Eagle Rock Reports Third Quarter 2011 Financial Results


HOUSTON, Nov. 2, 2011 (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 and nine months ended September 30, 2011. Key financial results for the third quarter 2011 included the following:

  • Reported Adjusted EBITDA of $62.2 million, up 15% from the $54.0 million reported in second quarter 2011.
  • Reported Distributable Cash Flow of $36.1 million, an increase of approximately 17% as compared to the $31.0 million reported in second quarter 2011.
  • Announced a quarterly distribution with respect to the third quarter of 2011 of $0.20 per common unit, an approximate 7% increase from the $0.1875 per common unit paid for the second quarter of 2011.
  • Reported Net Income of $97.4 million, up 77% as compared to the $55.1 million reported for the second quarter of 2011; the increase was driven primarily by unrealized mark-to-market gains on the Partnership's commodity derivative portfolio.

Other notable activities of the Partnership during the third quarter of 2011 included the following:

  • Announced the intention to install a recently acquired 60 MMcf/d high efficiency cryogenic processing facility (the Woodall Plant) in Hemphill County, Texas in the first quarter of 2012 to service production from the Granite Wash play.
  • Secured a substantial increase in committed natural gas liquids transportation and fractionation capacity out of the Texas Panhandle to support additional volumes from the Phoenix-Arrington Ranch Plant expansion and the new Woodall Plant.
  • Received proceeds of $32.3 million from the exercise of 5.4 million warrants on August 15, 2011. The Partnership used the proceeds to repay outstanding borrowings under its revolving credit facility.

"We are pleased with our third quarter results," said Joseph A. Mills, Eagle Rock's Chairman and Chief Executive Officer. "Both of our lines of business performed well during the third quarter despite the volatility in commodity prices. In our Upstream Business, we remain focused on developing our extensive inventory of drilling opportunities in the Golden Trend and the Cana Shale. In our Midstream Business, we continue to demonstrate our commitment to our producer customers by expanding our processing capacity to meet their growing needs. We have completed the Phoenix-Arrington Ranch Plant expansion and are scheduled to have our Woodall and Wheeler Plants online in the Granite Wash play of the Texas Panhandle in 2012."

Recent Announcements

On October 31, 2011, the Partnership announced its intention to install a 125 MMcf/d high efficiency cryogenic processing plant in Wheeler County, Texas, in the heart of the prolific Granite Wash play. The Partnership expects the installation of the new processing plant (to be named the "Wheeler Plant") and the construction of the associated infrastructure to be completed early in the fourth quarter of 2012. Eagle Rock also announced that construction of the 30 MMcf/d expansion of its Phoenix-Arrington Ranch Plant in Hemphill County, Texas is complete. Following the installation of the Woodall and Wheeler plants in 2012, the Partnership will have over 300 MMcf/d of high efficiency processing capacity serving its producer customers in the Granite Wash play of the Texas Panhandle.

On October 4, 2011, the Partnership announced a 6% increase in the upstream component of the borrowing base under its senior secured credit facility, from $353 million to $375 million. Total commitments under the credit facility remained unchanged at $675 million.

Third-Quarter 2011 Financial and Operating Results

Eagle Rock analyzes and manages its operations under six segments: four segments in its Midstream Business - the Texas Panhandle, East Texas/Louisiana, South Texas and Gulf of Mexico Segments - and the Upstream and Corporate and Other Segments. The Corporate and Other Segment includes the Partnership's general and administrative expenses, commodity risk management portfolio, and other corporate activities. The following discussion of Eagle Rock's operating income by business segment compares the Partnership's financial results in the third quarter of 2011 to those of the second quarter of 2011. 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 2010. Please refer to the financial tables at the end of this release for further detailed information. In comparing the Partnership's third quarter 2011 financial results against prior periods, including those presented for comparison only in the financial tables at the end of this release, note that all historical financial results for the Partnership's Minerals Business, which was sold during the second quarter of 2010, and a small, non-core gathering system accounted for in the Partnership's South Texas Segment, which was sold in the second quarter of 2011, have been removed from the operating financial results and are reflected in Discontinued Operations.

Midstream Business - Operating income from continuing operations for the Midstream Business, excluding the impact of impairments, in the third quarter of 2011 decreased by approximately $3.0 million compared to the second quarter of 2011. The primary reason for this decrease was lower average realized commodity prices and a 3% decrease in gas gathering volumes as compared to the second quarter of 2011. These factors more than offset the positive impact of an 11% increase in combined natural gas liquid ("NGL") and condensate equity volumes in the third quarter.

In the Texas Panhandle, gathered volumes were up approximately 6%, with combined equity NGL and condensate volumes up approximately 16%, as compared to the second quarter of 2011. Increased gathering volumes are primarily a result of an increase in drilling activity in the Partnership's East Panhandle system serving the Granite Wash play. Combined equity NGL and condensate volumes were higher in the third quarter due to curtailed customer production and reduced NGL recoveries in the second quarter resulting from damage at the Partnership's Cargray plant due to the severe weather in the first quarter. The Cargray plant was repaired in late June and is now performing consistent with its prior operating performance.

