Eagle Rock Reports Second Quarter Financial Results

HOUSTON, July 31, 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 June 30, 2013. Financial results with respect to second quarter 2013 included the following:
  • Reported Adjusted EBITDA of $55.9 million, an increase of approximately 4% as compared to the $53.6 million reported for the first quarter of 2013.
  • Reported Distributable Cash Flow of $22.8 million, an increase of approximately 3% as compared to the $22.2 million reported for the first quarter of 2013.
  • Announced a quarterly distribution with respect to the second quarter of 2013 of $0.22 per common unit, equal to the first quarter 2013 distribution.
  • Reported Net Income of $16.0 million, as compared to a Net Loss of $33.5 million for the first quarter of 2013.

Other notable financial and operational activities that occurred during the second quarter of 2013 included the following:
  • Startup of its 60 MMcf/d cryogenic processing facility in Wheeler County, Texas, in the heart of the prolific Granite Wash play (the "Wheeler Plant").
  • Execution of a new, fee-based gas gathering and processing agreement with Monarch Natural Gas, LLC ("Monarch"), under which Monarch has dedicated to the Partnership all of its gathered natural gas volume from wells within an area encompassing more than 150,000 gross acres, located in Hemphill, Lipscomb and Ochiltree counties, Texas.
  • Amendment of its existing senior secured credit facility to allow for a temporary step-up in the Total Leverage Ratio and the Senior Secured Leverage Ratio through the third quarter of 2014.

"Second quarter results were below our expectations due primarily to the weak NGL price environment and lower than anticipated volume growth in both businesses," said Joseph A. Mills, Eagle Rock's Chairman and Chief Executive Officer. "However, we are seeing positive results from drilling activity on our new acreage dedications in the Midstream Business, synergies associated with our BP acquisition and recent drilling activity in the Upstream Business."

"In addition, we appreciate the continued support of our lender group who recently approved an amendment to our senior secured credit facility which substantially enhances our financial flexibility so we may continue to pursue organic growth opportunities," stated Mills.

Second 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 the Partnership's operating income by business segment compares the Partnership's financial results in the second quarter of 2013 to those of the first quarter of 2013. Please refer to the financial tables at the end of this release for further detailed information.

Midstream Business – Operating income from continuing operations for the Midstream Business in the second quarter of 2013 increased by approximately $0.7 million, or approximately 10%, compared to the first quarter of 2013. This increase was due to higher natural gas, NGL, and condensate volumes and higher average realized prices for natural gas. These factors were partially offset by lower average realized prices for NGLs and condensate.

In the Texas Panhandle, gathered volumes were up 2%, with combined equity NGL and condensate volumes up approximately 65%, as compared to the first quarter of 2013, on a reported basis. However, this increase was primarily due to negative adjustments and updates to estimates impacting reported equity NGL and condensate volumes in the first quarter of 2013 related to the Partnership's acquisition of BP's Sunray and Hemphill processing plants and associated 2,500 mile gathering system. Excluding the impact of these adjustments, combined equity NGL and condensate volumes for the second quarter of 2013 were down approximately 7%, as compared to the first quarter of 2013. This decrease was primarily due to the rejection of ethane for the entire second quarter of 2013 versus the rejection of ethane during a portion of the first quarter. Eagle Rock's decision to reject ethane is an economic decision based on the Partnership's contract portfolio and the price spread between ethane and natural gas.

In the Partnership's East Texas and Other Midstream segment, gathered volumes were down 3%, with equity NGL and condensate volumes up approximately 43%, compared to the first quarter of 2013, on a reported basis. This increase was due to higher gathering volumes around the Partnership's systems servicing the liquids-rich Woodbine formation in East Texas and to adjustments in measured volumes in the second quarter of 2013. Excluding the impact of these adjustments, combined equity NGL and condensate volumes for the second quarter of 2013 were up approximately 15%, as compared to the first quarter of 2013.

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 second quarter of 2013, including intercompany sales and intersegment cost of sales, was up approximately 2% compared to the first quarter of 2013.

