Market Overview

Eagle Rock Reports Third Quarter 2012 Financial Results

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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's initial 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 of Eagle Rock's plant 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 as the Partnership's leased 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
(Swap)
150,000
MMbtu/month
$4.36
 
Cal. 2015
 
9/25/12
 
WTI Crude
(Swap)
30,000
Bbls/month
$90.65
 
Cal. 2014
 
9/25/12
 
WTI Crude
(Swap)
15,000
Bbls/month
$93.50
 
Cal. 2013
 
9/24/12
 
HH Natural Gas
(Swap)
400,000
MMbtu/month
$4.02
 
Cal. 2014
 
9/24/12
 
HH Natural Gas
(Swap)
300,000
MMbtu/month
$3.62
 
Cal. 2013
 

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 Months Ended Nine Months Ended Three Months Ended
  September 30, September 30, June 30,
  2012 2011 2012 2011 2012
REVENUE:          
Natural gas, natural gas liquids, oil, condensate and sulfur sales  $ 184,494  $ 264,119  $ 580,152  $ 732,491  $ 172,945
Gathering, compression, processing and treating fees  13,604  11,567  35,566  37,116  10,451
Unrealized commodity derivative (losses) gains  (51,305)  97,011  13,426  86,164  79,502
Realized commodity derivative gains (losses)  15,802  (2,698)  38,428  (17,958)  16,463
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 liquids  110,430  166,293  338,798  486,286  97,914
Operations and maintenance  27,074  24,897  81,685  66,323  27,562
Taxes other than income  4,748  4,556  14,518  13,061  4,620
General and administrative  16,807  16,068  52,384  43,746  18,736
Other operating income  --   --   --   (2,893)  -- 
Impairment  55,900  9,870  122,824  14,754  21,402
Depreciation, depletion and amortization  40,395  35,040  118,043  90,314  38,354
Total costs and expenses  255,354  256,724  728,252  711,591  208,588
OPERATING (LOSS) INCOME  (91,965)  113,416  (56,704)  127,628  73,816
OTHER INCOME (EXPENSE):          
Interest expense, net  (14,199)  (10,050)  (35,087)  (19,579)  (10,647)
Realized interest rate derivative losses  (1,733)  (3,713)  (8,578)  (13,374)  (3,470)
Unrealized interest rate derivative (losses) gains  615  (3,165)  4,418  2,191  2,007
Other (expense) income, net  1  (3)  (44)  (167)  4
Total other income (expense)  (15,316)  (16,931)  (39,291)  (30,929)  (12,106)
(LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES  (107,281)  96,485  (95,995)  96,699  61,710
INCOME TAX BENEFIT  (386)  (1,077)  (556)  (1,810)  (79)
(LOSS) INCOME FROM CONTINUING OPERATIONS  (106,895)  97,562  (95,439)  98,509  61,789
DISCONTINUED OPERATIONS, NET OF TAX  --   (197)  --   210  -- 
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 liquids, oil and condensate sales  $ 147,099  $ 213,593  $ 468,355  $ 624,939  $ 140,324
Intercompany sales - natural gas  (2,846)  (1,403)  (7,809)  (1,403)  (2,113)
Gathering and treating services  13,604  11,567  35,566  37,116  10,451
Other  --   --   2,864  --   2,864
Total revenue  157,857  223,757  498,976  660,652  151,526
Cost of natural gas, natural gas liquids, oil and condensate  110,430  166,293  338,798  486,286  97,914
Intersegment elimination - cost of condensate  8,598  8,825  32,612  29,817  10,383
Operating costs and expenses:          
Operations and maintenance  17,647  16,716  53,178  48,081  18,164
Impairment  35,840  --   101,979  4,560  20,617
Depreciation, depletion and amortization  16,488  16,093  49,735  48,250  16,565
Total operating costs and expenses  69,975  32,809  204,892  100,891  55,346
Operating (loss) income from continuing operations  (31,146)  15,830  (77,326)  43,658  (12,117)
Discontinued Operations (1)  --   (197)  --   (194)  -- 
Operating (loss) income  $ (31,146)  $ 15,633  $ (77,326)  $ 43,464  $ (12,117)
           
