updated 3/10/2011 7:16:46 AM ET 2011-03-10T12:16:46

HOUSTON, March 9, 2011 (GLOBE NEWSWIRE) -- Eagle Rock Energy Partners, L.P. ("Eagle Rock" or the "Partnership") (Nasdaq:EROC) today announced its unaudited financial results for the full-year and three months ended December 31, 2010. Financial highlights with respect to fourth-quarter 2010 included the following (all current and historical financial results for the Partnership's Minerals Business, which was sold during the second quarter of 2010, have been removed from the operating financial results and are reflected in Discontinued Operations):

  • Reported Adjusted EBITDA of $31.7 million, down from the $33.2 million reported in third-quarter 2010.
  • Reported Distributable Cash Flow of $18.1 million, an increase of approximately 5% as compared to the $17.2 million reported in third-quarter 2010.
  • Reported a net loss of $52.2 million, primarily attributable to unrealized commodity derivative losses and impairments totaling $55.9 million.
  • Paid a quarterly distribution with respect to the fourth quarter of 2010 of $0.15 per common unit, an increase of $0.125 per common unit over the distribution paid with respect to third-quarter 2010, with a distribution coverage ratio of approximately 1.4x; management has announced its objective and expectation of reaching an annualized distribution rate of $0.75 per unit commencing with respect to the fourth quarter of 2011 (payable in February 2012).
  • Announced that the borrowing base under the Partnership's senior secured credit facility had been increased to $140 million from its previous level of $130 million as part of Eagle Rock's regularly scheduled semi-annual borrowing base redetermination.

Other notable operational events impacting the fourth quarter of 2010 include the following:

  • Announced and closed the acquisition of 200 miles of complementary gathering systems in Texas Panhandle and the acquisition of additional interests in the Partnership's Big Escambia Creek Field; the two transactions totaled approximately $31 million.
  • Announced start-up of commercial operations of the Partnership's Phoenix Plant located in Roberts County in Texas Panhandle.
  • Approximately one quarter of the Partnership's total upstream production was shut-in for the entire quarter due to an unscheduled shutdown of a third-party owned and operated processing facility which negatively impacted the Partnership's financial results for the quarter. The Partnership recovered and recorded $3.0 million under its contingent business interruption insurance policy during the quarter.

For the full-year 2010, Eagle Rock generated $128.7 million of Adjusted EBITDA, a decrease of 26% from the $174.5 million reported for the full-year 2009. Realized commodity derivative gains contributed approximately $83.3 million to full-year 2009 Adjusted EBITDA, while realized commodity derivative losses reduced full-year 2010 Adjusted EBITDA by approximately $17.0 million. Without this impact, Adjusted EBITDA would have increased by $54.5 million, or 60%, from full-year 2009 to full-year 2010, which was largely driven by increases in the underlying commodity prices.

"The fourth quarter marked our return to growing the business after completing the restructuring of our capital and governance structure," said Joseph A. Mills, Eagle Rock's Chairman and Chief Executive Officer. "During the quarter, we closed two small but highly complementary acquisitions that strengthened several of our core operational areas."

Mr. Mills added, "As we look forward to 2011, we are excited about the numerous opportunities we see to capitalize on our core operational areas and to expand our operational and commercial reach. Our primary focus will be on growing the Partnership through organic growth projects and acquisitions that are accretive to our distributable cash flow per unit."

Recent Acquisitions

The Partnership acquired certain natural gas gathering systems and related facilities located primarily in Wheeler and Hemphill Counties in the Texas Panhandle from Centerpoint Energy Field Services, Inc. (the "East Hemphill Acquisition"). The purchase price for the assets was approximately $27 million, subject to post-closing adjustments. The East Hemphill Acquisition closed on October 19, 2010, with an effective date of October 1, 2010. The acquired assets include over 200 miles of gathering pipeline and related compression and dehydration facilities, together with gas gathering contracts, rights of way and other intangible assets. The assets are located in the core of the active and prolific Granite Wash play and are highly complementary to the Partnership's existing East Panhandle system and the newly installed and commissioned Phoenix processing plant.

In addition, Eagle Rock acquired additional working and net revenue interests in wells located in the Big Escambia Creek Field and the nearby Flomaton and Fanny Church Fields, located in Escambia County, Alabama, from Indigo Minerals, LLC, for $4.1 million, with an effective date of August 1, 2010 (the "BEC - Indigo Acquisition"). The acquisition closed on October 4, 2010, and these interests are in wells in which the Partnership currently owns a significant interest and are nearly 100% operated by the Partnership. The Partnership estimates that the interests acquired contain 411 MBoe of proved reserves, 87% of which are classified as proved developed producing. Currently, the daily production rate associated with the interests is 130 Boe/d.

