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Press release from GlobeNewswire (a Nasdaq OMX company)

Eagle Rock Reports First Quarter Financial Results

Wednesday, May 01, 2013

Eagle Rock Reports First Quarter Financial Results

13:56 EDT Wednesday, May 01, 2013

HOUSTON, May 1, 2013 (GLOBE NEWSWIRE) -- Eagle Rock Energy Partners, L.P. ("Eagle Rock" or the "Partnership") (Nasdaq:EROC) today announced its unaudited financial results for the three months ended March 31, 2013. The Partnership reported Adjusted EBITDA of $53.6 million for the quarter, a decrease of approximately 19% as compared to the $66.2 million reported for the fourth quarter of 2012. The decrease is attributable to a number of factors, including:

  • Approximately $2.8 million related to severe winter weather in the Texas Panhandle which caused shut-ins and prolonged reduced flow from many of the producing wells in the area and also caused reduced recovery efficiencies at the Partnership's processing facilities. The Partnership's operations in the Texas Panhandle have since returned to normal operations.
  • Approximately $3.9 million of charges taken in the current quarter related to adjustments and updates to estimates used in prior quarters.
  • Approximately $3.0 million related to the downtime experienced at the Partnership's Flomaton facility in Southern Alabama and unexpected workover expense on two wells that are connected to the facility.
  • The impact of declining NGL prices during the first quarter of 2013, especially in the heavier end of the NGL barrel.

Eagle Rock reported Distributable Cash Flow of $22.2 million as compared to the $29.5 million reported for the fourth quarter of 2012, with the decrease primarily driven by the same factors impacting Adjusted EBITDA. The Partnership also reported a Net Loss of $33.5 million, which in addition to the factors mentioned above was driven by unrealized mark-to-market losses on commodity hedges, which is a non-cash charge to earnings.

Other notable financial and operational activities of the Partnership during the first quarter of 2013 included the following:

  • Announced it had entered into a new fee-based Gas Gathering, Processing and Purchase Agreement with Apache Corporation ("Apache") to support Apache's active drilling program in the Texas Panhandle.
  • Announced a quarterly distribution with respect to the first quarter of 2013 of $0.22 per common unit, equal to the fourth quarter 2012 distribution.
  • Completed a public offering of 10.4 million common units for total net proceeds of approximately $92.5 million on March 18, 2013. The Partnership used the proceeds to repay a portion of the outstanding borrowings under its revolving credit facility associated with the acquisition of BP's assets in the Texas Panhandle.
  • Announced the upstream component of the borrowing base under its senior secured credit facility was decreased from $400 million to $375 million as part of the Partnership's regularly scheduled semi-annual redetermination by its commercial lenders.
  • Completed an exchange offer of $250 million of its 8 3/8% Senior Notes due 2019 for new notes with materially identical terms that have been registered under the Securities Act of 1933 and became freely tradable on March 1, 2013.

"We faced a challenging operating environment in the first quarter with severe winter storms impacting our midstream volumes and efficiencies in the Panhandle, and with NGL prices continuing near multi-year lows," said Joseph A. Mills, Eagle Rock's Chairman and Chief Executive Officer. "Despite these short-term challenges, the Partnership is well-positioned for future success in both businesses. Our integration of the midstream assets acquired from BP is progressing well, and we continue to see great interest from producers as evidenced by our recent acreage dedication agreement with Apache. Further, we are encouraged by our recent improved drilling results in our upstream business and the ongoing potential we see in the SCOOP play of southwestern Oklahoma."

Update Regarding Integration of Acquired BP Texas Panhandle Assets

The integration of the former BP assets continues on schedule. The pace of drilling activity and well connects on the system have been consistent with expectations. All back-office and operational functions are now integrated within Eagle Rock. Construction of the first major interconnect between the Partnership's legacy Panhandle assets and the former BP system will take place in the second quarter of 2013.