In East Texas/Louisiana, gathered volumes were down approximately 10% and combined equity NGL and condensate volumes were down approximately 7%, compared to the second quarter of 2011. The decrease in gathered volumes and combined equity NGL and condensate volumes were due to natural declines in the production of the existing wells and delays due to certain mechanical and completion difficulties experienced by the Partnership's producer customers during the quarter.

In South Texas, gathered volumes were down approximately 2 MMcf/d due to natural production declines. Combined equity NGL and condensate volumes remained minimal in the third quarter due to the low liquid content in the natural gas gathered by the Partnership's South Texas gathering systems.

In the Gulf of Mexico, gathered volumes were down approximately 2% and equity NGL volumes were down approximately 9%, as compared to the second quarter of 2011. Gathered volumes and equity NGL volumes were down as a result of the Partnership's ownership interest in the Yscloskey Plant decreasing (by virtue of an annual volume-based ownership adjustment mechanism) from approximately 11.5% to approximately 10.5%, effective September 1, 2011. In addition, the Yscloskey Plant was down for approximately two weeks due to scheduled maintenance during the month of September.

Upstream Business - Operating income for Eagle Rock's Upstream Business in the third quarter of 2011, excluding the impact of impairments, increased by $1.6 million, or approximately 6%, compared to the second quarter of 2011. The increase was primarily attributable to the full quarter of production from the Mid-Continent assets which Eagle Rock acquired on May 3, 2011. Production volumes in the Upstream Business averaged 81.1 MMcfe/d during the quarter, an increase of approximately 24% over the second quarter of 2011. In addition to the increase in production volumes, the Partnership also benefited from higher realized natural gas and sulfur prices, as well as lower unit operating costs, as compared to the second quarter of 2011. These positive factors were partially offset by an 8% and 10% decrease in realized oil and NGL prices, respectively.

In addition, the Partnership completed a nine day turnaround at its Big Escambia Creek facility in September. The total impact lowered operating income during the third quarter by approximately $3 million.

Corporate Segment - The Partnership recorded a realized commodity derivative settlement net loss of $2.7 million in the third quarter of 2011, as compared to a realized net loss of $8.8 million in the second quarter of 2011. The net loss was lower in the third quarter primarily due to lower crude oil, condensate and NGL settlement prices during the third quarter of 2011, as compared to the second quarter of 2011.

Total revenue for the third quarter of 2011, including the impact of Eagle Rock's realized and unrealized commodity derivative gains and losses, was $375.8 million, up 21% compared with the $311.7 million reported for the second quarter of 2011. The increase in revenue was primarily due to higher unrealized gains on commodity derivatives compared to the second quarter of 2011. Eagle Rock recorded an unrealized gain on commodity derivatives of $97.0 million in the third quarter 2011, as compared to an unrealized gain on commodity derivatives of $43.2 million in the second quarter 2011. The unrealized gain on commodity derivatives is a non-cash, mark-to-market amount which includes the amortization of commodity hedging costs.

Adjusted EBITDA was $62.2 million and Distributable Cash Flow was $36.1 million for the third quarter of 2011. The Partnership's distribution of $0.20 per common unit with respect to the third quarter of 2011 will be paid on Monday, November 14, 2011 to the Partnership's common unitholders of record as of the close of business on Monday, November 7, 2011, excluding unitholders of record with respect to 1,257,565 restricted common units granted on November 1, 2011 pursuant to the Partnership's Long Term Incentive Plan.

Update Regarding Distribution Policy

As previously stated, management anticipates recommending to the Board of Directors further increases in the distribution in 2011 and 2012, with the expectation and objective of reaching an annualized distribution rate of $1.00 per unit by the end of 2012.

Management's intentions around future distribution recommendations are subject to change, however, should factors affecting the general business climate, market conditions, commodity prices, the Partnership's specific operations, performance of the Partnership's underlying assets, applicable regulatory mandates, or the Partnership's ability to consummate accretive growth projects differ from current expectations.

Actual future distributions will be determined, declared and paid at the discretion of the Board of Directors.

Capitalization and Liquidity Update

Total debt outstanding as of September 30, 2011 was $741 million. As of September 30, 2011 the debt outstanding under the Partnership's senior unsecured notes was $297.9 million net of an unamortized debt discount of $2.1 million. Total debt outstanding as of September 30, 2011 under the Partnership's senior secured credit facility was $443 million, a decrease of $5.0 million from the amount outstanding at the end of the second quarter of 2011. The Partnership's overall liquidity position in the quarter benefited from $32.3 million of proceeds received from the exercise of 5,390,384 warrants on August 15, 2011.