Reminder Regarding Third Warrant Exercise Date

The third exercise date for Eagle Rock's outstanding warrants is March 15, 2011. A total of 21,557,164 warrants were issued in conjunction with the Eagle Rock rights offering which expired on June 30, 2010. The warrants have been trading on the NASDAQ Global Select Market since July 9, 2010 under the symbol "EROCW."

Each warrant entitles the holder to purchase one Eagle Rock common unit for $6.00 on certain specified days (March 15, May 15, August 15 and November 15, or on the first business day following such date if it is not a business day) through the expiration date of May 15, 2012. The method for exercising the warrants is set forth in the prospectus supplement the Partnership filed with the Securities and Exchange Commission on May 27, 2010.

This press release does not constitute an offer to sell or the solicitation of an offer to buy any securities, nor shall there be any sale of these securities in any state or jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such state or jurisdiction.

Update Regarding Distribution Policy

As previously disclosed, the Eagle Rock management team anticipates recommending to the Board of Directors increases in the quarterly distribution with the expectation and objective of reaching an annualized distribution rate of $0.75 per unit commencing with respect to the fourth quarter of 2011 (payable in February 2012).

Actual future changes in the distribution level, if any, will be driven by market conditions, future commodity prices, the Partnership's leverage levels, the performance of the Partnership's underlying assets and the Partnership's ability to consummate accretive growth projects or acquisitions.

Management's distribution recommendation is subject to change should factors affecting the general business climate or the Partnership's specific operations differ from current expectations. All actual distributions paid will be determined and declared at the discretion of the Eagle Rock board of directors.

Fourth-Quarter 2010 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 Segments. The Corporate Segment includes the Partnership's general and administrative expenses, derivatives 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 fourth quarter of 2010 to those of the third quarter of 2010. The Partnership believes comparing these periods is more illustrative of current operating trends than comparing the current quarter to results achieved in the fourth quarter of 2009. 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 fourth quarter of 2010 increased by $1.9 million, or 21%, compared to the third quarter of 2010. The primary reason for this increase was higher average realized prices for NGLs and condensate. Also contributing to the increase in operating income was a 10% increase in equity NGL volumes and a 2% increase in natural gas gathering volumes. These factors were partially offset by lower equity condensate volumes.

In the Texas Panhandle, gathered volumes were up 16%, with combined equity NGL and condensate volumes down less than 1%, compared to the third quarter of 2010. The increase in gathered volumes was primarily due to the addition of volumes from the East Hemphill system acquired on October 19, 2010, a portion of which is dry gas that does not require processing. Liquids volumes were down slightly, despite the increase in gathered volumes in the East Panhandle system, due to the natural production decline rates of the wells connected to our West Panhandle system. The wells in our West Panhandle system produce natural gas that contains a higher NGL content than the wells connected to our East Panhandle system.

In East Texas, gathered volumes were down 5%, with equity NGL and condensate volumes down 8%, compared to the third quarter of 2010. The volume decrease in this area was primarily due to natural decline curves on existing wells. Several new wells that were expected to mitigate this natural decline encountered permitting or water production issues which delayed bringing the gas and liquids production online during the quarter. These issues have now been resolved.

In South Texas, gathered volumes were down 26%, with equity NGL and condensate volumes up 69%, compared to the third quarter of 2010. Gathered volumes were down primarily due to the loss of a significant producer contract at the Partnership's Raymondville system in the middle of the third quarter of 2010 and decreased drilling activity in the fourth quarter of 2010. Equity NGL and condensate volumes increased substantially in the fourth quarter of 2010 due to "pigging" operations conducted in the South Texas Segment earlier in the year that flushed liquids and condensate from the pipelines. As a result, liquids volumes in the third quarter were artificially low as liquids built up in the pipelines during this period. Pigging operations resumed in the fourth quarter of 2010.

In the Gulf of Mexico, gathered volumes were up 12%, with equity NGL volumes down 4%. The increase in gathering volumes was primarily a result of increased drilling activity in the shallow water Gulf of Mexico in the fourth quarter of 2010. The natural gas received from the more recently-drilled wells, however, has been leaner (i.e., containing fewer natural gas liquids) than from the existing wells on the system, resulting in the decrease in our equity NGL volumes.