Upstream Business - Operating income for Eagle Rock's Upstream Business in the second quarter of 2013, excluding the impact of impairments, increased by approximately $2.5 million, or 20%, compared to the first quarter of 2013. The increase was driven by higher oil production, lower workover expense, and higher realized natural gas prices, and was partially offset by lower NGL production and lower realized NGL prices. Total production volumes in the Upstream Business averaged 72.7 MMcfe/d during the quarter. This production rate is unchanged from the first quarter of 2013, but lower than anticipated primarily due to an additional shutdown of the Flomaton plant facility, ongoing higher than expected fuel usage at the Big Escambia Creek (BEC) facility, and certain unsuccessful recompletions.

During the quarter, Eagle Rock brought online five new operated wells in the Partnership's Golden Trend field and the South Central Oklahoma Oil Province ("SCOOP") acreage in Oklahoma. Three of these wells are located in Grady County, Oklahoma and were drilled and completed late in the second quarter. Production from these new wells is contributing to the Upstream Business' current estimated July production of 77 MMcfe/d. One of these new wells is the Partnership's third operated horizontal Woodford shale well in the SCOOP play, the Riddle 14-32H well, in which the Partnership has a 60% working interest. The well was drilled and completed at a total cost of approximately $8.2 million and began flowing to sales on June 27, 2013. During July the well has averaged 3.6 MMcf/d and 230 bopd.

Corporate Segment – Operating loss for the Corporate Segment, excluding the impact of unrealized derivative gains and losses, was $11.7 million for the second quarter of 2013 as compared to a $9.4 million loss for the first quarter of 2013. The increased loss was attributable to a $1.8 million reduction in realized commodity derivative gains and a $0.5 million increase in general and administrative expenses for the second quarter, partially offset by a decrease in intercompany eliminations.

Total revenue for the second quarter of 2013, including the impact of the Partnership's realized and unrealized commodity derivative gains and losses, was $320.2 million, up 24.2% compared with the $257.7 million reported for the first quarter of 2013. The increase in revenue was primarily due to higher unrealized gains on commodity derivatives and higher revenue from sales of natural gas, NGLs, oil, condensate, sulfur and helium compared to the first quarter of 2013. The Partnership recorded an unrealized gain on commodity derivatives of $22.3 million in the second quarter 2013, as compared to an unrealized loss on commodity derivatives of $27.9 million in the first quarter 2013. Unrealized gain (loss) on commodity derivatives is a non-cash, mark-to-market amount.

Revenues associated with the sale of natural gas, NGLs, oil, condensate, sulfur and helium were up 6% relative to the first quarter of 2013, driven primarily by the impact of higher natural gas prices and higher volumes in the Midstream Business, but partially offset by lower NGL and condensate prices. Adjusted EBITDA was $55.9 million for the second quarter of 2013, up 4% from the first quarter of 2013, and Distributable Cash Flow was $22.8 million for the second quarter of 2013, up 3% as compared to the first quarter of 2013. The increase in Distributable Cash Flow was primarily attributable to higher Adjusted EBITDA and slightly lower interest expense, partially offset by higher maintenance capital spending during the quarter. The Partnership recorded approximately $14.9 million of maintenance capital in the second quarter of 2013, an increase of $2.2 million as compared to the first quarter of 2013.  Of the second quarter 2013 maintenance capital, approximately $0.8 million was related to the previously-disclosed, scheduled upgrades to the Partnership's Big Escambia Creek facility located in Southern Alabama to enhance SO 2 emissions reductions, as compared to approximately $0.5 million recorded in the first quarter of 2013.

The Partnership recorded net income of approximately $16.0 million for the second quarter of 2013, versus a net loss of $33.5 million for the first quarter of 2013. The increase was driven primarily by higher unrealized commodity derivative gains in the second quarter of 2013 and higher revenues associated with the sale of natural gas, NGLs, oil, condensate, sulfur and helium during the second quarter of 2013. Net loss for the quarter excluding the impact of unrealized gains and losses and impairments was approximately $6.0 million. The Partnership incurred a $1.8 million impairment charge in its Upstream Business in the second quarter of 2013 related to certain proved properties primarily in the Permian region due to reduced cash flows resulting from lower commodity prices and continued high operating costs.