Upstream (2)          
Revenues:          
Oil and condensate sales  $ 14,376  $ 17,269  $ 44,088  $ 33,799  $ 12,247
Intersegment sales - condensate  11,431  7,451  34,226  29,975  10,306
Natural gas sales (3)  8,324  16,014  22,474  31,294  6,832
Intersegment sales - natural gas  2,846  1,403  7,809  1,403  2,113
Natural gas liquids sales (4)  10,979  12,186  34,060  29,678  10,340
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 maintenance (1)  14,175  12,737  43,025  31,369  14,018
Intersegment operations and maintenance  --   --   --   --   -- 
Impairment  20,060  9,870  20,845  10,194  785
Depreciation, depletion and amortization  23,484  18,636  67,070  41,046  21,366
Total operating costs and expenses  57,719  41,243  130,940  82,609  36,169
Operating (loss) income  $ (5,253)  $ 18,278  $ 24,004  $ 57,727  $ 9,050
           
Corporate and Other          
Revenues:          
Unrealized commodity derivative (losses) gains  $ (51,305)  $ 97,011  $ 13,426  $ 86,164  $ 79,502
Realized commodity derivative gains (losses)  15,802  (2,698)  38,428  (17,958)  16,463
Intersegment elimination - sales of condensate  (11,431)  (7,451)  (34,226)  (29,975)  (10,306)
Total revenue  (46,934)  86,862  17,628  38,231  85,659
Costs and expenses:          
Intersegment elimination - cost of condensate  (8,598)  (8,825)  (32,612)  (29,817)  (10,383)
General and administrative  16,807  16,068  52,384  43,746  18,736
Intersegment elimination - operations and maintenance  --   --   --   (66)  -- 
Other operating Income  --   --   --   (2,893)  -- 
Depreciation, depletion and amortization  423  311  1,238  1,018  423
Operating (loss) income  $ (55,566)  $ 79,308  $ (3,382)  $ 26,243  $ 76,883
           
(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 September 30, 2012 and 2011, respectively, and $(49) for the three months ended June 30, 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 September 30, 2012 and 2011, respectively, and $(257) for the three months ended June 30, 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 September 30, 2012 and 2011, respectively, and $(2) for the three months ended June 30, 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 liquids, oil and condensate sales  $ 60,213  $ 90,420  $ 189,230  $ 304,813  $ 55,937
Intersegment sales - natural gas and condensate  28,025  26,247  72,514  26,247  19,043
Gathering, compression, processing and treating services  4,708  4,892  13,510  12,905  3,852
Other  --   --   2,864  --   2,864
Total revenue  92,946  121,559  278,118  343,965  81,696
Cost of natural gas, natural gas liquids, oil and condensate  67,098  87,797  189,703  247,512  51,117
Operating costs and expenses:          
Operations and maintenance  12,705  10,826  37,342  31,434  12,399
Impairment  --   --   --   4,560  -- 
Depreciation, depletion and amortization  10,164  9,145  29,554  27,382  9,873
Total operating costs and expenses  22,869  19,971  66,896  63,376  22,272
Operating income  $ 2,979  $ 13,791  $ 21,519  $ 33,077  $ 8,307
           
East Texas and Other Midstream          
Revenues:          
Natural gas, natural gas liquids, oil and condensate sales  $ 26,130  $ 59,590  $ 98,398  $ 193,785  $ 30,998
Intercompany Sales - natural gas  10,020  4,330  26,471  4,330  6,928
Gathering, compression, processing and treating services  8,896  6,675  22,056  24,211  6,599
Total revenue  45,046  70,595  146,925  222,326  44,525
Cost of natural gas, natural gas liquids and condensate  33,145  56,536  111,203  176,202  32,550
Operating costs and expenses:                
Operations and maintenance  4,940  5,888  15,833  16,645  5,764
Impairment  35,840  --   101,979  --   20,617
Depreciation, depletion and amortization  6,232  6,948  20,034  20,868  6,667
Total operating costs and expenses  47,012  12,836  137,846  37,513  33,048
Operating income (loss) from continuing operations  (35,111)  1,223  (102,124)  8,611  (21,073)
Discontinued Operations  --   (197)  --   (194)  -- 
Operating income (loss)  $ (35,111)  $ 1,026  $ (102,124)  $ 8,417  $ (21,073)
           