Upstream Business - Operating income for Eagle Rock's Upstream Business in the fourth quarter of 2010, excluding the impact of impairments, increased by $2.2 million, or 25%, compared to the third quarter of 2010. The increase was attributable to higher crude oil and condensate, NGLs and sulfur prices, and increased production associated with the BEC-Indigo Acquisition, as compared to the third quarter of 2010. This increase was partially offset by lower production from the Partnership's East Texas upstream assets during the quarter, as compared to the third quarter of 2010. Upstream production during the entire fourth quarter of 2010 was negatively impacted by the shut-in of the Partnership's East Texas oil, natural gas, NGL, and sulfur production due to an unscheduled shutdown of the Eustace processing facility owned and operated by Tristream Energy, LLC, ("Tristream"), the third party owner of the Eustace facility. As previously disclosed, the Eustace facility was shut down on August 11, 2010, due to significant damage to the facility's sulfur recovery unit. The Partnership estimates the shut-in negatively impacted net revenues in its Upstream Business in the fourth quarter by approximately $5.0 million and for the full-year 2010 by approximately $7.1 million. According to Tristream, all major repairs to the Eustace facility have been completed, and the plant should return to service in the coming days. Eagle Rock will continue to provide updates as to its East Texas production status as new information becomes available. The Partnership received recoveries of $3 million as a result of its contingent business interruption insurance in the fourth quarter of 2010, which was recorded as 'Other Revenue,' and is pursuing additional recoveries (subject to deductibles and an overall cap of $5 million) associated with its lost net revenues due to the shut-in of the Eustace facility.

Corporate Segment - Cash flow from realized commodity derivative settlements decreased by $5.4 million to a realized net loss of $7.0 million in fourth-quarter 2010, as compared to a realized net loss of $1.5 million in third-quarter 2010. This was primarily due to substantially higher oil, condensate and NGL prices at the index points where the Partnership's hedges settled during the fourth quarter of 2010. This decrease was partially offset by the higher weighted average strike price on Eagle Rock's crude oil hedges in the fourth quarter of 2010 ($70.52 per barrel) relative to $67.67 per barrel in the third quarter of 2010. The weighted average strike price on the Partnership's crude oil hedges for 2011 increases to $74.97 per barrel, which represents a 6.3% increase over the average strike price in the fourth quarter of 2010.

Total revenue for fourth-quarter 2010, including the impact of Eagle Rock's realized and unrealized derivative gains and losses, was $153.5 million, down 3% compared with $159.0 million reported for third-quarter 2010. The largest contributor to the decline in total revenue was the Partnership's unrealized loss on commodity derivatives. Eagle Rock recorded an unrealized loss on commodity derivatives of $29.6 million in fourth-quarter 2010, as compared to an unrealized loss on commodity derivatives of $17.0 million in third-quarter 2010. The unrealized gain (loss) on commodity derivatives is a non-cash, mark-to-market amount which includes the amortization of commodity hedging costs. Revenues associated with the sale of crude oil, natural gas, NGLs, condensate and sulfur were up 7% relative to the third quarter of 2010, driven by higher average realized crude oil, condensate, NGL and sulfur prices.

Adjusted EBITDA was $31.7 million and Distributable Cash Flow was $18.1 million for the fourth quarter of 2010. The Partnership's distribution of $0.15 per common unit with respect to the fourth quarter of 2010 was paid on Monday, February 14, 2011 to the Partnership's common unitholders of record as of the close of business on Monday, February 7, 2011. 

Full-Year 2010 Financial and Operating Results

Total revenue for 2010, including the impact of Eagle Rock's realized and unrealized derivative gains and losses, was $758.4 million, up 28% compared with $594.8 million reported for 2009. The largest contributor to the increase in total revenue was the Partnership's unrealized gain (loss) on commodity derivatives. Eagle Rock recorded an unrealized gain on commodity derivatives of $8.2 million in 2010, as compared to an unrealized loss on commodity derivatives of $189.6 million in 2009. Revenues associated with the sale of crude oil, natural gas, NGLs, condensate and sulfur were up 9% relative to those in 2009, driven by higher average realized commodity prices. 2010 revenues included a realized loss on commodity derivatives of $17.0 million, as compared to a realized gain of $83.3 million in 2009.

Adjusted EBITDA was $128.7 million and Distributable Cash Flow was $67.6 million in 2010 as compared to $174.5 million and $109.7 million, respectively, in 2009. The primary reason for these declines was a decrease in the Partnership's realized commodity derivative gains, which is accounted for in the Partnership's Corporate Segment. As noted above, the Partnership's realized commodity derivative settlements were down more than $100 million in 2010 as compared to in 2009.

With regard to the Partnership's Midstream operations, gas gathering volumes were down 15%, and combined NGL and condensate volumes were down 4%, as compared to those in 2009. However, these declines were more than offset by higher average realized prices for NGLs and condensate which were up 66% and 13%, respectively, as compared to commodity prices in 2009.

With regard to the Partnership's Upstream operations, total production was down 5% as compared to production in 2009 due to the shut-in of the Partnership's East Texas production beginning on August 11, 2010 and continuing through the end of the year. Without this impact, management estimates total production in 2010 would have increased by approximately 3% over 2009. The production decline was more than offset by higher realized commodity prices during 2010 versus 2009. 