Second Quarter Distribution

On July 23, 2013, the Partnership declared a cash distribution for the quarter ended June 30, 2013 of $0.22 per unit, equivalent to $0.88 per unit on an annualized basis. The distribution will be paid on a total of 159.0 million common and eligible restricted units. The second quarter 2013 distribution is equal to the distribution paid for the first quarter 2013. Distribution coverage, calculated as distributable cash flow per unit divided by distributions per unit, was approximately 0.65 times for the second quarter, which is roughly consistent with distribution coverage in the first quarter of 2013. The distribution will be paid on Wednesday, August 14, 2013, to unitholders of record as of the close of business on Wednesday, August 7, 2013.

Capitalization and Liquidity Update

Total debt outstanding as of June 30, 2013 was $1.16 billion, consisting of $544.9 million of senior unsecured notes (net of an unamortized debt discount of $5.1 million) and borrowings of $613.0 million under the Partnership's senior secured credit facility.

On July 23, 2013, the Partnership and its lenders amended the senior secured credit facility to allow for a temporary step-up in the Total Leverage Ratio and the Senior Secured Leverage Ratio, as defined therein, through the third quarter of 2014 and the third quarter of 2013, respectively. The amendment also extends the period of time the Partnership is subject to the Senior Secured Leverage Ratio from September 30, 2013 to September 30, 2014. The amendment is effective as of June 30, 2013, and adjusts the Total Leverage Ratio and Senior Secured Leverage Ratio covenants as follows:
         
  Total Leverage Ratio Senior Secured Leverage Ratio
  Amended Previous Amended Previous
2Q13 5.50x 4.75x 3.15x 2.85x
3Q13 5.50x 4.75x 3.15x 2.85x
4Q13 5.50x 4.50x 3.15x NA
1Q14 5.25x 4.50x 3.10x NA
2Q14 5.00x 4.50x 3.05x NA
3Q14 4.75x 4.50x 2.95x NA
Thereafter 4.50x 4.50x NA NA
         

The Partnership is in compliance with its financial covenants and has no maturities under its senior secured credit facility until June 2016. As of June 30, 2013, the Partnership had approximately $164.4 million of availability under its senior secured credit facility, after taking into account $613.0 million of outstanding borrowings and approximately $25.3 million of outstanding letters of credit. 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. 

The current 2013 capital budget is approximately $208 million, which includes $60 million expected to be allocated to maintenance capital expenditures and $148 million expected to be allocated to growth capital expenditures. The current 2013 capital budget includes approximately $90 million allocated to the Midstream Business and approximately $115 million allocated to the Upstream Business (with the remainder allocated to general corporate purposes). The Partnership's capital expenditures were approximately $67.4 million for the three months ended June 30, 2013, of which $14.9 million were related to maintenance capital expenditures and $52.5 million were related to growth capital expenditures. 

As of June 30, 2013, the Partnership had 159.6 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 most recent hedging update on March 28, 2013:
         
Transaction Date Product / (Type) Quantity Price ($/Bbl) Term
6/13/2013 WTI Crude 20,000 $87.30 Cal. 2015
  (Swap) Bbls/month    
6/13/2013 WTI Crude 20,000 $87.28 Cal. 2015
  (Swap) Bbls/month    
6/13/2013 WTI Crude 20,000 $84.40 Cal. 2016
  (Swap) Bbls/month    
6/14/2013 WTI Crude 20,000 $84.55 Cal. 2016
  (Swap) Bbls/month    
         

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

Second Quarter 2013 Conference Call Information

The Partnership will hold a conference call to discuss its second quarter 2013 financial and operating results on Thursday, August 1, 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 21592571. 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 21592571. In addition, a replay of the audio webcast will be available by accessing the Partnership's website after the call is concluded.

About the Partnership

The Partnership is a growth-oriented master limited partnership engaged in two businesses: a) midstream, which includes (i) gathering, compressing, treating, processing and transporting natural gas; (ii) fractionating and transporting natural gas liquids (NGLs); (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.

Adjusted EBITDA does not include interest expense, income taxes or depreciation and amortization expense. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate net income. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net income (loss) and net cash flows provided by operating activities determined under GAAP, as well as Adjusted EBITDA, to evaluate our performance and liquidity.

Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flows provided by operating activities or any other measure of financial performance presented in accordance with U.S. GAAP.