Update Regarding Construction of the Wheeler Cryogenic Processing Plant

Construction of the Wheeler 60 MMcf/d cryogenic processing plant (the "Wheeler Plant"), located in Wheeler County, and associated gathering and compression infrastructure, is expected to be completed in the second quarter of 2013 at a total cost of approximately $64 million, of which $47.9 million had been spent through March 31, 2012. Upon completion of the Wheeler Plant, the Partnership will have over 540 MMcf/d of high-efficiency processing capacity in the Texas Panhandle to serve continued drilling activity in the Granite Wash and surrounding geological plays.

New Fee-Based Apache Acreage Dedication

On March 6, 2013, the Partnership announced that it had entered into a new fee-based Gas Gathering, Processing and Purchase Agreement with Apache to support Apache's active drilling program in the Texas Panhandle.

As part of the agreement, Apache dedicated to the Partnership all existing and future wells drilled within an area encompassing more than 106,000 gross acres, located in Hemphill, Lipscomb, Ochiltree, Roberts, Hansford and Sherman Counties, Texas, under market-based terms. The agreement supersedes and expands on various existing agreements between the Partnership and Apache. The dedicated acreage covers the Granite Wash, Hogshooter, Tonkawa, Marmaton and Cleveland plays in the Anadarko Basin of the Texas Panhandle. The agreement provides for fee-based compensation to the Partnership and fixed NGL recoveries to Apache, and applies to all existing and future wells completed by Apache on any of the acreage in the dedicated area.

First Quarter 2013 Financial and Operating Results

The Partnership's financial results are reported in the following segments: (a) the Midstream Business -- Texas Panhandle; (b) the Midstream Business -- East Texas and Other Midstream; (c) the Midstream Business -- Marketing and Trading; (d) the Upstream Business; and (e) the Corporate segment.

The following discussion of Eagle Rock's operating income by business segment compares the Partnership's financial results in the first quarter of 2013 to those of the fourth 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 first quarter of 2012. 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 first quarter of 2013 decreased by approximately $3.5 million, or approximately 31%, compared to the fourth quarter of 2012, primarily due to lower gathering, NGLs and condensate volumes and to certain true-ups recorded in the quarter related to prior periods.

In the Texas Panhandle, gathered volumes were down 8%, with combined equity NGL and condensate volumes down approximately 53%, compared to the fourth quarter of 2012. NGL and condensate equity volumes were lower due to lower volumes and lower-than-normal NGL recovery rates as a result of the harsh winter storms in the Texas Panhandle in early January and late February 2013. The impact of these lower recovery rates on equity NGL volumes was even more pronounced because the Partnership pays many producers in the Texas Panhandle on a contractually-fixed theoretical recovery rate for NGL volumes (i.e., fixed recovery contracts). As such, vis-a-vis many of these producers, the Partnership was "short" actual NGL volumes during the quarter. The Partnership estimates that the impact of the freezing weather in the Texas Panhandle during the quarter to Adjusted EBITDA was approximately $2.8 million.  

NGL equity volumes were also lower due to the Partnership's decision to reject ethane during the quarter.  The Partnership's election to reject ethane is an economic decision based on its contract portfolio and the price spread between ethane and natural gas. Despite the negative impact on ethane equity volumes, this decision is made to enhance the overall economics for the Partnership.

In addition, the first quarter 2013 results were negatively impacted by prior period adjustments related to the BP Acquisition, which closed on October 1, 2012. As previously disclosed, following the fourth quarter 2012 earnings conference call on February 26, 2013, the Partnership received new information related to the system acquired from BP, which was operated by BP through the fourth quarter in accordance with a transition services agreement. The Partnership was informed that the cost of product sold on the system was higher than had been originally communicated.  As a result, an adjustment to reflect the previously disclosed understatement of cost of product sold in the fourth quarter of 2012 was made. This, combined with other true-ups recorded in the first quarter of 2013 negatively impacted the Partnership's Adjusted EBITDA by approximately $1.2 million.