Capitalization and Liquidity Update

Total debt outstanding under the Partnership's revolving credit facility as of December 31, 2010 was $530.0 million. Outstanding borrowings increased by $14.6 million during the fourth quarter due to the East Hemphill Acquisition and BEC - Indigo Acquisition. Since December 31, 2009, the Partnership has reduced its total debt outstanding under its revolving credit facility by $224.4 million.

As of December 31, 2010, the revolving credit facility had aggregate commitments of approximately $871 million after adjusting for the unfunded portion of Lehman Brothers' commitment. The Partnership is in compliance with its financial covenants and has no maturities under its credit facility until December 2012. Availability under the credit facility is a function of undrawn commitments and the limitations imposed by the borrowing base for the Upstream Business and traditional cash-flow based covenants for the Midstream Business. The borrowing base for the Upstream Business was $140 million for the fourth-quarter 2010.

Hedging Update

On November 29, 2010, the Partnership announced it had terminated certain of its crude oil proxy hedges related to the expected natural gas liquids production from its Midstream Business in 2011 and replaced them with direct natural gas liquids product hedges. As a result, approximately 51% of Eagle Rock's expected 2011 natural gas liquids production (propane and heavier) is hedged using direct product hedges. 

On December 20, 2010, the Partnership undertook several steps to reduce its exposure in 2011 to changes in ethane and natural gas prices. As a result of these actions, the Partnership estimates that its Upstream natural gas and ethane exposure is 84% hedged through natural gas hedges. With respect to its Midstream business, approximately 40% of its natural gas exposure and 47% of its ethane exposure has been hedged. All of its Midstream ethane hedges are direct product hedges.

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 fourth-quarter and full-year 2010 financial and operating results on Thursday, March 10, 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 888-679-8038, confirmation code 85531643. 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=PLAJVCAGV. 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 75069663. 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 natural gas, condensate and NGLs; b) upstream, which includes acquiring, exploiting, developing, and producing hydrocarbons in oil and natural gas properties. Its corporate office is located in Houston, Texas.

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 as 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: a) in our Midstream Business, capital expenditures made to replace partially or fully depreciated assets, to meet regulatory requirements, to maintain the existing operating capacity of our assets and extend their useful lives, or to connect wells to maintain existing system volumes and related cash flows; and b) in our Upstream Business, capital which is expended to maintain our production and cash flow levels in the near future.

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 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, 2009, and the Partnership's Forms 10-Q, filed with the SEC for subsequent quarters, as well as any other public filings, including, when filed, the Partnership's Form 10-K for the year ended December 31, 2010, and press releases.

Eagle Rock Energy Partners, L.P.
Consolidated Statement of Operations
($ in thousands)
(unaudited)
 
 

Three Months

Ended December 31,


Twelve Months Ending

December 31,
Three Months

Ended

September 30,
  2010 2009 2010 2009 2010
REVENUE:          
Natural gas, natural gas liquids, oil, condensate and sulfur sales $ 177,370 $ 185,123 $ 712,795 $ 653,712 $ 165,131
Gathering, compression, processing and treating fees 10,219 10,433 51,951 45,476 12,358
Unrealized commodity derivative gains (losses) (29,615) (62,022) 8,224 (189,590) (17,044)
Realized commodity derivative (losses) gains (6,979) 12,869 (17,010) 83,300 (1,535)
Other revenue 2,550 88 2,435 1,858 100
Total revenue 153,545 146,491 758,395 594,756 159,010
           
COSTS AND EXPENSES:          
Cost of natural gas and natural gas liquids 120,086 129,428 490,206 488,230 111,916
Operations and maintenance 19,262 18,572 77,898 73,196 19,037
Taxes other than income 3,279 2,948 12,240 10,766 2,613
General and administrative 9,284 11,020 45,775 45,819 10,674
Other operating (income) expenses (3,552)
Impairment 26,313 21,546 32,875 21,788 3,432
Depreciation, depletion and amortization 26,231 28,799 108,781 110,255 26,474
Total costs and expenses 204,455 212,313 767,775 746,502 174,146
OPERATING LOSS (50,910) (65,822) (9,380) (151,746) (15,136)
OTHER INCOME (EXPENSE):          
Interest income (73) 5 111 187 9
Other income 402 111 501 934 21
Interest expense, net (3,091) (4,309) (15,147) (21,591) (3,258)
Realized interest rate derivative losses (4,959) (5,207) (19,971) (18,876) (5,170)
Unrealized interest rate derivative (losses) gains 5,124 2,784 (7,164) 12,529 (3,112)
Other expense (269) (51) (1,070) (51)
Total other income (expense) (2,597) (6,885) (41,721) (27,887) (11,561)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (53,507) (72,707) (51,101) (179,633) (26,697)
INCOME TAX (BENEFIT) PROVISION (1,605) (504) (2,545) 1,022 (1,236)
LOSS FROM CONTINUING OPERATIONS (51,902) (72,203) (48,556) (180,655) (25,461)
DISCONTINUED OPERATIONS, NET OF TAX (334) 3,548 43,207 9,397 224
NET LOSS (52,236) (68,655) (5,349) (171,258) (25,237)
 