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. For purposes of the foregoing, maintenance capital expenditures are intended to 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. In particular, with respect to maintenance capital expenditures intended to maintain the Partnership's natural gas, NGL, crude or sulfur production, the Partnership estimates these amounts based on current projections and expectations, and the Partnership does not undertake to adjust any historical amounts based on the actual impact of such expenditures on production. As a result, the included amount of maintenance capital expenditures could fail to maintain production if actual performance does not meet projections and expectations.

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 or declines (including sustained declines) in 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 and the Partnership's Forms 10-Q filed with the SEC for subsequent quarters, including the Partnership's Form 10-Q to be filed for the quarter ended June 30, 2013, 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 Six Months Ended Three Months
  June 30, June 30, Ended March
  2013 2012 2013 2012 31, 2013
REVENUE:          
Natural gas, natural gas liquids, oil, condensate, sulfur and helium sales  $ 269,392  $ 172,945  $ 523,592  $ 395,658  $ 254,200
Gathering, compression, processing and treating fees  20,153  10,451  41,095  21,962  20,942
Unrealized commodity derivative gains (losses)  22,316  79,502  (5,590)  64,731  (27,906)
Realized commodity derivative gains  8,177  16,463  18,175  22,626  9,998
Other revenue  113  3,043  610  3,182  497
Total revenue  320,151  282,404  577,882  508,159  257,731
           
COSTS AND EXPENSES:          
Cost of natural gas and natural gas liquids  185,760  97,914  365,748  228,368  179,988
Operations and maintenance  35,122  27,562  67,341  54,611  32,219
Taxes other than income  5,060  4,620  8,926  9,770  3,866
General and administrative  19,396  18,736  38,243  35,577  18,847
Impairment  1,839  21,402  1,839  66,924  — 
Depreciation, depletion and amortization  41,157  38,354  81,394  77,648  40,237
Total costs and expenses  288,334  208,588  563,491  472,898  275,157
OPERATING INCOME (LOSS)  31,817  73,816  14,391  35,261  (17,426)
OTHER INCOME (EXPENSE):          
Interest expense, net  (16,609)  (10,647)  (33,693)  (20,888)  (17,084)
Realized interest rate derivative losses  (1,685)  (3,470)  (3,336)  (6,845)  (1,651)
Unrealized interest rate derivative gains  1,534  2,007  3,029  3,803  1,495
Other income (expense)  113  4  105  (45)  (8)
Total other expense  (16,647)  (12,106)  (33,895)  (23,975)  (17,248)
INCOME (LOSS) BEFORE INCOME TAXES  15,170  61,710  (19,504)  11,286  (34,674)
INCOME TAX BENEFIT  (862)  (79)  (2,022)  (170)  (1,160)
NET INCOME (LOSS)  $ 16,032  $ 61,789  $ (17,482)  $ 11,456  $ (33,514)
           
Eagle Rock Energy Partners, L.P.
Consolidated Balance Sheets
($ in thousands)
(unaudited)
     
  June 30, 2013 December 31, 2012
ASSETS    
CURRENT ASSETS:    
Cash and cash equivalents  $ 95  $ 25
Accounts receivable  150,257  138,732
Risk management assets  24,202  33,340
Prepayments and other current assets  9,070  9,867
Total current assets  183,624  181,964
PROPERTY, PLANT AND EQUIPMENT - Net  2,021,705  1,968,206
INTANGIBLE ASSETS - Net  108,289  111,515
DEFERRED TAX ASSET  1,646  1,656
RISK MANAGEMENT ASSETS  17,003  7,953
OTHER ASSETS  20,675  22,922
TOTAL ASSETS  $ 2,352,942  $ 2,294,216
     
LIABILITIES AND MEMBERS' EQUITY    
CURRENT LIABILITIES:    
Accounts payable  $ 183,464  $ 160,473
Accrued liabilities  27,278  19,764
Taxes payable  —   46
Risk management liabilities  2,032  1,231
Total current liabilities  212,774  181,514
LONG-TERM DEBT  1,157,923  1,153,103
ASSET RETIREMENT OBLIGATIONS  47,436  44,814
DEFERRED TAX LIABILITY  41,092  43,000
RISK MANAGEMENT LIABILITIES  3,466  1,700
OTHER LONG TERM LIABILITIES  3,102  1,711
MEMBERS' EQUITY  887,149  868,374
TOTAL LIABILITIES AND MEMBERS' EQUITY  $ 2,352,942  $ 2,294,216
     