The Partnership is in compliance with its financial covenants and has no maturities under its credit facility until June 2016. 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, 2011, the Partnership had approximately $228 million of availability under the credit facility, based on its outstanding commitments.

Capital Expenditures

In its 2011 capital budget, which excludes capital expenditures that were part of satisfying the purchase price for the Partnership's Mid-Continent assets acquired May 3, 2011 (but which includes capital expenditures on such assets after May 3, 2011), the Partnership estimates it will spend a total of approximately $196 million in 2011 on capital expenditures, including approximately $40 million related to the installation of the Woodall Plant. 

The Partnership expects its capital expenditures to increase in response to environmental compliance associated with sulfur dioxide (SO2) emissions. The Partnership has certain permit obligations to lower its SO2 emissions at its Alabama plant operations. Additionally, in mid-2010, the Environmental Protection Agency ("EPA") enacted new National Ambient Air Quality Standards ("2010 NAAQS") which substantially lowered the emissions limits for SO2 and mandated timelines for compliance. In order to fulfill its permit obligations, comply with the new 2010 NAAQS requirements and replace and upgrade certain aging assets in the Partnership's Alabama facilities, the Partnership expects to incur approximately $50 million over the next several years to enhance its SO2 recovery capabilities at its Alabama operations. The expected facility upgrades to Eagle Rock's Alabama operations should not only increase the marketable sulfur recovered from the inlet gas stream, but also are anticipated to reduce plant fuel consumption, improve the plant's operating reliability and extend the plant's operating life. Management does not anticipate, however, that the required spending will generate returns consistent with the Partnership's internal rate of return thresholds for discretionary capital investment. 

Management expects a substantial percentage of the total capital invested to achieve the SO2 emissions standard at the Partnership's Alabama operations will be classified as maintenance capital, and therefore will reduce the amount of distributable cash flow Eagle Rock recognizes in the periods in which the capital is spent. Management, based on its current expectations, does not believe the additional maintenance capital will impact its objective of recommending a distribution at an annualized rate of $1.00 per common unit by the end of 2012; it will, however, reduce the Partnership's distribution coverage ratio in the periods in which the capital is spent.

Hedging Update

On October 17 and 20, 2011, the Partnership entered into the hedges outlined below to replace a portion of its 2012 "proxy hedges" (where one commodity is hedged with a closely-correlated commodity) with direct NGL product hedges.

NYMEX WTI Crude to Direct NGL Product Hedges:

 

Product / (Type) Quantity Price   Term
WTI Crude
(Swap Unwind)
(7,800)
 Bbls/month
  $97.42     Cal. 2012
WTI Crude
(Remaining Swap)
12,200
Bbls/month
  $103.31     Cal. 2012

Note: Proceeds from unwind rolled into strike price on remaining volumes. 

Product / (Type) Quantity Price   Term
OPIS Propane
(Swap)
961,800
 Gallons/month
  $1.3425     Cal. 2012
OPIS IsoButane
(Swap)
310,800
Gallons/month
  $1.7700     Cal. 2012
OPIS Normal Butane
(Swap)
453,600
Gallons/month
  $1.6700     Cal. 2012
OPIS Natural Gasoline (Swap) 252,000
Gallons/month
  $2.1900     Cal. 2012

NYMEX Henry Hub Natural Gas to Direct Ethane Hedges:

Product / (Type) Quantity Price   Term
Natural Gas
(Swap Offset)
(260,000)
MMbtu/month
  $3.965     Jan-Jun
2012
OPIS Ethane
(Swap)
3,150,000
Gallons/month
  $0.7300     Jan-Jun
2012

Note: Natural gas transaction offsets an existing hedge with the same counterparty.

As a result of the hedges outlined above:

  • Approximately 78% of Eagle Rock's expected 2012 heavy NGL (C3+) exposure is hedged directly by specific product.
  • Approximately 35% of Eagle Rock's expected 2012 ethane exposure is hedged directly.

Note the preceding hedge discussion excludes the derivative activity associated with the Partnership's natural gas marketing and trading subsidiary. 

For more details regarding these hedging transactions and the Partnership's overall hedging portfolio, please visit Eagle Rock's website at www.eaglerockenergy.com under the Investor Relations tab, Presentations, Commodity Hedging Update. 

Conference Call

Eagle Rock will hold a conference call to discuss its third quarter 2011 financial and operating results on November 3, 2011 at 2:00 p.m. Eastern Time (1:00 p.m. Central Time).

Interested parties may listen live over the internet or via telephone. To listen live over the internet, log on to the Partnership's web site at www.eaglerockenergy.com. To participate by telephone, the call-in number is 888-680-0860, confirmation code 57796110. Investors are advised to dial into the call at least 15 minutes prior to the call to register. Participants may pre-register for the call by using the following link: https://www.theconferencingservice.com/prereg/key.process?key=PV3689JCR. Interested parties can also view important information about the Partnership's conference call by following this link. Pre-registering is not mandatory but is recommended as it will provide you immediate entry to the call and will facilitate the timely start of the call. Pre-registration only takes a few minutes and you may pre-register at any time, including up to and after the start of the call. An audio replay of the conference call will also be available for thirty days by dialing 888-286-8010, confirmation code 88780783. In addition, a replay of the audio webcast will be available by accessing the Partnership's website after the call is concluded.