Eagle Rock Energy Partners, L.P.
Consolidated Balance Sheets
($ in thousands)
(unaudited)
 
  December 31, 2010 December 31, 2009
ASSETS    
CURRENT ASSETS:    
Cash and cash equivalents $ 4,049 $ 2,732
Accounts receivable 77,810 88,122
Risk management assets 2,847 2,479
Due from affiliates 490
Prepayments and other current assets 2,498 2,790
Assets held for sale 135,224
Total current assets 87,204 231,837
PROPERTY, PLANT AND EQUIPMENT - Net 1,143,459 1,155,733
INTANGIBLE ASSETS - Net 113,914 132,343
DEFERRED TAX ASSET 1,969 1,562
RISK MANAGEMENT ASSETS 3,292 3,410
OTHER ASSETS 4,623 9,933
TOTAL ASSETS $ 1,354,461 $ 1,534,818
     
LIABILITIES AND MEMBERS' EQUITY    
CURRENT LIABILITIES:    
Accounts payable $ 93,591 $ 91,286
Due to affiliate 56 60
Accrued liabilities 10,940 11,110
Taxes payable 1,102 2,416
Risk management liabilities 42,197 51,650
Liabilities held for sale 150
Total current liabilities 147,886 156,672
LONG-TERM DEBT 530,000 754,383
ASSET RETIREMENT OBLIGATIONS 24,711 19,829
DEFERRED TAX LIABILITY 38,662 40,246
RISK MANAGEMENT LIABILITIES 33,222 32,715
OTHER LONG TERM LIABILITIES 867 575
     
MEMBERS' EQUITY:    
Common Unitholders 579,113 484,282
Subordinated Unitholders 52,058
General Partner (5,942)
Total members' equity 579,113 530,398
TOTAL LIABILITIES AND MEMBERS' EQUITY $ 1,354,461 $ 1,534,818
 
Eagle Rock Energy Partners, L.P.
Segment Summary
Operating Income
($ in thousands)
(unaudited)
 
 

Three Months

Ended December 31,


Twelve Months Ending

December 31,
Three Months

Ended

September 30
  2010 2009 2010 2009 2010
Midstream          
Revenues:          
Natural gas, natural gas liquids, oil and condensate sales (1) $ 160,979 $ 164,335 $ 626,605 $ 590,318 $ 142,493
Gathering and treating services 10,219 10,433 51,951 45,476 12,358
Other revenue 1,619
Total revenue 171,198 174,768 678,556 637,413 154,851
Cost of natural gas, natural gas liquids, oil and condensate (2) 125,673 129,428 495,793 488,230 111,916
Operating costs and expenses:          
Operations and maintenance 14,770 12,800 57,414 55,426 14,728
Impairment 26,209 13,674 29,339 13,674
Depreciation, depletion and amortization 19,924 19,604 76,807 75,173 19,265
Total operating costs and expenses 60,903 46,078 163,560 144,273 33,993
Operating (loss) income from continuing operations (15,378) (738) 19,203 4,910 8,942
Discontinued Operations 14 24 77 290 35
Operating (loss) income $ (15,364) $ (714) $ 19,280 $ 5,200 $ 8,977
           
Upstream          
Revenue          
Oil and condensate sales (3) (4) $ 12,853 $ 9,943 $ 50,507 $ 35,316 $ 14,292
Natural gas sales (5) 3,045 4,940 15,027 12,021 2,617
Natural gas liquids sales (6) 4,488 5,905 19,973 16,057 4,231
Sulfur sales (7) 2,115 6,793 1,498
Other 2,550 88 2,435 239 100
Total revenue 25,051 20,876 94,735 63,633 22,738
Operating costs and expenses:          
Operations and maintenance (1) 7,818 7,980 32,042 26,336 6,922
Sulfur disposal costs 740 729 2,200
Impairment 104 7,872 3,536 8,114 3,432
Other operating income (3,552)
Depreciation, depletion and amortization 5,991 8,890 30,424 34,009 6,810
Total operating costs and expenses 13,913 25,482 66,731 67,107 17,164
Operating income (loss) $ 11,138 $ (4,606) $ 28,004 $ (3,474) $ 5,574
           