 
Eagle Rock Energy Partners, L.P.
Segment Summary
Operating Income
($ in thousands)
(unaudited)
           
  Three Months Ended Six Months Ended Three Months
  June 30, June 30, Ended March
  2013 2012 2013 2012 31, 2013
Midstream          
Revenues:          
Natural gas, natural gas liquids, oil and condensate sales  $ 231,734  $ 140,324  $ 452,229  $ 321,256  $ 220,495
Intercompany sales - natural gas and condensate  (2,275)  (2,113)  (4,070)  (4,963)  (1,795)
Gathering and treating services  20,153  10,451  41,095  21,962  20,942
Other revenue  37  2,864  37  2,864  — 
Total revenue  249,649  151,526  489,291  341,119  239,642
Cost of natural gas, natural gas liquids, oil and condensate  185,760  97,914  365,748  228,368  179,988
Intersegment cost of sales - natural gas and condensate  9,405  10,383  20,517  24,014  11,112
Operating costs and expenses:          
Operations and maintenance  27,020  18,164  48,989  35,531  21,969
Impairment  —   20,617  —   66,139  — 
Depreciation, depletion and amortization  19,087  16,565  38,018  33,247  18,931
Total operating costs and expenses  46,107  55,346  87,007  134,917  40,900
Operating income (loss)  $ 8,377  $ (12,117)  $ 16,019  $ (46,180)  $ 7,642
           
Upstream          
Revenue          
Oil and condensate sales  $ 15,756  $ 12,247  $ 28,069  $ 29,712  $ 12,313
Intersegment sales - condensate  9,220  10,306  20,506  22,795  11,286
Natural gas sales  10,355  6,832  18,536  14,150  8,181
Intersegment sales - natural gas  2,374  2,113  4,188  4,963  1,814
Natural gas liquids sales  8,596  10,340  18,872  23,081  10,276
Sulfur sales  2,951  3,202  5,886  7,459  2,935
Other  76  179  573  318  497
Total revenue  49,328  45,219  96,630  102,478  47,302
Operating costs and expenses:          
Operations and maintenance  13,162  14,018  27,278  28,850  14,116
Impairment  1,839  785  1,839  785  — 
Depreciation, depletion and amortization  21,456  21,366  42,385  43,586  20,929
Total operating costs and expenses  36,457  36,169  71,502  73,221  35,045
Operating income  $ 12,871  $ 9,050  $ 25,128  $ 29,257  $ 12,257
           
Corporate and Other          
Revenues:          
Unrealized commodity derivative gains (losses)  $ 22,316  $ 79,502  $ (5,590)  $ 64,731  $ (27,906)
Realized commodity derivative gains  8,177  16,463  18,175  22,626  9,998
Intersegment elimination - Sales of natural gas and condensate  (9,319)  (10,306)  (20,624)  (22,795)  (11,305)
Total revenue  21,174  85,659  (8,039)  64,562  (29,213)
Costs and expenses:          
Intersegment elimination - Cost of natural gas and condensate  (9,405)  (10,383)  (20,517)  (24,014)  (11,112)
General and administrative  19,396  18,736  38,243  35,577  18,847
Depreciation, depletion and amortization  614  423  991  815  377
Operating income (loss)  $ 10,569  $ 76,883  $ (26,756)  $ 52,184  $ (37,325)
           
 
Eagle Rock Energy Partners, L.P.
Midstream Segment
Operating Income
($ in thousands)
(unaudited)
           
  Three Months Ended Six Months Ended Three Months
  June 30, June 30, Ended March
  2013 2012 2013 2012 31, 2013
Texas Panhandle          
Revenues:          
Natural gas, natural gas liquids, condensate and helium sales  $ 108,505  $ 55,937  $ 214,899  $ 129,017  $ 106,394
Intersegment sales - natural gas and condensate  56,523  19,043  105,658  44,489  49,135
Gathering, compression, processing and treating services  12,031  3,852  24,552  8,802  12,521
Other revenue  37  2,864  37  2,864  — 
Total revenue  177,096  81,696  345,146  185,172  168,050
Cost of natural gas, natural gas liquids, condensate and helium  135,296  51,117  267,522  122,605  132,226
Intersegment cost of sales - natural gas  78  —   97  —   19
Operating costs and expenses:          
Operations and maintenance  22,022  12,399  39,156  24,637  17,134
Depreciation, depletion and amortization  14,005  9,873  27,850  19,390  13,845
Total operating costs and expenses  36,027  22,272  67,006  44,027  30,979
Operating income  $ 5,695  $ 8,307  $ 10,521  $ 18,540  $ 4,826
           