Marketing and Trading          
Revenues:          
Natural gas, oil and condensate sales  $ 60,756  $ 63,583  $ 180,727  $ 126,341  $ 53,389
Intercompany sales - natural gas and condensate  (40,891)  (31,980)  (106,794)  (31,980)  (28,084)
Total revenue  19,865  31,603  73,933  94,361  25,305
Cost of natural gas and natural gas liquids  10,187  21,960  37,892  62,572  14,247
Intersegment cost of sales - condensate  8,598  8,825  32,612  29,817  10,383
Operating costs and expenses:            
Operations and maintenance  2  2  3  2  1
Depreciation, depletion and amortization  92  --   147  --   25
Total operating costs and expenses  94  2  150  2  26
Operating income  $ 986  $ 816  $ 3,279  $ 1,970  $ 649
 
 
 
Eagle Rock Energy Partners, L.P.
Midstream Operations Information
(unaudited)
           
  Three Months Ended Nine Months Ended  Three 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 Other Midstream  248,094  312,103  268,512  331,003  265,472
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 Other Midstream  81,997  114,280  258,322  345,255  84,981
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 Other Midstream  7,010  10,519  28,737  35,426  10,403
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 Other Midstream  392  1,758  1,482  1,963  3,952
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 Other Midstream $ 32.24 $ 52.57 $ 39.45 $ 51.13 $ 39.72
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 Other Midstream $ 91.57 $ 93.82 $ 100.66 $ 94.28 $ 103.71
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 Other Midstream $ 2.85 $ 4.36 $ 2.67 $ 4.42 $ 2.22
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 Months Ended Nine Months Ended  Three Months Ended 
  September 30, September 30, June 30,
  2012 2011 2012 2011 2012
Upstream          
Production:          
Oil and condensate (Bbl) 310,349 302,766 900,873 772,350 266,580
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 (per Bbl)  $ 83.16  $ 81.65  $ 86.93  $ 82.57  $ 84.60
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 production taxes) (2)  $ 1.60  $ 1.57  $ 1.69  $ 1.88  $ 1.68
Operating costs per Mcfe (excl production taxes) (2)  $ 1.11  $ 1.07  $ 1.18  $ 1.23  $ 1.18
Operating income per Mcfe  $ (0.67)  $ 2.45  $ 1.04  $ 3.58  $ 1.20
           
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 September 30, 2012, respectively, $1,031 for both the three and nine months ended September 30, 2011 and $1,319 June 30, 2012.
 
 
 
Eagle Rock Energy Partners, L.P.
GAAP to Non-GAAP Reconciliations
($ in thousands)
(unaudited)
           
  Three Months Ended Nine Months Ended  Three Months Ended 
  September 30, September 30, June 30,
  2012 2011 2012 2011 2012
Net (loss) income to Adjusted EBITDA          
Net (loss) income, as reported  $ (106,895)  $ 97,365  $ (95,439)  $ 98,719  $ 61,789
Depreciation, depletion and amortization  40,395  35,040  118,043  90,314  38,354
Impairment  55,900  9,870  122,824  14,754  21,402
Risk management interest related instruments - unrealized  (615)  3,165  (4,418)  (2,191)  (2,007)
Risk management commodity related instruments - unrealized  51,305  (97,011)  (13,426)  (86,164)  (79,502)
Other Operating Income  --   --   --   (2,893)  -- 
Non-cash mark-to-market of Upstream product imbalances  229  (107)  338  (123)  307
Unrealized losses (gains) from other derivative activity  157  (538)  427  (538)  473
Restricted units non-cash amortization expense  3,080  1,507  8,092  3,441  2,818
Income tax (benefit) provision  (386)  (1,077)  (556)  (1,810)  (79)
Interest - net including realized risk management instruments and other expense  15,931  13,766  43,709  33,120  14,113
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 reported  $ (106,895)  $ 97,365  $ (95,439)  $ 98,719  $ 61,789
Depreciation, depletion and amortization expense  40,395  35,040  118,043  90,314  38,354
Impairment  55,900  9,870  122,824  14,754  21,402
Risk management interest related instruments-unrealized  (615)  3,165  (4,418)  (2,191)  (2,007)
Risk management commodity related instruments and other derivative activity - unrealized  51,462  (97,549)  (12,999)  (86,702)  (79,029)
Capital expenditures-maintenance related  (15,982)  (11,980)  (35,824)  (30,311)  (11,816)
Non-cash mark-to-market of Upstream product imbalances  229  (107)  338  (123)  307
Restricted units non-cash amortization expense  3,080  1,507  8,092  3,441  2,818
Other Operating Income  --   --   --   (2,893)  -- 
Income tax (benefit) provision  (386)  (1,077)  (556)  (1,810)  (79)
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

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