Corporate and Other          
Revenues:          
Unrealized commodity derivative gains (losses) $ (29,615) $ (62,022) $ 8,224 $ (189,590) $ (17,044)
Realized commodity derivative (losses) gains (6,979) 12,869 (17,010) 83,300 (1,535)
Intersegment elimination - Sales of natural gas, oil and condensate (6,110) (6,110)
Total revenue (42,704) (49,153) (14,896) (106,290) (18,579)
Intersegment elimination - Cost of natural gas, oil and condensate (5,587) (5,587)
General and administrative 9,284 11,020 45,775 45,819 10,674
Intersegment elimination - Operations and maintenance (47) (47)
Depreciation, depletion and amortization 316 305 1,550 1,073 399
Operating loss $ (46,670) $ (60,478) $ (56,587) $ (153,182) $ (29,652)
           
(1) Includes natural gas sales of $47 from the South Texas Segment to the Upstream Segment for both the three and twelve month periods ended December 31, 2010.
(2) Includes purchases of oil and condensate from the Upstream Segment of $5,587 for both the three and twelve month periods ended Devember 31, 2010.
(3) Includes sales of oil and condensate to the Texas Panhandle Segment of $6,063 for both the three and twelve month periods ended December 31, 2010.
(4) Revenues include a change in the value of product imbalances of $(102) for both the three and twelve months ended December 31, 2010, respectively, and $(260) for the twelve months ended December 31, 2009, respectively. 
(5) Revenues include a change in the value of product imbalances of $(89), $1,104, $430, $(1,273) and $(48) for the three and twelve months ended December 31, 2010 and 2009 and the three months ended September 30, 2010, respectively.
(6) Revenues include a change in the value of product imbalances of $451, $370, $28 and $(81) for the three months ended December 31, 2010, the three and twelve months ended December 31, 2009 and the three months ended September 30, 2010, respectively.
(7) Revenues include a change in the value of product imbalances of $21 and $48 for the three and twelve months ended December 31, 2010.
 
Eagle Rock Energy Partners, L.P.
Midstream Segment
Operating Income
($ in thousands)
(unaudited)
 
 

Three Months

Ended December 31,


Twelve Months Ending

December 31,
Three Months

Ended

September 30,
  2010 2009 2010 2009 2010
Texas Panhandle          
Revenues:          
Natural gas, natural gas liquids, oil and condensate sales $ 95,685 $ 86,125 $ 346,278 $ 282,916 $ 78,905
Gathering, compression, processing and treating services 3,146 2,827 11,957 11,036 2,821
Total revenue 98,831 88,952 358,235 293,952 81,726
Cost of natural gas, natural gas liquids, oil and condensate (1) 66,569 59,091 243,054 206,985 54,783
Operating costs and expenses:          
Operations and maintenance 9,366 7,466 35,032 31,873 9,155
Depreciation, depletion and amortization 10,945 12,425 45,876 46,085 11,702
Total operating costs and expenses 20,311 19,891 80,908 77,958 20,857
Operating income $ 11,951 $ 9,970 $ 34,273 $ 9,009 $ 6,086
           
East Texas/Louisiana          
Revenues:          
Natural gas, natural gas liquids, oil and condensate sales $ 41,106 $ 46,601 $ 168,922 $ 181,550 $ 37,352
Gathering, compression, processing and treating services 5,895 6,017 35,427 27,968 8,854
Total revenue 47,001 52,618 204,349 209,518 46,206
Cost of natural gas and natural gas liquids 36,614 41,050 151,236 162,957 33,940
Operating costs and expenses:          
Operations and maintenance 4,354 4,098 17,275 17,985 4,502
Depreciation, depletion and amortization 5,281 3,719 18,452 17,188 4,631
Impairment 5,941 5,941
Total operating costs and expenses 9,635 13,758 35,727 41,114 9,133
Operating income (loss) $ 752 $ (2,190) $ 17,386 $ 5,447 $ 3,133
           
South Texas          
Revenues:          
Natural gas, natural gas liquids, oil and condensate sales (2) $ 15,565 $ 20,828 $ 79,480 $ 94,691 $ 18,613
Gathering, compression, processing and treating services 968 1,397 3,538 5,608 472
Other revenue 3
Total revenue 16,533 22,225 83,018 100,302 19,085
Cost of natural gas and natural gas liquids 14,958 20,186 73,475 91,916 16,555
Operating costs and expenses:          
Operations and maintenance 669 715 3,336 3,661 717
Impairment 26,209 7,733 29,339 7,733
Depreciation, depletion and amortization 1,681 1,329 5,641 5,324 1,281
Total operating costs and expenses 28,559 9,777 38,316 16,718 1,998
Operating (loss) income from continuing operations (26,984) (7,738) (28,773) (8,332) 532
Discontinued Operations 14 24 77 290 35
Operating (loss) income $ (26,970) $ (7,714) $ (28,696) $ (8,042) $ 567
           