In the Partnership's East Texas and Other Midstream segment, gathered volumes were down 7.7%, with equity NGL and condensate volumes down approximately 35%, compared to the fourth quarter of 2012. The decrease in gathered volumes was in part due to natural declines in the production of existing wells and a decrease in production from the Partnership's Tyler County gathering system in East Texas and the North Terrebonne plant, in which the Partnership owns a non-operated 3.07% interest, serving production from the Gulf of Mexico. The gathering volumes associated with the Partnership's Tyler County system hit recent highs in the fourth quarter of 2012 when one of its producer customer's wells came online in October and has since returned to normal levels. The volumes associated with the Partnership's North Terrebonne's plant were lower during the quarter primarily due to a lower ownership percentage in the plant, as compared to the fourth quarter, and lower associated third party drilling in the Gulf of Mexico. The decrease in combined equity NGL and condensate volumes was down primarily due to a true-up related to equity NGLs and condensate reported in the fourth quarter of 2012. Lower gathering volumes during the quarter also contributed to the decline.

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.  Operating income for the Marketing and Trading segment in the first quarter of 2013, including intercompany sales and intersegment cost of sales, increased by approximately $0.1 million compared to the fourth quarter of 2012. 

Upstream Business - Operating income for Eagle Rock's Upstream Business in the first quarter of 2013, excluding the impact of impairments, decreased by approximately $0.6 million, or 5%, compared to the fourth quarter of 2012. Production volumes in the Upstream Business averaged 72.7 MMcfe/d during the quarter, a decrease of approximately 7% from the fourth quarter of 2012. The quarter-over-quarter decreases were primarily due to lower production during the quarter associated with unscheduled downtime at the Partnership's Flomaton facility in Southern Alabama; a prior period reallocation adjustment of volumes flowing through the Eustace midstream plant located in East Texas and owned and operated by Tristream Energy; a separate prior period adjustment related to the Partnership's non-operated drilling program in the Mid-Continent; and a full quarter without the Partnership's non-core Barnett Shale assets, which were sold for $15 million on December 20, 2012.

From February 7 to April 18, 2013, Eagle Rock's Flomaton facility in Escambia County, Alabama was not operational due to minor equipment failure and insufficient inlet volumes to operate the facility's sulfur recovery unit.  During this time, the Partnership unsuccessfully attempted to work over two wells connected to the facility. The Flomaton facility resumed operations after equipment repairs were made and inlet gas rates were increased by diverting natural gas production from a nearby operated well.  The Partnership estimates the EBITDA impact during the quarter from these events was approximately $3.0 million.

The Partnership estimates the Adjusted EBITDA impact during the quarter from the prior period adjustments related to the Eustace plant and the lower expected actualization of the Partnership's non-operated drilling program mentioned above was approximately $0.8 and $1.9 million, respectively.

Corporate Segment – Operating loss for the Corporate segment, excluding the impact of unrealized derivative gains and losses, was $9.4 million for the first quarter of 2013 as compared to a $2.3 million loss for the fourth quarter of 2012. The increased loss was attributable to an increase in intercompany eliminations, a $2.9 million reduction in realized commodity derivative gains and an approximate $1.2 million increase in General and Administrative expenses for the first quarter.

Total revenue for the first quarter of 2013, including the impact of Eagle Rock's realized and unrealized commodity derivative gains and losses, was $257.7 million, down 17.5% compared with the $312.4 million reported for the fourth quarter of 2012. The decrease in revenue was primarily due to higher unrealized losses on commodity derivatives and lower revenue from sales of natural gas, NGLs, crude oil, condensate and sulfur compared to the fourth quarter of 2012. Eagle Rock recorded an unrealized loss on commodity derivatives of $27.9 million in the first quarter 2013, as compared to an unrealized loss on commodity derivatives of $6.9 million in the fourth quarter 2012. Unrealized gain (loss) on commodity derivatives is a non-cash, mark-to-market amount.

