany eliminations for the third quarter, which was partially offset by lower General and Administrative expenses for the quarter compared to the second quarter of 2012. Total revenue for the third quarter of 2012, excluding the impact of Eagle Rock's realized and unrealized commodity derivative gains and losses, was $198.9 million, up 7% compared with the $186.4 million reported for the second quarter of 2012.The increase in revenue was primarily due to increased sales of natural gas, NGLs, crude oil, condensate and sulfur as compared to the second quarter of 2012.Eagle Rock recorded an unrealized loss on commodity derivatives of $51.3 million in the third quarter 2012, as compared to an unrealized gain on commodity derivatives of $79.5 million in the second quarter 2012.Unrealized gain (loss) on commodity derivatives is a non-cash, mark-to-market amount. Revenues less cost of goods sold associated with the sale of crude oil, natural gas, NGLs, condensate and sulfur decreased by approximately $1.0 million relative to the second quarter of 2012, driven primarily by lower average realized NGL and crude prices. Adjusted EBITDA for the third quarter of 2012 was $59.1 million, up 3% from the second quarter of 2012, and Distributable Cash Flow was $27.0 million for the third quarter of 2012, down 14% as compared to the second quarter of 2012. The decrease was attributable to higher interest expense following the senior notes issuance in July 2012 and to higher maintenance capital spending. The Partnership recorded $2.8 million of maintenance capital in the third quarter of 2012 related to the Alabama facility upgrades discussed above, relative to $1.5 million of such spending in the second quarter of 2012. The Partnership recorded a net loss of approximately $106.9 million for the third quarter of 2012, versus net income of $61.8 million for the second quarter of 2012. The net loss was driven primarily by unrealized, non-cash mark-to-market losses totaling $51.3 million on the Partnership's commodity derivative portfolio and by an impairment charge of $55.9 million taken during the quarter. The Partnership incurred impairment charges in its Upstream Business related to its proved properties in the Barnett Shale that experienced reduced revenues resulting from lower natural gas prices and continuing relatively high operating costs associated with gas compression. The Partnership also incurred impairment charges in its Midstream Business primarily related to the substantial damage incurred at the Yscloskey processing plant as a result of Hurricane Isaac in August 2012. Third Quarter Distribution On October 24, 2012, the Partnership declared a cash distribution of $0.22 per common and restricted unit for the quarter ended September 30, 2012, equivalent to $0.88 per unit on an annualized basis.This distribution is equal to the distribution paid for the second quarter 2012 and represents a 10% increase over the distribution paid for the third quarter of 2011.The distribution will be paid on Wednesday, November 14, 2012 to unitholders of record as of the close of business on Wednesday, November 7, 2012. Capitalization and Liquidity Update Total debt outstanding as of September 30, 2012 was $875.4 million, consisting of $544.4 million of senior unsecured notes (net of an unamortized debt discount of $5.6 million) and borrowings of $331.0 million under the Partnership's senior secured credit facility. Borrowings during the third quarter of 2012 were primarily attributable to capital spending related to the Partnership's Wheeler Plant and Big Escambia Creek facility, new drilling activity in the Mid-Continent, and the $22.8 million deposit made for the BP Acquisition. On July 13, 2012, the Partnership completed the sale of an additional $250.0 million of 8.375% senior unsecured notes through a private placement exempt from the registration requirements of the Securities Act of 1933. After the original discount of $3.7 million and excluding related offering expenses, the Partnership received net proceeds of approximately $246.3 million, which were used to repay borrowings outstanding under its revolving credit facility.The issuance supplemented the Partnership's prior $300 million of senior notes issued in May 2011, all of which are treated