About the Partnership

The Partnership is a growth-oriented master limited partnership engaged in two businesses: a) midstream, which includes (i) gathering, compressing, treating, processing and transporting natural gas; (ii) fractionating and transporting natural gas liquids; and (iii) marketing and trading natural gas, and marketing condensate and NGLs; and b) upstream, which includes acquiring, exploiting, developing, and producing hydrocarbons in oil and natural gas properties. Its corporate office is located in Houston, Texas.

References to "Board of Directors" are to the board of directors of Eagle Rock Energy G&P, LLC, the general partner of Eagle Rock Energy GP, L.P., the general partner of Eagle Rock Energy Partners, L.P.

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 our equity-based compensation program; unrealized (gains) losses on commodity and interest rate risk management related instruments; (gains) losses on discontinued operations and other (income) expense.

Eagle Rock uses Adjusted EBITDA as a measure of its core profitability to assess the financial performance of its assets. Adjusted EBITDA also is used as a supplemental financial measure by external users of Eagle Rock's financial statements such as investors, commercial banks and research analysts. For example, the Partnership's lenders under its revolving credit facility use a variant of its Adjusted EBITDA in a compliance covenant designed to measure the viability of Eagle Rock and its ability to perform under the terms of the revolving credit facility; Eagle Rock, therefore, uses Adjusted EBITDA to measure its compliance with its revolving credit facility. Eagle Rock believes that investors benefit from having access to the same financial measures that its management uses in evaluating performance. Adjusted EBITDA is 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 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 natural gas supply; the availability of local, intrastate and interstate transportation systems and other facilities to transport 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, 2010 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 Statements of Operations
($ in thousands)
(unaudited)
           
           
       
  Three Months
Ended September 30,
Nine Months
Ended September 30,
Three
Months
Ended June 
  2011 2010 2011 2010  30, 2011
           
REVENUE:          
Natural gas, natural gas liquids, oil, condensate and sulfur sales  $ 269,790  $ 159,303  $ 738,162  $ 516,276  $ 265,317
Gathering, compression, processing and treating fees  11,567  12,093  37,116  40,806  12,304
Unrealized commodity derivative gains (losses)  97,011  (17,044)  86,164  37,839  43,151
Realized commodity derivative losses  (2,698)  (1,535)  (17,958)  (10,031)  (8,813)
Other revenue  141  100  1,406  (115)  (244)
Total revenue  375,811  152,917  844,890  584,775  311,715
           
COSTS AND EXPENSES:          
Cost of natural gas and natural gas liquids  171,964  106,682  491,957  353,227  172,674
Operations and maintenance  24,897  18,714  66,323  57,511  21,951
Taxes other than income  4,556  2,609  13,061  8,949  5,189
General and administrative  16,068  10,674  43,746  36,491  15,902
Other operating income  --   --   (2,893)  --   (2,893)
Impairment  9,870  3,432  14,754  6,562  4,560
Depreciation, depletion and amortization  35,040  25,892  90,314  80,805  31,576
Total costs and expenses  262,395  168,003  717,262  543,545  248,959
OPERATING INCOME (LOSS)  113,416  (15,086)  127,628  41,230  62,756
OTHER INCOME (EXPENSE):          
Interest income  7  9  13  184  3
Interest expense, net  (10,057)  (3,258)  (19,592)  (12,056)  (6,311)
Realized interest rate derivative losses  (3,713)  (5,170)  (13,374)  (15,012)  (4,434)
Unrealized interest rate derivative (losses) gains  (3,165)  (3,112)  2,191  (12,288)  2,791
Other (expense) income  (3)  (30)  (167)  48  (114)
Total other income (expense)  (16,931)  (11,561)  (30,929)  (39,124)  (8,065)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES  96,485  (26,647)  96,699  2,106  54,691
INCOME TAX BENEFIT  (1,077)  (1,244)  (1,810)  (970)  (691)
INCOME (LOSS) FROM CONTINUING OPERATIONS  97,562  (25,403)  98,509  3,076  55,382
DISCONTINUED OPERATIONS, NET OF TAX  (197)  166  210  43,811  (311)
NET INCOME (LOSS)  $ 97,365  $ (25,237)  $ 98,719  $ 46,887  $ 55,071
 
 
Eagle Rock Energy Partners, L.P.
Consolidated Balance Sheets
($ in thousands)
(unaudited)
     
     
     