Revenues associated with the sale of crude oil, natural gas, NGLs, condensate and sulfur were down 11% relative to the fourth quarter of 2012, driven primarily by the impact of unscheduled downtime at the Partnership's Flomaton facility, harsh winter weather in the Texas Panhandle and the prior period adjustments mentioned above. Adjusted EBITDA was $53.6 million for the first quarter of 2013, down 19% from the fourth quarter of 2012, and Distributable Cash Flow was $22.2 million for the first quarter of 2013, down 25% as compared to the fourth quarter of 2012. The decrease in Distributable Cash Flow was primarily attributable to lower Adjusted EBITDA and slightly higher interest expense, partially offset by lower maintenance capital spending during the quarter. The Partnership recorded approximately $12.7 million of maintenance capital in the first quarter of 2013, a decrease of $5.9 million as compared to the fourth quarter of 2012.  Of the first quarter 2013 maintenance capital, $0.5 million was related to the previously-disclosed, scheduled upgrades to Eagle Rock's Big Escambia Creek facility located in Southern Alabama to enhance SO2 emissions reductions.

The Partnership recorded a net loss of approximately $33.5 million for the first quarter of 2013, versus a net loss of $55.2 million for the fourth quarter of 2012. The reduction in net loss was driven primarily by impairment charges in the fourth quarter of 2012, offset by higher unrealized commodity derivative losses taken during the first quarter of 2013 and lower revenues associated with the sale of crude oil, natural gas, NGLs, condensate and sulfur during the first quarter of 2013. Net loss for the quarter excluding the impact of unrealized gains and losses was approximately $7.1 million. The Partnership did not incur any impairment charges in the first quarter of 2013.

First Quarter Distribution

On April 23, 2013, the Partnership declared a cash distribution on common units of $0.22 per unit for the quarter ended March 31, 2013, equivalent to $0.88 per unit on an annualized basis. This distribution is equal to the distribution paid for the fourth quarter 2012. As declared, the distribution will be paid on Wednesday, May 15, 2013, to unitholders of record as of the close of business on Tuesday, May 7, 2013, including holders of restricted common units other than those issued in late April and early May of 2013.

Capitalization and Liquidity Update

Total debt outstanding as of March 31, 2012 was $1.12 billion, consisting of $544.8 million of senior unsecured notes (net of an unamortized debt discount of $5.2 million) and borrowings of $577.8 million under the Partnership's senior secured credit facility. Total debt decreased during the first quarter of 2013 as a result of repayments from the proceeds of the Partnership's $92.5 million public offering of 10.4 million common units on March 18, 2013. Borrowings during the quarter were primarily to fund the construction of the Wheeler Plant and the Partnership's Upstream drilling program.

The Partnership is in compliance with its financial covenants and has no maturities under its senior secured credit facility until June 2016. Availability under the Partnership's senior secured credit facility is subject to a borrowing base comprised of two components: the upstream component and the midstream component. On April 17, 2013, the Partnership announced the upstream component of the borrowing base under its senior secured credit facility was decreased from $400 million to $375 million as part of the Partnership's regularly scheduled semi-annual redetermination by its commercial lenders. As of March 31, 2013, the Partnership had approximately $215.4 million of availability under its senior secured credit facility, based on its outstanding commitments, after taking into account $577.8 million of outstanding borrowings and approximately $26.8 million of outstanding letters of credit. Availability under the revolving credit facility as of March 31, 2013, considering the additional impact of covenant limitations, was approximately $52 million.

The current capital budget for 2013 is approximately $208 million in total, which includes $70 million allocated to maintenance capital expenditures and $138 million allocated to growth capital expenditures. The current capital budget for 2013 includes approximately $88 million allocated to the Midstream Business and approximately $118 million allocated to the Upstream Business (with the remainder allocated to general corporate purposes). The Partnership's capital expenditures were approximately $56.0 million for the three months ended March 31, 2013, of which $12.7 million were related to maintenance capital expenditures and $43.2 million were related to growth capital expenditures. 