as a single series. On August 17, 2012, the Partnership completed a public offering of 10,120,000 common units for total net proceeds of approximately $84.5 million. The Partnership used the proceeds to repay outstanding borrowings under its revolving credit facility in advance of funding the BP Acquisition on October 1, 2012. In addition, Eagle Rock issued 691,020 common units in the third quarter of 2012 under its equity shelf program for total net proceeds of approximately $6.1 million. Availability under the credit facility is subject to a borrowing base comprised of two components: the upstream component and the midstream component.As of September 30, 2012, the Partnership had approximately $328.5 million of availability under its credit facility, based on its outstanding commitments, after taking into account $331 million of outstanding borrowings and approximately $15.6 million of outstanding letters of credit. On October 1, 2012, Eagle Rock borrowed approximately $207.9 million under its credit facility in connection with closing the BP Acquisition. On October 9, 2012, the Partnership announced that the Upstream Segment component of the borrowing base under its revolving credit facility was increased to $400 million by its commercial lenders as part of its regularly scheduled semi-annual borrowing base redetermination. This represents an increase of $58 million from the previous level of $342 million. The redetermined borrowing base was effective October 1, 2012, with no additional fees or increase in interest rate spread incurred. The total borrowing capacity under the Partnership's credit facility is limited to the lower of the borrowing base and the total lender commitments, which remain unchanged at $675 million. As of September 30, 2012, the Partnership had 147.4 million units outstanding, including unvested restricted common units outstanding under its Long-Term Incentive Plan. Hedging Update The Partnership has entered into the following commodity hedges since its last hedging update on August 1, 2012: Transaction Date Product / (Type) Quantity Price ($/MMBtu) Term 10/1/12 HH Natural Gas 150,000 $4.36 Cal. 2015 (Swap) MMbtu/month 9/25/12 WTI Crude 30,000 $90.65 Cal. 2014 (Swap) Bbls/month 9/25/12 WTI Crude 15,000 $93.50 Cal. 2013 (Swap) Bbls/month 9/24/12 HH Natural Gas 400,000 $4.02 Cal. 2014 (Swap) MMbtu/month 9/24/12 HH Natural Gas 300,000 $3.62 Cal. 2013 (Swap) MMbtu/month Details of the recent hedging transactions are included in the updated Commodity Hedging Overview presentation Eagle Rock posted on October 31, 2012 to its website. The latest presentation can be accessed by going to www.eaglerockenergy.com: select Investor Relations, then select Presentations. In July 2012, in conjunction with the Partnership's issuance of $250.0 million of senior unsecured notes, which increased its fixed interest rate exposure, the Partnership terminated the full $200.0 million notional amount of its existing 4.295% and 4.095% fixed rate interest rate swaps at a cost of $3.9 million. Third Quarter Earnings Conference Call Information The third quarter 2012 earnings conference call will be held at 2:00 p.m. Eastern Time (1:00 p.m. Central Time) on Thursday, November 1, 2012. Interested parties may listen to the earnings conference call live over the Internet or via telephone. To listen live over the Internet, participants are advised to log on to the Partnership's web site at www.eaglerockenergy.com and select the "Events & Presentations" sub-tab under the "Investor Relations" tab.To participate by telephone, the call in number is 877-293-5457, conference ID 43758738.Participants are advised to dial into the call at least 15 minutes prior to the call. An audio replay of the conference call will also be available for thirty days by dialing 855-859-2056, conference ID 43758738.In addition, a replay of the audio webcast will be available by accessing the Partnership's web site 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 (NGLs); (iii) crude oil logistics and marketing; and (iv) natural gas marketing and trading; and b) upstream, which includes exploiting, developing, and producing hydrocarbons in oil and natural gas properties. 