East Texas and Other Midstream          
Revenues:          
Natural gas, natural gas liquids, and condensate sales  $ 26,597  $ 30,998  $ 53,985  $ 72,268  $ 27,388
Intersegment sales - natural gas  12,705  6,928  21,243  16,451  8,538
Gathering, compression, processing and treating services  8,081  6,599  16,439  13,160  8,358
Total revenue  47,383  44,525  91,667  101,879  44,284
Cost of natural gas and natural gas liquids  36,340  32,550  69,574  78,058  33,234
Operating costs and expenses:                
Operations and maintenance  5,006  5,764  9,835  10,893  4,829
Impairment  —   20,617  —   66,139  — 
Depreciation, depletion and amortization  4,989  6,667  9,991  13,802  5,002
Total operating costs and expenses  9,995  33,048  19,826  90,834  9,831
Operating income (loss)  $ 1,048  $ (21,073)  $ 2,267  $ (67,013)  $ 1,219
           
Marketing and Trading          
Revenues:          
Natural gas, oil and condensate sales  $ 96,632  $ 53,389  $ 183,345  $ 119,971  $ 86,713
Intersegment sales - natural gas and condensate  (71,503)  (28,084)  (130,971)  (65,903)  (59,468)
Gathering, compression, processing and treating services  41  —   104  —   63
Total revenue  25,170  25,305  52,478  54,068  27,308
Cost of natural gas and condensate  14,124  14,247  28,652  27,705  14,528
Intersegment cost of sales - natural gas and condensate  9,327  10,383  20,420  24,014  11,093
Operating costs and expenses:            
Operations and maintenance  (8)  1  (2)  1  6
Depreciation, depletion and amortization  93  25  177  55  84
Total operating costs and expenses  85  26  175  56  90
Operating income  $ 1,634  $ 649  $ 3,231  $ 2,293  $ 1,597
           
Eagle Rock Energy Partners, L.P.
Midstream Operations Information
(unaudited)
           
  Three Months Ended Six Months Ended Three Months  
  June 30, June 30, Ended March
  2013 2012 2013 2012 31, 2013
Gas gathering volumes - (Average Mcf/d)          
Texas Panhandle  349,681  133,590  346,224  146,749  342,346
East Texas and Other Midstream  194,704  265,472  197,164  278,961  200,700
Total  544,385  399,062  543,388  425,710  543,046
           
NGLs - (Net equity Bbls)          
Texas Panhandle  265,538  297,688  325,800  626,802  64,551
East Texas and Other Midstream  74,620  84,981  127,605  176,325  53,204
Total  340,158  382,669  453,405  803,127  117,755
           
Condensate - (Net equity Bbls)          
Texas Panhandle  295,204  163,320  570,874  335,414  275,692
East Texas and Other Midstream  9,100  10,403  14,299  21,727  5,226
Total  304,304  173,723  585,173  357,141  280,918
           
Natural gas position - (Average MMbtu/d)          
Texas Panhandle  9,676  (5,629)  6,559  (6,546)  3,379
East Texas and Other Midstream  (190)  3,952  14  2,031  344
Total  9,486  (1,677)  6,573  (4,515)  3,723
           
Average realized NGL price - per Bbl          
Texas Panhandle $33.44 $38.30 $34.56 $42.40 $35.53
East Texas and Other Midstream $28.10 $39.72 $29.01 $42.53 $29.98
Weighted Average $32.41 $38.85 $33.52 $42.45 $34.51
           
Average realized condensate price - per Bbl          
Texas Panhandle $79.83 $82.29 $80.08 $89.28 $80.34
East Texas and Other Midstream $93.29 $103.71 $93.75 $103.68 $94.25
Weighted Average $80.56 $83.90 $80.80 $90.61 $81.06
           