  September 30,
2011
December 31,
2010
ASSETS    
CURRENT ASSETS:    
Cash and cash equivalents  $ 17,662  $ 4,049
Accounts receivable  93,434  75,695
Risk management assets  18,577  -- 
Prepayments and other current assets  5,943  2,498
Assets held for sale  --   8,615
Total current assets  135,616  90,857
PROPERTY, PLANT AND EQUIPMENT - Net  1,716,875  1,137,239
INTANGIBLE ASSETS - Net  111,264  113,634
DEFERRED TAX ASSET  1,765  1,969
RISK MANAGEMENT ASSETS  38,568  1,075
OTHER ASSETS  21,043  4,623
TOTAL ASSETS  $ 2,025,131  $ 1,349,397
     
LIABILITIES AND MEMBERS' EQUITY    
CURRENT LIABILITIES:    
Accounts payable  $ 135,311  $ 91,886
Due to affiliate  41  56
Accrued liabilities  21,843  10,940
Taxes payable  707  1,102
Risk management liabilities  4,073  39,350
Liabilities held for sale  --  1,705
Total current liabilities $161,975 $145,039
LONG-TERM DEBT  740,904  530,000
ASSET RETIREMENT OBLIGATIONS  30,303  24,711
DEFERRED TAX LIABILITY  38,444  38,662
RISK MANAGEMENT LIABILITIES  4,594  31,005
OTHER LONG TERM LIABILITIES  2,473  867
       
MEMBERS' EQUITY  2,025,131  579,113
TOTAL LIABILITIES AND MEMBERS' EQUITY  $ 2,024,725  $ 1,349,397
 
 
Eagle Rock Energy Partners, L.P.
Segment Summary
Operating Income
($ in thousands)
(unaudited)
           
           
       
  Three Months
Ended September 30,
Nine Months
Ended September 30,
 Three
Months
Ended June
  2011 2010 2011 2010 30, 2011
           
Midstream          
Revenues:          
Natural gas, natural gas liquids, oil and condensate sales (1)  $ 223,594  $ 136,665  $ 634,940  $ 446,477  $ 225,749
Gathering and treating services  11,567  12,093  37,116  40,806  12,304
Total revenue  234,759  148,758  672,056  487,283  238,053
Cost of natural gas, natural gas liquids, oil and condensate (2)  186,120  106,682  527,507  353,227  186,577
Operating costs and expenses:          
Operations and maintenance  16,716  14,401  48,081  41,507  16,580
Impairment  --   --   4,560  3,130  4,560
Depreciation, depletion and amortization  16,093  18,683  48,250  55,138  16,076
Total operating costs and expenses  32,809  33,084  100,891  99,775  37,216
Operating income from continuing operations  15,830  8,992  43,658  34,281  14,260
Discontinued Operations (3)  (197)  (15)  (194)  363  (449)
Operating income  $ 15,633  $ 8,977  $ 43,464  $ 34,644  $ 13,811
           
Upstream          
Revenue          
Oil and condensate sales (4)  $ 24,720  $ 14,292  $ 63,774  $ 37,654  $ 24,193
Natural gas sales (5)  17,417  2,617  32,697  11,982  11,886
Natural gas liquids sales (6)  12,186  4,231  29,678  15,485  11,826
Sulfur sales (7)  5,057  1,498  12,781  4,678  4,684
Other  141  100  1,406  (115)  (244)
Total revenue  59,521  22,738  140,336  69,684  52,345
Operating costs and expenses:          
Operations and maintenance (3)  12,737  6,922  31,369  24,224  10,584
Sulfur disposal costs  --   --   --   729  -- 
Impairment  9,870  3,432  10,194  3,432  -- 
Depreciation, depletion and amortization  18,636  6,810  41,046  24,433  15,180
Total operating costs and expenses  41,243  17,164  82,609  52,818  25,764
Operating income  $ 18,278  $ 5,574  $ 57,727  $ 16,866  $ 26,581
           
Corporate and Other          
Revenues:          
Unrealized commodity derivative gains (losses)  $ 97,011  $ (17,044)  $ 86,164  $ 37,839  $ 43,151
Realized commodity derivative losses  (2,698)  (1,535)  (17,958)  (10,031)  (8,813)
Intersegment elimination - Sales of natural gas, oil and condensate  (13,184)  --   (35,708)  --   (13,021)
Total revenue  81,129  (18,579)  32,498  27,808  21,317
Costs and expenses          
Intersegment elimination - Cost of natural gas, oil and condensate  (14,558)  --   (35,550)  --   (13,903)
General and administrative  16,068  10,674  43,746  36,491  15,902
Intersegment elimination - Operations and maintenance  --   --   (66)  --   (24)
Other operating Income  --   --   (2,893)  --   (2,893)
Depreciation, depletion and amortization  311  399  1,018  1,234  320
Operating income (loss)  $ 79,308  $ (29,652)  $ 26,243  $ (9,917)  $ 21,915
           