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 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 the Partnership's 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'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 finance its maintenance capital expenditures. Eagle Rock further believes that Adjusted EBITDA also portrays 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 portray 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 capital expenditures made to replace partially or fully depreciated assets; to meet regulatory requirements; to maintain the existing operating capacity of the Partnership's gathering, processing and treating assets or to maintain the Partnership's natural gas, NGL, crude or sulfur production. 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. These include, but are not limited to, risks related to volatility of commodity prices; market demand for crude oil, natural gas and natural gas liquids; the effectiveness of the Partnership's hedging activities; the Partnership's ability to retain key customers; the Partnership's ability to continue to obtain new sources of crude oil and natural gas supply; the availability of local, intrastate and interstate transportation systems and other facilities to transport crude oil, natural gas and natural gas liquids; competition in the oil and gas industry; the Partnership's ability to obtain credit and access the capital markets; general economic conditions; and the effects of government regulations and policies. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, the Partnership's actual results and plans could differ materially from those implied or expressed by any 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 ("SEC") for the year ended December 31, 2011 and the Partnership's Forms 10-Q filed with the SEC for subsequent quarters, as well as any other public filings and press releases. Eagle Rock Energy Partners, L.P. Consolidated Statement of Operations ($ in thousands) (unaudited) Three Three Months Ended Nine Months Ended Months Ended September 30, September 30, June 30, 2012 2011 2012 2011 2012 REVENUE: Natural gas, natural gas liquids, oil, $184,494 $264,119 $580,152 $732,491 $172,945 condensate and sulfur sales Gathering, compression, 13,604 11,567 35,566 37,116 10,451 processing and treating fees Unrealized commodity derivative (losses) (51,305) 97,011 13,426 86,164 79,502 gains Realized commodity derivative gains 15,802 (2,698) 38,428 (17,958) 16,463 (losses) Other revenue 794 141 3,976 1,406 3,043 Total revenue 163,389 370,140 671,548 839,219 282,404 COSTS AND EXPENSES: Cost of natural gas and natural gas 110,430 166,293 338,798 486,286 97,914 liquids Operations and 27,074 24,897 81,685 66,323 27,562 maintenance Taxes other than 4,748 4,556 14,518 13,061 4,620 income General and 16,807 16,068 52,384 43,746 18,736 administrative Other operating -- -- -- (2,893) -- income Impairment 55,900 9,870 122,824 14,754 21,402 Depreciation, depletion and 40,395 35,040 118,043 90,314 38,354 amortization Total costs and 255,354 256,724 728,252 711,591 208,588 expenses OPERATING(LOSS) (91,965) 113,416 (56,704) 127,628 73,816 INCOME OTHER INCOME (EXPENSE): Interest expense, (14,199) (10,050) (35,087) (19,579) (10,647) net Realized interest rate derivative (1,733) (3,713) (8,578) (13,374) (3,470) losses Unrealized interest rate derivative 615 (3,165) 4,418 2,191 2,007 (losses) gains Other (expense) 1 (3) (44) (167) 4 income, net Total other income (15,316) (16,931) (39,291) (30,929) (12,106) (expense) (LOSS) INCOME FROM CONTINUING (107,281) 96,485 (95,995) 96,699 61,710 OPERATIONS BEFORE INCOME TAXES INCOME TAX BENEFIT (386) (1,077) (556) (1,810) (79) (LOSS) INCOME FROM CONTINUING (106,895) 97,562 (95,439) 98,509 61,789 OPERATIONS DISCONTINUED OPERATIONS, NET OF -- (197) -- 210 -- TAX NET (LOSS) INCOME $(106,895) $97,365 $(95,439) $98,719 $61,789 Eagle Rock Energy Partners, L.P. Consolidated Balance Sheets ($ in thousands) (unaudited) September 30, 2012 December 31, 2011 ASSETS CURRENT ASSETS: Cash and cash equivalents $194 $877 Accounts receivable 96,637 97,832 Risk management assets 33,963 13,080 Prepayments and other current assets 13,547 13,739 Total current assets 144,341 125,528 PROPERTY, PLANT AND EQUIPMENT- Net 1,792,414 1,763,674 INTANGIBLE ASSETS- Net 85,917 109,702 DEFERRED TAX ASSET 1,449 1,432 