Average realized natural gas price - per MMbtu          
Texas Panhandle $3.76 $1.93 $3.53 $2.19 $3.27
East Texas and Other Midstream $3.93 $2.22 $3.63 $2.59 $3.36
Weighted Average $3.81 $2.04 $3.56 $2.35 $3.29
           
Eagle Rock Energy Partners, L.P.
Upstream Operations Information
(unaudited)
           
  Three Months Ended Six Months Ended Three Months
  June 30, June 30, Ended March
  2013 2012 2013 2012 31, 2013
Upstream          
Production:          
Oil and condensate (Bbl) 294,353 266,580 573,421 590,524 279,069
Gas (Mcf) 3,181,264 4,341,298 6,310,316 8,437,103 3,129,052
NGLs (Bbl) 278,158 267,673 568,024 546,404 289,866
Total Mcfe 6,616,330 7,546,811 13,158,986 15,258,666 6,542,662
           
Sulfur (long ton) 26,641 21,705 53,240 50,697 26,598
           
Realized prices, excluding derivatives:          
Oil and condensate (per Bbl) $84.85 $84.60 $84.71 $88.92 $84.56
Gas (Mcf) $4.00 $2.06 $3.60 $2.27 $3.19
NGLs (Bbl) $30.90 $38.63 $33.22 $42.24 $35.45
Sulfur (long ton) $110.75 $147.55 $110.54 $147.15 $110.34
           
Operating statistics:          
Operating costs per Mcfe (incl production taxes) (1) $1.83 $1.68 $1.89 $1.73 $1.96
Operating costs per Mcfe (excl production taxes) (1) $1.28 $1.18 $1.44 $1.21 $1.59
Operating income per Mcfe $1.95 $1.20 $1.91 $1.92 $1.87
           
Drilling program (gross wells):          
Development wells 14 9 22 19 8
Completions 14 9 21 19 7
Workovers 11 4 18 9 7
Recompletions 6 1 7 3 1
           
(1) Excludes post-production costs of $1,083, $2,394, $1,319 and $2,467 for the three months ended June30, 2013 and 2012, respectively, and $1,311 for the three months ended March 31, 2013.
           

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 Six Months Ended Three Months
  June 30, June 30, Ended March
  2013 2012 2013 2012 31, 2013
Net income (loss) to Adjusted EBITDA          
Net income (loss), as reported  $ 16,032  $ 61,789  $ (17,482)  $ 11,456  $ (33,514)
Depreciation, depletion and amortization  41,157  38,354  81,394  77,648  40,237
Impairment  1,839  21,402  1,839  66,924  — 
Risk management interest related instruments - unrealized  (1,534)  (2,007)  (3,029)  (3,803)  (1,495)
Risk management commodity related instruments - unrealized  (22,475)  (79,029)  5,684  (64,461)  28,159
Non-cash mark-to-market of Upstream product imbalances  (5)  307  (5)  109  — 
Restricted units non-cash amortization expense  3,520  2,818  6,167  5,012  2,647
Income tax benefit  (862)  (79)  (2,022)  (170)  (1,160)
Interest - net including realized risk management instruments and other expense  18,181  14,113  36,924  27,778  18,743
Adjusted EBITDA  $ 55,853  $ 57,668  $ 109,470  $ 120,493  $ 53,617
           
Net income (loss) to Distributable Cash Flow          
Net income (loss), as reported  $ 16,032  $ 61,789  $ (17,482)  $ 11,456  $ (33,514)
Depreciation, depletion and amortization expense  41,157  38,354  81,394  77,648  40,237
Impairment  1,839  21,402  1,839  66,924  — 
Risk management interest related instruments-unrealized  (1,534)  (2,007)  (3,029)  (3,803)  (1,495)
Risk management commodity related instruments - unrealized  (22,475)  (79,029)  5,684  (64,461)  28,159
Capital expenditures-maintenance related  (14,900)  (11,816)  (27,614)  (19,842)  (12,714)
Non-cash mark-to-market of Upstream product imbalances  (5)  307  (5)  109  — 
Restricted units non-cash amortization expense  3,520  2,818  6,167  5,012  2,647
Income tax benefit  (862)  (79)  (2,022)  (170)  (1,160)
Cash income taxes  —   (189)  —   (564)  — 
Distributable Cash Flow  $ 22,772  $ 31,550  $ 44,932  $ 72,309  $ 22,160
           
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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