As of March 31, 2012, the Partnership had 157.7 million common units outstanding, including unvested restricted common units issued under its Long-Term Incentive Plan.

Hedging Update

The Partnership entered into the following commodity hedges since its hedging update on February 25, 2013:

 
Transaction
Date

Product / (Type)

Quantity

Price ($/Bbl)

Term
3/22/13 WTI Crude
(Swap)
20,000
Bbls/month
$85.20 Cal. 2016
3/22/13 WTI Crude
(Swap)
20,000
Bbls/month
$85.00 Cal. 2016
3/22/13 HH Natural
Gas (Swap)
250,000
MMBtu/month
$4.36 Cal. 2016

Details of the recent hedging transactions are included in the updated Commodity Hedging Overview presentation Eagle Rock posted to its website on March 28, 2013. The latest presentation can be accessed by going to www.eaglerockenergy.com: select Investor Relations, then select Presentations.

First Quarter 2013 Conference Call Information

Eagle Rock will hold a conference call to discuss its first quarter 2013 financial and operating results on Thursday, May 2, 2013 at 2:00 p.m. Eastern Time (1:00 p.m. Central Time).

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 50061377. 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 50061377. 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; (iii) crude oil and condensate 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. 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. 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, 2012, as well as any other public filings, including, when filed, the Partnership's Form 10-Q for the quarter ended March 31, 2013, and press releases.

Eagle Rock Energy Partners, L.P.
Consolidated Statement of Operations
($ in thousands)
(unaudited)
       
 
Three Months Ended
Three Months
Ended
  March 31, December 31,
  2013 2012 2012
REVENUE:      
Natural gas, natural gas liquids, oil, condensate and sulfur sales  $ 254,200  $ 222,713  $ 284,732
Gathering, compression, processing and treating fees  20,942  11,511  21,265
Unrealized commodity derivative losses  (27,906)  (14,771)  (6,864)
Realized commodity derivative gains  9,998  6,163  12,904
Other revenue  497  139  374
Total revenue  257,731  225,755  312,411
       
COSTS AND EXPENSES:      
Cost of natural gas and natural gas liquids  179,988  130,454  193,921
Operations and maintenance  32,219  27,049  38,143
Taxes other than income  3,866  5,150  4,914
General and administrative  18,847  16,841  17,610
Impairment  --   45,522  54,179
Depreciation, depletion and amortization  40,237  39,294  43,002
Total costs and expenses  275,157  264,310  351,769
OPERATING LOSS  (17,426)  (38,555)  (39,358)
OTHER INCOME (EXPENSE):      
Interest expense, net  (17,084)  (10,241)  (16,391)
Realized interest rate derivative losses  (1,651)  (3,375)  (1,649)
Unrealized interest rate derivative gains  1,495  1,796  1,082
Other (expense) income  (8)  (49)  6
Total other expense  (17,248)  (11,869)  (16,952)
       
LOSS BEFORE INCOME TAXES  (34,674)  (50,424)  (56,310)
INCOME TAX BENEFIT  (1,160)  (91)  (1,147)
NET LOSS  $ (33,514)  $ (50,333)  $ (55,163)
 
Eagle Rock Energy Partners, L.P.
Consolidated Balance Sheets
($ in thousands)
(unaudited)
     
  March 31,
2013
December 31,
2012
ASSETS    
CURRENT ASSETS:    
Cash and cash equivalents  $ 60  $ 25
Accounts receivable  144,272  138,732
Risk management assets  14,789  33,340
Prepayments and other current assets  10,122  9,867
Total current assets  169,243  181,964
PROPERTY, PLANT AND EQUIPMENT - Net  1,988,530  1,968,206
INTANGIBLE ASSETS - Net  109,901  111,515
DEFERRED TAX ASSET  1,655  1,656
RISK MANAGEMENT ASSETS  9,752  7,953
OTHER ASSETS  21,530  22,922
TOTAL ASSETS  $ 2,300,611  $ 2,294,216
     
