Eagle Rock Energy Partners L P (EROC) DEFA14A Additional proxy soliciting materials

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

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Eagle Rock Energy Partners, L.P.

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March 5, 2010

Eagle Rock Reports Fourth-Quarter and Year-End 2009 Financial Results

HOUSTON — Eagle Rock Energy Partners, L.P. (“Eagle Rock” or the “Partnership”) (NASDAQ: EROC) today announced its unaudited financial results for the three months and year ended December 31, 2009. Notable events with respect to fourth-quarter 2009 included the following:

• Adjusted EBITDA totaled $51.4 million, in line with the $51.3 million reported in third-quarter 2009 and a decrease of 20% as compared to the $64.0 million reported for fourth-quarter 2008.

• Repaid $20.0 million of outstanding borrowings during the quarter, reducing total debt outstanding under its revolving credit facility to $754.4 million as of December 31, 2009. The Partnership has repaid an additional $10 million subsequent to year-end 2009.

• Distributable Cash Flow totaled $34.2 million, a decrease of 7% as compared to the $36.6 million reported in third-quarter 2009 and a decrease of 28% as compared to the $47.7 million reported for fourth-quarter 2008.

• Reported a net loss of $68.7 million, as compared to a net loss of $25.3 million for third-quarter 2009 and net income of $54.8 million for fourth-quarter 2008.

• Paid a quarterly distribution with respect to the fourth quarter of 2009 of $0.025 per common and general partner unit, unchanged from the distribution paid with respect to third-quarter 2009.

Fourth-quarter 2009 Adjusted EBITDA and Distributable Cash Flow excluded $14.5 million in amortization of commodity hedge costs for the period, primarily related to hedge reset transactions. Including the amortization costs, fourth-quarter 2009 Adjusted EBITDA would have been $37.0 million and Distributable Cash Flow would have been $19.7 million, representing a decrease of 9% and 24%, respectively, compared to the third quarter of 2009 (presented on same basis).

For the full-year 2009, Eagle Rock generated $188.6 million of Adjusted EBITDA, a decrease of 24% from the $248.3 million reported for the full-year 2008. Including $48.4 million in amortization of commodity hedge costs for 2009, full-year 2009 Adjusted EBITDA would have been $140.2 million, a 40% decrease from full-year 2008 Adjusted EBITDA (presented on same basis).

“Our fourth quarter 2009 financial results reflect continued improvement in the commodity price environment. In particular, our Midstream Business realized a 56% improvement in normalized operating margin due primarily to higher realized natural gas liquids prices. Our Adjusted EBITDA of $51.4 million for the quarter and $188.6 million for the year were

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above the high ends of our guidance range given in April 2009, as our business benefited from the ongoing recovery in crude oil and natural gas liquids prices and prudent management of our hedge portfolio,” said Joseph A. Mills, Eagle Rock’s Chairman and Chief Executive Officer.

Mr. Mills added, “2009 was a challenging year, and we remain focused on improving our financial strength going forward. Specifically, we have paid down $93 million in debt since we made the decision in April 2009 to reduce our distribution and redirect our cash flow towards improving liquidity. We continue to make preparations for a unitholder meeting in which we will seek to gain approval for the recapitalization and related transactions outlined in the agreements we filed with the SEC. We expect to mail our definitive proxy within the month of March and to have our unitholder meeting, and the proposed rights offerings if we receive the requisite approval of unitholders, within the second quarter. In addition, we continue to be excited about the organic growth opportunities that are currently available in our core areas, namely the Granite Wash play around our Panhandle midstream assets and the Haynesville Shale play around our East Texas midstream assets.”

Fourth-Quarter 2009 Financial and Operating Results

Eagle Rock analyzes and manages its operations under seven distinct segments: four segments in its Midstream Business — the Texas Panhandle, East Texas/Louisiana, South Texas and Gulf of Mexico Segments — and the Upstream, Minerals and Corporate Segments. The Corporate Segment includes the Partnership’s risk management (derivatives) 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 2009 to those of the third quarter of 2009. 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 2008. Please refer to the financial tables at the end of this release for further detailed information.

Midstream Business— Operating income for the Midstream Business in the fourth quarter of 2009, excluding the impact of impairments, increased by $4.7 million, or 56%, compared to the third quarter of 2009. The increase was a result primarily of improved realized NGL prices. The weighted average realized NGL and condensate prices for the fourth-quarter 2009 were approximately 36% and 4%, respectively, above those realized in the third-quarter 2009. These factors more than offset a 3.9% decline in gas gathered volume from third-quarter 2009 to fourth-quarter 2009. The equity NGL volumes declined, from third-quarter 2009 to fourth-quarter 2009, by a slightly higher amount of 4.1% as the Panhandle Segment was primarily affected by lower wellhead volumes in the West Panhandle due to cold weather.