(1) Includes sales of natural gas between Midstream Segments of $4,330  for both of the three and nine months ended September 30, 2011.          
(2) Includes purchases of natural gas between Midstream Segments of $4,330 and purchases of natural gas, oil and condensate from the Upstream Segment of $10,228 and $31,220  for the three and nine months ended September 30, 2011, respectively, and $13,903 for the three months ended June 30, 2011.          
(3) Includes natural gas sales of $66 and $24 from the South Texas Segment to the Upstream Segment for the nine months ended September 30, 2011 and the three months ended June 30, 2011, respectively.          
(4) Includes sales of oil and condensate to the Texas Panhandle Segment of $13,184 and $35,708 for the three and nine months ended September 30, 2011, respectively, and $13,021 for the three months ended June 30, 2011.          
(5)  Revenues include a change in the value of product imbalances of $(38), $22,  $(48) and $519 for the three and nine months ended September 30, 2011 and 2010, respectively, and $53 for the three months ended June 30, 2011.          
(6)  Revenues include a change in the value of product imbalances of $270, $(81), $155 and $(81) for the three and nine months ended September 30, 2011 and 2010, respectively, and $(195) for the three months ended June 30, 2011.          
(7) Revenues include a change in the value of product imbalances of $(125), $27, $(54) and $27 for the three and nine months ended September 30, 2011 and 2010, respectively, and $66 for the three months ended June 30, 2011.           
           
Eagle Rock Energy Partners, L.P.  
Midstream Segment  
Operating Income  
($ in thousands)  
(unaudited)  
           
  Three Months Nine Months Three Months
  Ended September 30, Ended September 30, Ended 
  2011 2010 2011 2010 June 30, 2011
           
Texas Panhandle          
Revenues:          
Natural gas, natural gas liquids, oil and condensate sales  $ 159,674  $ 78,905  $ 436,825  $ 250,593  $ 156,073
Gathering, compression, processing and treating services  4,892  2,821  12,905  8,811  4,227
Total revenue  164,566  81,726  449,730  259,404  160,300
Cost of natural gas, natural gas liquids, oil and condensate (1)  129,986  54,783  351,305  176,485  125,391
Operating costs and expenses:          
Operations and maintenance  10,828  9,155  31,436  25,666  11,207
Impairment  --   --   4,560  --   4,560
Depreciation, depletion and amortization  9,145  11,702  27,382  34,931  9,116
Total operating costs and expenses  19,973  20,857  63,378  60,597  24,883
Operating income  $ 14,607  $ 6,086  $ 35,047  $ 22,322  $ 10,026
           
East Texas/Louisiana          
Revenues:          
Natural gas, natural gas liquids, oil and condensate sales  $ 43,817  $ 37,352  $ 138,237  $ 127,816  $ 47,828
Gathering, compression, processing and treating services  6,123  8,854  22,517  29,532  7,813
Total revenue  49,940  46,206  160,754  157,348  55,641
Cost of natural gas and natural gas liquids  37,892  33,940  120,946  114,622  41,386
Operating costs and expenses:              
Operations and maintenance  4,990  4,502  14,193  12,921  4,651
Depreciation, depletion and amortization  4,589  4,631  13,706  13,171  4,561
Total operating costs and expenses  9,579  9,133  27,899  26,092  9,212
Operating income  $ 2,469  $ 3,133  $ 11,909  $ 16,634  $ 5,043
           
South Texas          
Revenues:          
Natural gas, natural gas liquids, oil and condensate sales  $ 11,042  $ 12,785  $ 32,186  $ 44,766  $ 11,151
Gathering, compression, processing and treating services  429  207  1,305  1,644  162
Total revenue  11,471  12,992  33,491  46,410  11,313
Cost of natural gas and natural gas liquids  10,910  11,321  31,544  41,624  10,714
Operating costs and expenses:          
Operations and maintenance  400  390  1,055  1,530  278
Impairment  --   --   --   3,130  -- 
Depreciation, depletion and amortization  735  699  2,208  2,215  735
Total operating costs and expenses  1,135  1,089  3,263  6,875  1,013
Operating (loss) income from continuing operations  (574)  582  (1,316)  (2,089)  (414)
Discontinued Operations (2)  (197)  (15)  (194)  363  (449)
Operating income (loss)  $ (771)  $ 567  $ (1,510)  $ (1,726)  $ (863)
           
Gulf of Mexico          
Revenues:          
Natural gas, natural gas liquids, oil and condensate sales  $ 9,061  $ 7,623  $ 27,692  $ 23,302  $ 10,697
Gathering, compression, processing and treating services  123  211  389  819  102
Total revenue  9,184  7,834  28,081  24,121  10,799
Cost of natural gas and natural gas liquids  7,734  6,638  23,712  20,496  9,086
Operating costs and expenses:            
Operations and maintenance  498  354  1,397  1,390  444
Depreciation, depletion and amortization  1,624  1,651  4,954  4,821  1,664
Total operating costs and expenses  2,122  2,005  6,351  6,211  2,108
Operating loss  $ (672)  $ (809)  $ (1,982)  $ (2,586)  $ (395)
           
(1) Includes purchases of natural gas between Midstream Segments of $4,330 and purchases of natural gas, oil and condensate from the Upstream Segment of $10,228 and $31,220 for the three and nine months ended September 30, 2011, respectively, and $13,903 for the three months ended June 30, 2011.          
(2) Includes sales of natural gas of $66 and $24 to the Upstream Segment for the nine months ended September 30, 2011 and the three months ended June 30, 2011, respectively.          
 