LIABILITIES AND MEMBERS' EQUITY    
CURRENT LIABILITIES:    
Accounts payable  $ 148,689  $ 160,473
Accrued liabilities  32,518  19,764
Taxes payable  46  46
Risk management liabilities  3,438  1,231
Total current liabilities  184,691  181,514
LONG-TERM DEBT  1,122,560  1,153,103
ASSET RETIREMENT OBLIGATIONS  41,569  44,814
DEFERRED TAX LIABILITY  41,838  43,000
RISK MANAGEMENT LIABILITIES  9,405  1,700
OTHER LONG TERM LIABILITIES  3,049  1,711
MEMBERS' EQUITY  897,499  868,374
TOTAL LIABILITIES AND MEMBERS' EQUITY  $ 2,300,611  $ 2,294,216
 
Eagle Rock Energy Partners, L.P.
Segment Summary
Operating Income
($ in thousands)
(unaudited)
       
 
Three Months Ended
Three Months
Ended 
  March 31, December 31,
  2013 2012 2012
Midstream      
Revenues:      
Natural gas, natural gas liquids, oil and condensate sales  $ 220,495  $ 180,932  $ 248,153
Intercompany sales - natural gas  (1,795)  (2,850)  (2,325)
Gathering and treating services  20,942  11,511  21,265
Other -- -- --
Total revenue  239,642  189,593  267,093
Cost of natural gas, natural gas liquids, oil and condensate (1)  180,007  130,454  194,004
Intersegment elimination - cost of condensate  11,093  13,631  11,705
Operating costs and expenses:      
Operations and maintenance  21,969  17,367  29,470
Impairment  --   45,522  29,735
Depreciation, depletion and amortization  18,931  16,682  20,760
Total operating costs and expenses  40,900  79,571  79,965
Operating income (loss)  $ 7,642  $ (34,063)  $ (18,581)
       
Upstream      
Revenue      
Oil and condensate sales  $ 12,409  $ 17,465  $ 14,332
Intersegment sales - condensate  11,190  12,489  8,778
Natural gas sales  8,200  7,318  9,631
Intersegment sales - natural gas  1,795  2,850  2,530
Natural gas liquids sales  10,276  12,741  9,771
Sulfur sales  2,935  4,257  2,845
Other  497  139  374
Total revenue  47,302  57,259  48,261
Operating costs and expenses:      
Operations and maintenance (2)  14,116  14,832  13,709
Impairment  --   --   24,444
Depreciation, depletion and amortization  20,929  22,220  21,707
Total operating costs and expenses  35,045  37,052  59,860
Operating income (loss)  $ 12,257  $ 20,207  $ (11,599)
       
Corporate and Other      
Revenues:      
Unrealized commodity derivative (losses) gains  $ (27,906)  $ (14,771)  $ (6,864)
Realized commodity derivative gains (losses)  9,998  6,163  12,904
Intersegment elimination - sales of condensate  (11,305)  (12,489)  (8,983)
Total revenue  (29,213)  (21,097)  (2,943)
Costs and expenses:      
Intersegment elimination - cost of condensate  (11,112)  (13,631)  (11,788)
General and administrative  18,847  16,841  17,610
Intersegment elimination - operations and maintenance  --   --   (122)
Depreciation, depletion and amortization  377  392  535
Operating loss  $ (37,325)  $ (24,699)  $ (9,178)
       
(1) Includes purchase of natural gas of $19 from the Upstream Segment to the Panhandle Segment for the three months ended March 31, 2013.
(2) Includes purchase of natural gas of $122 from the Marketing and Trading Segment to the Upstream Segment for the three months ended December 31, 2012.
 