RISK MANAGEMENT ASSETS 14,354 24,290 OTHER ASSETS 44,414 21,062 TOTAL $2,082,889 $2,045,688 LIABILITIES AND MEMBERS' EQUITY CURRENT LIABILITIES: Accounts payable $135,960 $145,985 Accrued liabilities 29,753 12,734 Taxes payable 372 487 Risk management liabilities 1,396 11,649 Total current liabilities 167,481 170,855 LONG-TERM DEBT 875,446 779,453 ASSET RETIREMENT OBLIGATIONS 35,145 33,303 DEFERRED TAX LIABILITY 43,898 45,216 RISK MANAGEMENT LIABILITIES 3,012 6,893 OTHER LONG TERM LIABILITIES 2,522 2,621 COMMITMENTS AND CONTINGENCIES MEMBERS' EQUITY: Members' equity 955,385 1,007,347 TOTAL $2,082,889 $2,045,688 Eagle Rock Energy Partners, L.P. Segment Summary Operating Income ($ in thousands) (unaudited) Three Months Ended Nine Months Ended Three Months Ended September 30, September 30, June 30, 2012 2011 2012 2011 2012 Midstream Revenues: Natural gas, natural gas $147,099 $213,593 $468,355 $624,939 $140,324 liquids, oil and condensate sales Intercompany sales - natural (2,846) (1,403) (7,809) (1,403) (2,113) gas Gathering and treating 13,604 11,567 35,566 37,116 10,451 services Other -- -- 2,864 -- 2,864 Total revenue 157,857 223,757 498,976 660,652 151,526 Cost of natural gas, natural gas 110,430 166,293 338,798 486,286 97,914 liquids, oil and condensate Intersegment elimination - 8,598 8,825 32,612 29,817 10,383 cost of condensate Operating costs and expenses: Operations and 17,647 16,716 53,178 48,081 18,164 maintenance Impairment 35,840 -- 101,979 4,560 20,617 Depreciation, depletion and 16,488 16,093 49,735 48,250 16,565 amortization Total operating costs and 69,975 32,809 204,892 100,891 55,346 expenses Operating (loss)income (31,146) 15,830 (77,326) 43,658 (12,117) from continuing operations Discontinued -- (197) -- (194) -- Operations (1) Operating (loss) $(31,146) $15,633 $(77,326) $43,464 $(12,117) income Upstream (2) Revenues: Oil and $14,376 $17,269 $44,088 $33,799 $12,247 condensate sales Intersegment sales - 11,431 7,451 34,226 29,975 10,306 condensate Natural gas 8,324 16,014 22,474 31,294 6,832 sales (3) Intersegment sales - natural 2,846 1,403 7,809 1,403 2,113 gas Natural gas liquids sales 10,979 12,186 34,060 29,678 10,340 (4) Sulfur Sales (5) 3,716 5,057 11,175 12,781 3,202 Other 794 141 1,112 1,406 179 Total revenue 52,466 59,521 154,944 140,336 45,219 Operating costs and expenses: Operations and 14,175 12,737 43,025 31,369 14,018 maintenance (1) Intersegment operations and -- -- -- -- -- maintenance Impairment 20,060 9,870 20,845 10,194 785 Depreciation, depletion and 23,484 18,636 67,070 41,046 21,366 amortization Total operating costs and 57,719 41,243 130,940 82,609 36,169 expenses Operating (loss) $(5,253) $18,278 $24,004 $57,727 $9,050 income Corporate and Other Revenues: Unrealized commodity $(51,305) $97,011 $13,426 $86,164 $79,502 derivative (losses) gains Realized commodity 15,802 (2,698) 38,428 (17,958) 16,463 derivative gains(losses) Intersegment elimination - (11,431) (7,451) (34,226) (29,975) (10,306) sales of condensate Total revenue (46,934) 86,862 17,628 38,231 85,659 Costs and expenses: Intersegment elimination - (8,598) (8,825) (32,612) (29,817) (10,383) cost of condensate General and 16,807 16,068 52,384 43,746 18,736 administrative Intersegment elimination - -- -- -- (66) -- operations and maintenance Other operating -- -- -- (2,893) -- Income Depreciation, depletion and 423 311 1,238 1,018 423 amortization Operating (loss) $(55,566) $79,308 $(3,382) $26,243 $76,883 income (1) Includes natural gas sales of $66 from the East Texas and Other Midstream Texas Segment to the Upstream Segment for the nine months ended September 30, 2011, respectively. (2)Includes operations related to the Crow Creek Acquisition starting on May 3, 2011. (3) Revenues include a change in the value of product imbalances of $18, $(37), $(38) and $22 for the three and nine months ended September30, 2012 and 2011, respectively, and $(49) for the three months ended June30, 2012. (4) Revenues include a change in the value of product imbalances of $(215) , $(301), $270 and $155 for the three and nine months ended September30, 2012 and 2011, respectively, and $(257) for the three months ended June30, 2012. (5) Revenues include a change in the value of product imbalances of $(32) , $0, $(125) and $(54) for the three