Eagle Rock Energy Partners, L.P.
Midstream Operations Information
(unaudited)
           
           
       
  Three Months
Ended September 30,
Nine Months
Ended September 30,
Three Months
Ended June
  2011 2010 2011 2010 30, 2011
           
Gas gathering volumes - (Average Mcf/d)          
Texas Panhandle  163,665  123,541  154,011  128,201  153,870
East Texas/Louisiana (1)  173,567  205,194  188,431  209,724  191,735
South Texas  25,170  39,792  29,423  54,347  27,221
Gulf of Mexico  113,365  101,473  113,150  100,560  115,581
Total  475,767  470,000  485,015  492,832  488,407
           
NGLs - (Net equity Bbls)          
Texas Panhandle  231,965  198,639  609,097  660,839  181,186
East Texas/Louisiana (1)  89,050  115,625  267,348  328,147  99,483
South Texas  1,248  1,483  3,393  5,994  1,069
Gulf of Mexico  23,981  27,995  74,514  77,961  26,373
Total  346,244  343,742  954,352  1,072,941  308,111
           
Condensate - (Net equity Bbls)          
Texas Panhandle  260,228  303,197  728,860  780,148  243,238
East Texas/Louisiana  10,364  9,457  34,382  29,070  6,939
South Texas  155  (588)  1,045  10,999  — 
Total  270,747  312,066  764,287  820,217  250,177
           
Natural gas short position - (Average MMbtu/d)          
Texas Panhandle  (7,418)  (4,776)  (5,517)  (5,405)  (360)
East Texas/Louisiana  523  317  1,129  949  1,717
South Texas  1,235  773  834  995  145
Total  (5,660)  (3,686)  (3,554)  (3,461)  1,502
           
Average realized NGL price - per Bbl          
Texas Panhandle  $ 53.39  $ 40.38  $ 55.28  $ 44.99  $ 58.27
East Texas/Louisiana  $ 50.94  $ 31.32  $ 48.94  $ 34.48  $ 53.23
South Texas  $ 58.64  $ 40.81  $ 53.41  $ 45.09  $ 55.37
Gulf of Mexico  $ 55.58  $ 43.52  $ 56.70  $ 45.31  $ 61.23
Weighted Average  $ 53.08  $ 37.74  $ 53.51  $ 42.15  $ 56.80
           
Average realized condensate price - per Bbl          
Texas Panhandle  $ 79.43  $ 60.82  $ 82.31  $ 64.81  $ 87.54
East Texas/Louisiana  $ 94.20  $ 79.15  $ 95.42  $ 75.91  $ 109.51
South Texas  $ 80.06  $ 67.24  $ 82.34  $ 74.56  $ -- 
Total  $ 79.74  $ 60.31  $ 83.31  $ 65.33  $ 88.80
           
Average realized natural gas price - per MMbtu          
Texas Panhandle  $ 3.86  $ 3.45  $ 3.95  $ 3.98  $ 4.00
East Texas/Louisiana  $ 4.43  $ 4.56  $ 4.55  $ 5.15  $ 4.61
South Texas  $ 4.21  $ 4.45  $ 4.15  $ 4.60  $ 4.26
Total  $ 4.05  $ 3.97  $ 4.14  $ 4.47  $ 4.18
           
(1) The Partnership changed the way it reports NGL and condensate volumes under certain contracts in its East Texas/Louisiana Segment. For the three and nine months ended September 30, 2011 and the three months ended June 30, 2011, volumes from Eagle Rock's Indian Springs plant, in which the Partnership owns 25%, are included in equity NGL and condensate volumes, as the Partnership believes including these volumes is more illustrative of current operating trends. In addition, volumes associated with a certain contract at the Partnership's Brookeland plant have been excluded from the three and nine months ended September 30, 2011 and three months ended June 30, 2011 due to a change in reporting methodology.          
           