Gulf of Mexico          
Revenues:          
Natural gas, natural gas liquids, oil and condensate sales $ 8,623 $ 10,781 $ 31,925 $ 31,161 $ 7,623
Gathering, compression, processing and treating services 210 192 1,029 864 211
Other revenue 1,616
Total revenue 8,833 10,973 32,954 33,641 7,834
Cost of natural gas and natural gas liquids 7,532 9,101 28,028 26,372 6,638
Operating costs and expenses:          
Operations and maintenance 381 521 1,771 1,907 354
Depreciation, depletion and amortization 2,017 2,131 6,838 6,576 1,651
Total operating costs and expenses 2,398 2,652 8,609 8,483 2,005
Operating loss $ (1,097) $ (780) $ (3,683) $ (1,214) $ (809)
           
(1) Includes purchase of oil and condensate of $5,587 from the Upstream Segment for both the three and twelve month periods ended December 31, 2010.
(2) Includes sales of natural gas of $47 to the Upstream Segment for both the three and twelve month periods ended December 31, 2010.
 
Eagle Rock Energy Partners, L.P.
Midstream Operations Information
(unaudited)
 
 

Three Months

Ended December 31,


Twelve Months Ending

December 31,
Three Months

Ended

September 30,
  2010 2009 2010 2009 2010
Gas gathering volumes - (Average Mcf/d)          
Texas Panhandle 142,976 131,626 131,925 138,450 123,541
East Texas/Louisiana 194,423 220,639 205,868 248,597 205,194
South Texas 37,025 75,661 57,571 83,307 49,842
Gulf of Mexico 113,598 119,193 103,846 116,492 101,473
Total 488,022 547,119 499,210 586,846 480,050
           
NGLs - (Net equity gallons)          
Texas Panhandle 10,270,684 11,755,661 38,025,937 46,376,433 8,342,850
East Texas/Louisiana 4,435,339 5,253,365 18,217,505 19,924,820 4,856,237
South Texas 271,293 319,332 1,175,767 1,248,783 285,505
Gulf of Mexico 1,124,103 1,487,348 4,398,467 5,768,018 1,175,792
Total 16,101,419 18,815,706 61,817,676 73,318,054 14,660,384
           
Condensate - (Net equity gallons)          
Texas Panhandle 10,673,347 9,347,564 43,439,551 35,292,388 12,734,275
East Texas/Louisiana 397,058 605,820 1,617,996 2,381,123 397,199
South Texas 233,218 275,430 1,259,346 1,443,060 13,942
Total 11,303,623 10,228,814 46,316,893 39,116,571 13,145,416
           
Natural gas short position - (Average MMbtu/d)          
Texas Panhandle (3,046) (7,469) (4,811) (6,010) (4,776)
East Texas/Louisiana 489 3,033 833 2,851 317
South Texas 479 822 865 902 773
Total (2,078) (3,614) (3,113) (2,257) (3,686)
           
Average realized NGL price - per Bbl          
Texas Panhandle $ 48.50 $ 46.58 $ 45.85 $ 33.45 $ 40.38
East Texas/Louisiana $ 35.31 $ 56.50 $ 34.68 $ 35.87 $ 31.32
South Texas $ 48.89 $ 44.86 $ 45.91 $ 32.26 $ 40.81
Gulf of Mexico $ 47.97 $ 45.65 $ 46.00 $ 35.52 $ 43.52
Weighted Average $ 45.20 $ 48.54 $ 56.77 $ 34.18 $ 37.74
           
Average realized condensate price - per Bbl          
Texas Panhandle $ 71.61 $ 66.85 $ 66.68 $ 60.14 $ 60.82
East Texas/Louisiana $ 90.26 $ 73.78 $ 79.89 $ 63.34 $ 79.15
South Texas $ 79.16 $ 67.33 $ 75.41 $ 50.83 $ 67.24
Total $ 72.94 $ 67.50 $ 67.75 $ 60.17 $ 60.31
           
Average realized natural gas price - per MMbtu          
Texas Panhandle $ 3.72 $ 4.14 $ 3.92 $ 3.23 $ 3.45
East Texas/Louisiana $ 3.85 $ 4.19 $ 4.87 $ 3.83 $ 4.56
South Texas $ 3.60 $ 4.23 $ 4.38 $ 3.76 $ 4.45
Total $ 3.74 $ 4.18 $ 4.31 $ 3.57 $ 3.97
 
Eagle Rock Energy Partners, L.P.
Upstream Operations Information
(unaudited)
 
 

Three Months

Ended December 31,


Twelve Months Ending

December 31,
Three Months

Ended

September 30,
  2010 2009 2010 2009 2010
Upstream          
Production: (1)          
Oil and condensate (Bbl) 194,762 182,548 808,077 811,075 212,083
Gas (Mcf) 770,195 867,115 3,514,078 3,659,431 778,793
NGLs (Bbl) 81,905 129,454 437,375 504,669 102,967
Total Mcfe 2,430,197 2,739,127 10,986,790 11,553,895 2,669,093
           