and nine months ended September30, 2012 and 2011, respectively, and $(2) for the three months ended June30, 2012. Eagle Rock Energy Partners, L.P. Midstream Segment Operating Income ($ in thousands) (unaudited) Three Months Ended Nine Months Ended Three Months Ended September 30, September 30, June 30, 2012 2011 2012 2011 2012 Texas Panhandle Revenues: Natural gas, natural gas $60,213 $90,420 $189,230 $304,813 $55,937 liquids, oil and condensate sales Intersegment sales - natural gas and 28,025 26,247 72,514 26,247 19,043 condensate Gathering, compression, 4,708 4,892 13,510 12,905 3,852 processing and treating services Other -- -- 2,864 -- 2,864 Total revenue 92,946 121,559 278,118 343,965 81,696 Cost of natural gas, natural gas 67,098 87,797 189,703 247,512 51,117 liquids, oil and condensate Operating costs and expenses: Operations and 12,705 10,826 37,342 31,434 12,399 maintenance Impairment -- -- -- 4,560 -- Depreciation, depletion and 10,164 9,145 29,554 27,382 9,873 amortization Total operating 22,869 19,971 66,896 63,376 22,272 costs and expenses Operating income $2,979 $13,791 $21,519 $33,077 $8,307 East Texas and Other Midstream Revenues: Natural gas, natural gas $26,130 $59,590 $98,398 $193,785 $30,998 liquids, oil and condensate sales Intercompany Sales 10,020 4,330 26,471 4,330 6,928 - natural gas Gathering, compression, 8,896 6,675 22,056 24,211 6,599 processing and treating services Total revenue 45,046 70,595 146,925 222,326 44,525 Cost of natural gas, natural gas 33,145 56,536 111,203 176,202 32,550 liquids and condensate Operating costs and expenses: Operations and 4,940 5,888 15,833 16,645 5,764 maintenance Impairment 35,840 -- 101,979 -- 20,617 Depreciation, depletion and 6,232 6,948 20,034 20,868 6,667 amortization Total operating 47,012 12,836 137,846 37,513 33,048 costs and expenses Operating income (loss) from (35,111) 1,223 (102,124) 8,611 (21,073) continuing operations Discontinued -- (197) -- (194) -- Operations Operating income $(35,111) $1,026 $(102,124) $8,417 $(21,073) (loss) Marketing and Trading Revenues: Natural gas, oil and condensate $60,756 $63,583 $180,727 $126,341 $53,389 sales Intercompany sales - natural gas and (40,891) (31,980) (106,794) (31,980) (28,084) condensate Total revenue 19,865 31,603 73,933 94,361 25,305 Cost of natural gas and natural gas 10,187 21,960 37,892 62,572 14,247 liquids Intersegment cost of sales - 8,598 8,825 32,612 29,817 10,383 condensate Operating costs and expenses: Operations and 2 2 3 2 1 maintenance Depreciation, depletion and 92 -- 147 -- 25 amortization Total operating 94 2 150 2 26 costs and expenses Operating income $986 $816 $3,279 $1,970 $649 Eagle Rock Energy Partners, L.P. Midstream Operations Information (unaudited) Three Three Months Ended Nine Months Ended Months Ended September 30, September 30, June 30, 2012 2011 2012 2011 2012 Gas gathering volumes - (Average Mcf/d) Texas Panhandle 183,415 163,665 159,229 154,011 133,590 East Texas and 248,094 312,103 268,512 331,003 265,472 Other Midstream Total 431,509 475,768 427,741 485,014 399,062 NGLs - (Net equity Bbls) Texas Panhandle (1) 228,696 231,965 855,499 609,097 297,688 East Texas and 81,997 114,280 258,322 345,255 84,981 Other Midstream Total 310,693 346,245 1,113,821 954,352 382,669 Condensate - (Net equity Bbls) Texas Panhandle (1) 164,246 260,228 499,660 728,860 163,320 East Texas and 7,010 10,519 28,737 35,426 10,403 Other Midstream Total 171,256 270,747 528,397 764,286 173,723 Natural gas short position - (Average MMbtu/d) Texas Panhandle (990) (7,418) (4,661) (5,517) (5,629) East Texas and 392 1,758 1,482 1,963 3,952 Other Midstream Total (598) (5,660) (3,179) (3,554) (1,677) Average realized NGL price - per Bbl Texas Panhandle $ 36.23 $ 53.39 $ 39.55 $ 55.28 $ 38.30 East Texas and $ 32.24 $ 52.57 $ 39.45 $ 51.13 $ 39.72 Other Midstream Weighted Average $ 34.89 $ 53.08 $ 39.51 $ 53.51 $ 38.85 Average realized condensate price - per Bbl Texas Panhandle $ 81.08 $ 79.43 $ 86.74 $ 82.31 $ 82.29 East Texas and $ 91.57 $ 93.82 $ 100.66 $ 94.28 $ 103.71 Other Midstream Total $ 81.82 $ 79.74 $ 87.94 $ 83.31 $ 83.90 Average realized natural gas price - per MMbtu Texas Panhandle $ 2.64 $ 3.86 $ 2.37 $ 3.95 $ 1.93 East Texas and $ 2.85 $ 4.36 $ 2.67 $ 4.42 $ 2.22 Other Midstream Total $ 2.71 $ 4.05 $ 2.48 $ 4.14 $ 2.04 (1) Effective January 2012, reported NGL volumes include those volumes recovered from our equity condensate through stabilization. These NGL volumes were previously reported as condensate. This change results in an increase to reported NGLs equity barrels and a corresponding decrease to reported condensate equity barrels. Eagle Rock Energy Partners, L.P. Upstream Operations Information (unaudited) Three Three Months Ended Nine Months Ended Months Ended September 30, September 30, June 30, 2012 2011 2012 2011 2012 Upstream Production: Oil and condensate 310,349 302,766 900,873 772,350 266,580 (Bbl) Gas (Mcf) 4,177,156 4,274,811 12,614,258 8,272,176 4,341,298 NGLs (Bbl) 301,644 227,614 848,047 533,223 267,673 Total Mcfe 7,849,113 7,457,091 23,107,779 16,105,615 7,546,811 Sulfur (long ton) 28,414 27,706 79,111 71,509 21,705 Realized prices, excluding derivatives: (1) Oil and condensate $83.16 $81.65 $86.93 $82.57 $84.60 (per Bbl) Gas (Mcf) $2.67 $4.08 $2.40 $3.95 $2.06 NGLs (Bbl) $36.40 $52.35 $40.16 $55.37 $38.63 Sulfur (long ton) $130.77 $187.03 $141.27 $179.48 $147.55 Operating statistics: Operating costs per Mcfe (incl $1.60 $1.57 $1.69 $1.88 $1.68 production taxes) (2) Operating costs per Mcfe (excl $1.11 $1.07 $1.18 $1.23 $1.18 production taxes) (2) Operating income per $(0.67) $2.45 $1.04 $3.58 $1.20 Mcfe Drilling program (gross wells): Development wells 6 13 25 32 9 Completions 6 13 25 32 9 Workovers 10 5 19 13 4 Recompletions 4 4 7 8 1 (1) Calculation does not include impact of product imbalances. (2) Excludes post-production costs of $1,601 and $4,068 for the three and nine months ended September30, 2012, respectively, $1,031 for both the three and nine months ended September30, 2011 and $1,319 June30, 2012. Eagle Rock Energy Partners, L.P. GAAP to Non-GAAP Reconciliations ($ in thousands) (unaudited) Three Three Months Ended Nine Months Ended Months Ended September 30, September 30, June 30, 2012 2011 2012 2011 2012 Net (loss) income to Adjusted EBITDA Net (loss) income, as $(106,895) $97,365 $(95,439) $98,719 $61,789 reported Depreciation, depletion 40,395 35,040 118,043 90,314 38,354 and amortization Impairment 55,900 9,870 122,824 14,754 21,402 Risk management interest related instruments - (615) 3,165 (4,418) (2,191) (2,007) unrealized Risk management commodity related 51,305 (97,011) (13,426) (86,164) (79,502) instruments - unrealized Other Operating Income -- -- -- (2,893) -- Non-cash mark-to-market of Upstream product 229 (107) 338 (123) 307 imbalances Unrealized losses (gains) from other 157 (538) 427 (538) 473 derivative activity Restricted units non-cash amortization 3,080 1,507 8,092 3,441 2,818 expense Income tax (benefit) (386) (1,077) (556) (1,810) (79) provision Interest - net including realized risk management 15,931 13,766 43,709 33,120 14,113 instruments and other expense Other income -- -- -- -- -- Discontinued operations -- 197 -- (210) -- Adjusted EBITDA $59,101 $62,177 $179,594 $146,419 $57,668 Net (loss) income to Distributable Cash Flow Net (loss) income, as $(106,895) $97,365 $(95,439) $98,719 $61,789 reported Depreciation, depletion 40,395 35,040 118,043 90,314 38,354 and amortization expense Impairment 55,900 9,870 122,824 14,754 21,402 Risk management interest related (615) 3,165 (4,418) (2,191) (2,007) instruments-unrealized Risk management commodity related instruments and other 51,462 (97,549) (12,999) (86,702) (79,029) derivative activity - unrealized Capital expenditures-maintenance (15,982) (11,980) (35,824) (30,311) (11,816) related Non-cash mark-to-market of Upstream product 229 (107) 338 (123) 307 imbalances Restricted units non-cash amortization 3,080 1,507 8,092 3,441 2,818 expense Other Operating Income -- -- -- (2,893) -- Income tax (benefit) (386) (1,077) (556) (1,810) (79) provision Cash income taxes (185) (325) (749) (802) (189) Discontinued operations -- 197 -- (210) -- Distributable Cash Flow $27,003 $36,106 $99,312 $82,186 $31,550 CONTACT: Eagle Rock Energy Partners, L.P. Jeff Wood, 281-408-1203 Senior Vice President and Chief Financial Officer Adam Altsuler, 281-408-1350 Director, Corporate Finance and Investor Relations company logo
Eagle Rock Reports Third Quarter 2012 Financial Results
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