 
 
Eagle Rock Energy Partners, L.P.
Upstream Operations Information
(unaudited)
           
           
       
  Three Months
Ended September 30,
Nine Months
Ended September 30,
Three  Months
Ended June
  2011 2010 2011 2010 30, 2011
           
Upstream          
Production:          
Oil and condensate (Bbl)  302,766  212,083  772,350  613,315  272,850
Gas (Mcf)  4,274,811 778,793  8,272,176 2,743,883  3,165,060
NGLs (Bbl)  227,614  102,967  533,223  355,470  206,251
Total Mcfe  7,457,091  2,669,093  16,105,615  8,556,593  6,039,672
           
Sulfur (long ton) (1)  27,706  17,622  71,509  69,929  25,268
           
Realized prices, excluding derivatives: (2)          
Oil and condensate (per Bbl) $81.65 $60.21 $82.57 $60.98 $88.67
Gas (Mcf) $4.08 $4.30 $3.95 $4.54 $3.74
NGLs (Bbl) $52.35 $41.92 $55.37 $45.70 $58.29
Sulfur (long ton) (1) $187.03 $80.54 $179.48 $75.38 $182.73
           
Operating statistics:          
Operating costs per Mcfe (incl production taxes) (3) $1.48 $2.59 $1.84 $2.83 $1.75
Operating costs per Mcfe (excl production taxes) (3) $0.98 $1.93 $1.19 $2.08 $1.04
Operating income per Mcfe $2.45 $2.09 $3.58 $1.97 $4.40
           
Drilling program (gross wells):          
Development wells  13  3  31  6  18
Completions  13  2  31  5  18
Workovers  5  6  14  13  7
Recompletions  4  5  5  11  1
           
(1) During the three months ended March 31, 2010, an adjustment was made to decrease sulfur volumes by 5,230 long tons related to a prior period adjustment. This adjustment is excluded from the calculation of realized prices.          
(2)  Calculation does not include impact of product imbalances.          
(3)  Excludes sulfur disposal costs of  $729 the nine months ended September 30, 2010 and excludes post-production costs of $1,683 for both the three and nine months ended September 30, 2011, and $63 and $(383) for the three and nine months ended September 30, 2010, respectively.          
           
           

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 September 30,
Nine Months
Ended September 30,
Three Months
Ended June
  2011 2010 2011 2010 30, 2011
Net (loss) income to Adjusted EBITDA          
Net (loss) income, as reported  $ 97,365  $ (25,237)  $ 98,719  $ 46,887  $ 55,071
Depreciation, depletion and amortization  35,040  25,892  90,314  80,805  31,576
Impairment  9,870  3,432  14,754  6,562  4,560
Risk management interest related instruments - unrealized  3,165  3,112  (2,191)  12,288  (2,791)
Risk management commodity related instruments - unrealized, including
amortization of commodity derivative costs
 (97,011)  17,044  (86,164)  (37,839)  (43,151)
Other Operating Income  --  --  (2,893)  --  (2,893)
Non-cash mark-to-market of Upstream product imbalances  (107)  102  (123)  (465)  76
Unrealized gains from Eagle Rock Gas Services  (538)  --  (538)  --  --
Restricted units non-cash amortization expense  1,507  1,294  3,441  4,652  1,024
Income tax (benefit) provision  (1,077)  (1,244)  (1,810)  (970)  (691)
Interest - net including realized risk management instruments and other expense $13,766 $8,470 $33,120 $26,935 $10,856
Other income  --  (21)  --  (99)  --
Discontinued operations  197  (166)  (210)  (43,811)  311
Adjusted EBITDA  $ 62,177  $ 32,678  $ 146,419  $ 94,945  $ 53,948
           
Net (loss) income to Distributable Cash Flow          
Net (loss) income, as reported $97,365 ($25,237) $98,719 $46,887 $55,071
Depreciation, depletion and amortization expense  35,040  25,892  90,314  82,550  31,576
Impairment  9,870  3,432  14,754  6,562  4,560
Risk management interest related instruments-unrealized  3,165  3,112  (2,191)  12,288  (2,791)
Risk management commodity related instruments - unrealized, including
amortization of commodity derivative costs
 (97,549)  17,044  (86,702)  (37,839)  (43,151)
Capital expenditures-maintenance related ($11,980) ($7,903) ($30,311) ($19,970) ($11,874)
Non-cash mark-to-market of Upstream product imbalances  (107)  102  (123)  (465)  76
Restricted units non-cash amortization expense  1,507  1,294  3,441  4,652  1,024
Other Operating Income  --  --  (2,893)  --  (2,893)
Income tax (benefit) provision  (1,077)  (1,244)  (1,810)  (940)  (691)
Other income  --  (21)  --  (99)  --
Cash income taxes  (325)  376  (802)  (605)  (268)
Discontinued operations  197  (166)  (210)  (43,811)  311
Distributable Cash Flow $36,106 $16,681 $82,186 $49,210 $30,950
           
Supplemental Information      
($ in thousands)      
        
  Three Months
Ended September 30,
 Nine Months 
Ended September 30,
Three Months
Ended June
  2011 2010 2011 2010  30, 2011
Amortization of commodity derivative costs  $ --   $ 437  $ --   $ 3,515  $ -- 


            

Coordonnées