Eagle Rock Energy Partners, L.P.
Midstream Segment
Operating Income
($ in thousands)
(unaudited)
       
 
Three Months Ended
Three Months
Ended 
  March 31, December 31,
  2013 2012 2012
Texas Panhandle      
Revenues:      
Natural gas, natural gas liquids, oil and condensate sales  $ 106,394  $ 73,080  $ 145,065
Intersegment sales - natural gas and condensate  49,135  25,446  33,245
Gathering, compression, processing and treating services  12,521  4,950  12,233
Other -- -- --
Total revenue  168,050  103,476  190,543
Cost of natural gas, natural gas liquids, oil and condensate (1)  132,245  71,488  143,172
Operating costs and expenses:      
Operations and maintenance  17,134  12,238  23,542
Depreciation, depletion and amortization  13,845  9,517  14,897
Total operating costs and expenses  30,979  21,755  38,439
Operating income  $ 4,826  $ 10,233  $ 8,932
       
East Texas and Other Midstream      
Revenues:      
Natural gas, natural gas liquids, oil and condensate sales  $ 27,388  $ 41,270  $ 27,114
Intercompany sales - natural gas  8,538  9,523  12,628
Gathering, compression, processing and treating services  8,358  6,561  8,961
Total revenue  44,284  57,354  48,703
Cost of natural gas and natural gas liquids and condensate  33,234  45,508  36,290
Operating costs and expenses:          
Operations and maintenance  4,829  5,129  5,929
Impairment  --   45,522  29,735
Depreciation, depletion and amortization  5,002  7,135  5,737
Total operating costs and expenses  9,831  57,786  41,401
Operating income (loss) $ 1,219 $ (45,940) $ (28,988)
       
Marketing and Trading      
Revenues:      
Natural gas, oil and condensate sales  $ 86,713  $ 66,582  $ 75,974
Intercompany sales - natural gas and condensate  (59,468)  (37,819)  (48,198)
Gathering, compression, processing and treating services 63 -- 71
Total revenue  27,308  28,763  27,847
Cost of natural gas and natural gas liquids  14,528  13,458  14,542
Intersegment cost of sales - condensate  11,093  13,631  11,705
Operating costs and expenses:        
Operations and maintenance  6  --   (1)
Depreciation, depletion and amortization  84  30  126
Total operating costs and expenses  90  30  125
Operating income  $ 1,597  $ 1,644  $ 1,475
       
(1) Includes purchase of natural gas of $19 from the Upstream Segment to the Panhandle Segment for the three months ended March 31, 2013.
 
Eagle Rock Energy Partners, L.P.
Midstream Operations Information
(unaudited)
       
 
Three Months Ended
Three Months
Ended 
  March 31, December 31,
  2013 2012 2012
Gas gathering volumes - (Average Mcf/d)      
Texas Panhandle  342,346  159,907  372,124
East Texas and Other Midstream  200,700  292,449  217,496
Total  543,046  452,356  589,620
       
NGLs - (Net equity Bbls)      
Texas Panhandle  64,551  287,800  415,103
East Texas and Other Midstream  53,204  91,344  80,315
Total  117,755  379,144  495,418
       
Condensate - (Net equity Bbls)      
Texas Panhandle  275,692  213,616  302,168
East Texas and Other Midstream  5,226  11,324  9,613
Total  280,918  224,940  311,781
       
Natural gas position - (Average MMbtu/d)      
Texas Panhandle  3,379  (7,463)  16,114
East Texas and Other Midstream  344  109  1,676
Total  3,723  (7,354)  17,790
       
Average realized NGL price - per Bbl      
Texas Panhandle $35.53 $44.08 $31.39
East Texas and Other Midstream $29.98 $44.60 $32.04
Weighted Average $34.51 $44.30 $31.51
       
Average realized condensate price - per Bbl      
Texas Panhandle $80.34 $92.11 $74.32
East Texas and Other Midstream $94.25 $103.65 $87.20
Total $81.06 $93.12 $75.20
       
Average realized natural gas price - per MMbtu      
Texas Panhandle $3.27 $2.41 $3.23
East Texas and Other Midstream $3.36 $2.88 $3.37
Total $3.29 $2.60 $3.26
 