Sulfur (long ton) 14,136 23,749 84,065 119,812 17,622
           
Realized prices, excluding derivatives: (1)          
Oil and condensate (per Bbl) $ 66.52 $ 4.51 $ 62.35 $ 45.30 $ 60.21
Gas (Mcf) $ 4.13 $ 0.22 $ 4.43 $ 3.69 $ 4.30
NGLs (Bbl) $ 54.96 $ 4.83 $ 47.00 $ 31.90 $ 41.92
Sulfur (long ton) (2) $ 150.26 $ — $ 88.36 $ — $ 80.54
           
Operating statistics:          
Operating costs per Mcfe (incl production taxes) (3) $ 3.22 $ 2.87 $ 2.92 $ 2.28 $ 2.59
Operating costs per Mcfe (excl production taxes) (3) $ 2.22 $ 2.05 $ 2.12 $ 1.60 $ 1.93
Operating income per Mcfe $ 4.90 $ (1.66) $ 2.62 $ (0.30) $ 2.09
           
Drilling program (gross wells):          
Development wells 2 6 5 3
Completions 2 5 4 2
Workovers 2 2 15 10 6
Recompletions 1 11 1 5
           
(1) Calculation does not include impact of product imbalances.
(2) During the twelve months ended December 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.
(3) Excludes sulfur disposal costs of $0.7 million, $0.7 million and $2.2 million for the twelve months ended December 31, 2010, the three and twelve months ended December 31, 2009, 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 December 31,


Twelve Months Ending

December 31,
Three Months

Ended

September 30,
  2010 2009 2010 2009 2010
Net loss to adjusted EBITDA          
Net loss, as reported $ (52,236) $ (68,655) $ (5,349) $ (171,258) $ (25,237)
Depreciation, depletion and amortization 26,231 28,799 108,781 110,255 26,474
Impairment 26,313 21,546 32,875 21,788 3,432
Risk management interest related instruments - unrealized (5,124) (2,784) 7,164 (12,529) 3,112
Risk management commodity related instruments - unrealized, including amortization of commodity derivative costs 29,615 62,022 (8,224) 189,590 17,044
Other Operating (income) expenses (non-recurring) (3,552)
Non-cash mark-to-market of Upstream product imbalances (281) (1,104) (746) 1,505 102
Restricted units non-cash amortization expense 755 1,661 5,407 6,685 1,294
Income tax provision (benefit) (1,605) (596) (2,545) 1,022 (1,236)
Interest - net including realized risk management instruments and other expense 8,123 9,780 35,058 41,350 8,470
Other (income)/expense (402) (111) (501) (934) (21)
Discontinued operations 334 (3,548) (43,207) (9,397) (224)
Adjusted EBITDA $ 31,723 $ 47,010 $ 128,713 $ 174,525 $ 33,210
           
Net loss to distribute cash flow          
Net loss, as reported $ (52,236) $ (68,655) $ (5,349) $ (171,258) $ (25,237)
Depreciation, depletion and amortization expense 26,231 28,799 108,781 110,255 26,474
Impairment 26,313 21,546 32,875 21,788 3,432
Risk management interest related instruments-unrealized (5,124) (2,784) 7,164 (12,529) 3,112
Risk management commodity related instruments - unrealized, including amortization of commodity derivative costs 29,615 62,022 (8,224) 189,590 17,044
Capital expenditures-maintenance related (5,558) (6,816) (25,528) (21,843) (7,903)
Non-cash mark-to-market of Upstream product imbalances (281) (1,104) (746) 1,505 102
Restricted units non-cash amortization expense 755 1,661 5,407 6,685 1,294
Other Operating (income) expenses (non-recurring) (3,552)
Income tax provision (benefit) (1,605) (596) (2,545) 1,022 (1,236)
Other (income)/expense (402) (111) (501) (934) (21)
Cash income taxes 29 (617) (576) (1,609) 376
Discontinued operations 334 (3,548) (43,207) (9,397) (224)
Distributable cash flow $ 18,071 $ 29,797 $ 67,551 $ 109,723 $ 17,213
           
Supplemental Information
($ in thousands)
 

Three Months

Ended December 31,


Twelve Months Ending

December 31,
Three Months Ended

September 30,
  2010 2009 2010 2009 2010
Amortization of commodity derivative costs $ 442 $ 14,477 $ 3,957 $ 48,363 $ 437
CONTACT: Eagle Rock Energy Partners, L.P.
         
         Jeff Wood, 281-408-1203
         Senior Vice President and Chief Financial Officer
         
         Adam Altsuler, 281-408-1350
         Director, Corporate Finance and Investor Relations

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