Eagle Rock Energy Partners, L.P.
Upstream Operations Information
(unaudited)
       
 
Three Months Ended
Three Months
Ended 
  March 31, December 31,
  2013 2012 2012
Upstream      
Production:      
Oil and condensate (Bbl) 279,069 323,944 283,326
Gas (Mcf) 3,129,052 4,095,805 3,828,320
NGLs (Bbl) 289,866 278,731 272,476
Total Mcfe 6,542,662 7,711,855 7,163,132
       
Sulfur (long ton) 26,598 28,992 22,892
       
Realized prices, excluding derivatives:      
Oil and condensate (per Bbl) $84.56 $92.46 $81.57
Gas (Mcf) $3.19 $2.48 $3.18
NGLs (Bbl) $35.45 $45.10 $35.86
Sulfur (long ton) $110.34 $145.70 $124.30
       
Operating statistics:      
Operating costs per Mcfe (incl production taxes) (1) $1.96 $1.77 $1.72
Operating costs per Mcfe (excl production taxes) (1) $1.59 $1.24 $1.22
Operating income per Mcfe $1.87 $2.62 ($1.62)
       
Drilling program (gross wells):      
Development wells 8 10 8
Completions 7 10 8
Workovers 7 5 2
Recompletions 1 2 4
       
(1) Excludes post-production costs of $1,311 and $1,148 for the three months ended March 31, 2013 and 2012, respectively, and $1,410 for the three months ended December 31, 2012.

Non-GAAP Financial Measures

The following tables present a reconciliation of the non-GAAP financial measures of Adjusted EBITDA and Distributable Cash Flow to the GAAP financial measure of net income for each of the periods indicated (in thousands).

Eagle Rock Energy Partners, L.P.
GAAP to Non-GAAP Reconciliations
($ in thousands)
(unaudited)
       
 
Three Months Ended
Three Months
Ended 
  March 31, December 31,
  2013 2012 2012
Net loss to Adjusted EBITDA      
Net loss, as reported  $ (33,514)  $ (50,333)  $ (55,163)
Depreciation, depletion and amortization  40,237  39,294  43,002
Impairment  --   45,522  54,179
Risk management interest related instruments - unrealized  (1,495)  (1,796)  (1,082)
Risk management commodity related instruments - unrealized  27,906  14,771  6,864
Non-cash mark-to-market of Upstream product imbalances  --   (198)  (21)
Unrealized losses (gains) from other derivative activity  253  (203)  (235)
Restricted units non-cash amortization expense  2,647  2,194  1,790
Income benefit provision  (1,160)  (91)  (1,147)
Interest - net including realized risk management instruments and other expense  18,743  13,664  18,040
Other income  --   --   (6)
Adjusted EBITDA  $ 53,617  $ 62,824  $ 66,221
       
Net loss to Distributable Cash Flow      
Net loss, as reported  $ (33,514)  $ (50,333)  $ (55,163)
Depreciation, depletion and amortization expense  40,237  39,294  43,002
Impairment  --   45,522  54,179
Risk management interest related instruments-unrealized  (1,495)  (1,796)  (1,082)
       
Risk management commodity related instruments and other derivative activity - unrealized  28,159  14,568  6,629
Capital expenditures-maintenance related  (12,714)  (8,026)  (18,593)
Non-cash mark-to-market of Upstream product imbalances  --   (198)  (21)
Restricted units non-cash amortization expense  2,647  2,194  1,790
Income benefit provision  (1,160)  (91)  (1,147)
Other income  --   --   (6)
Cash income taxes  --   (375)  (75)
Distributable Cash Flow  $ 22,160  $ 40,759  $ 29,513
CONTACT: Eagle Rock Energy Partners, L.P.
Jeff Wood, 281-408-1203
Senior Vice President and Chief Financial Officer
Adam Altsuler, 281-408-1350
Vice President, Corporate Finance and
Investor Relations, Treasurer

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