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Upstream Business— Operating income for Eagle Rock’s Upstream Business in the fourth quarter of 2009, excluding the impact of impairments, decreased by $0.9 million, or 22%, compared to the third quarter of 2009. The decrease was due to a decline in production volumes due to well workover activity in Alabama and unplanned plant maintenance by a third-party processor in East Texas. For the fourth quarter of 2009, total Upstream production was down 8.6% as compared to production in third-quarter 2009. This decrease was partially offset by higher realized commodity prices, which improved over the third quarter of 2009 by 21%, 46% and 35% for oil and condensate, natural gas and natural gas liquids sales, respectively. In addition, the Partnership continued to incur sulfur disposal costs in excess of sulfur revenues related to its sulfur production at its South Alabama and East Texas producing areas. Notwithstanding, management has recently seen a strengthening in sulfur demand and anticipates generating positive cash flow from its sulfur production over the next three to six months.

Minerals Business— Segment operating income from the Minerals Business in the fourth quarter of 2009 increased by $1.2 million, or 54%, compared to the third quarter of 2009, excluding the impact of impairments taken in the third quarter. The increase was due to higher realized crude oil, NGL and natural gas prices as well as 27% higher production volumes as compared to third-quarter 2009.

Revenue for fourth-quarter 2009, including the impact of Eagle Rock’s realized and unrealized derivative gains and losses, decreased 8% to $151.4 million, compared with $163.9 million reported for third-quarter 2009, and a decrease of 70% from the $504.2 million reported for fourth-quarter 2008. The primary contributor to this decrease was the Partnership’s unrealized commodity derivative losses. Eagle Rock recorded an unrealized loss on commodity derivatives of $62.0 million in fourth-quarter 2009, as compared to unrealized losses on commodity derivatives of $26.0 million in third-quarter 2009 and an unrealized gain on commodity derivatives of $241.2 million in fourth-quarter 2008. The unrealized gain (loss) on commodity derivatives is a non-cash, mark-to-market amount which includes the amortization of commodity hedging costs. Fourth-quarter 2009 revenues included a realized gain on commodity derivatives of $12.9 million, as compared to a realized gain of $17.2 million in third-quarter 2009.

Adjusted EBITDA was $51.4 million and Distributable Cash Flow was $34.2 million for the fourth quarter of 2009. The Partnership’s actual distribution of $0.025 per common and general partner unit with respect to the fourth quarter of 2009 distribution was paid on February 12, 2010. Because the actual distribution paid for the quarter was below the minimum quarterly distribution (the “MQD”), the cumulative arrearage attributable to the common units increased by $0.3375 per unit to a total of $1.35 per unit. The Partnership is under no obligation to pay the arrearages, but all cumulative arrearages must be paid before any distributions can be made to the Partnership’s subordinated units. For a more detailed discussion of the common unit arrearages, please refer to

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the Eagle Rock partnership agreement (filed as part of the Partnership’s filings with the U.S. Securities and Exchange Commission).

Fourth-quarter 2009 Adjusted EBITDA and Distributable Cash Flow excluded $14.5 million in amortization of commodity hedge costs for the period (including costs of hedge reset transactions — transactions undertaken by the Partnership to increase the strike prices on commodity swaps and/or collars that settled in the period). Including the amortization costs, fourth-quarter 2009 Adjusted EBITDA would have been $37.0 million, and Distributable Cash Flow would have been $19.7 million.

Full-Year 2009 Financial Results

Total Revenue for 2009, including the impact of both our realized and unrealized derivative gains and losses, decreased by 59% to $610.5 million compared with $1.5 billion for the prior year. As was the case in fourth-quarter 2009, one of the largest contributors to this decrease was the Partnership’s unrealized commodity derivative gains (losses). Total Revenue for 2009 includes $189.6 million of unrealized losses on commodity derivatives as compared to $207.8 million of unrealized gains on commodity derivatives for the full year ended December 31, 2008.

With regard to the Partnership’s Midstream operations, there were two primary contributors to this decrease: i) lower NGL and condensate pricing, as compared to pricing in 2008, and ii) lower NGL equity production in the Texas Panhandle and East Texas as compared to production in 2008. The lower NGL equity production in the Texas Panhandle was primarily due to approximately 9% lower gas gathered volumes in 2009 as compared to 2008. The lower NGL equity production in East Texas was primarily due to lower gathered volumes of rich gas despite the increase in overall gathered volumes driven by the Millennium Acquisition, which closed on October 1, 2008. Gas volumes from the Millennium Acquisition are comprised primarily of dry gas that does not require processing to remove NGLs prior to delivery to the interstate pipelines. Also contributing to the decline in NGL equity production, certain plants operated in ethane rejection mode for much of the first two months of 2009. Ethane rejection operations occur when the Partnership elects to not recover the ethane component in the natural gas stream in its plants and instead chooses to leave the ethane component in the residue gas stream sold at the tailgates of its plants. The Partnership operates in this manner when the value of ethane is worth more in the gas stream than as a separate product.

With regard to the Partnership’s Upstream and Minerals operations, the decrease in revenue was due to substantially lower realized prices for oil, natural gas, NGLs and sulfur as well as the non-cash mark-to-market of product imbalances. In the Partnership’s Upstream operations, these decreases were partially offset by an

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additional four months of operations in 2009 as compared to 2008 related to the assets acquired in the Stanolind Acquisition.

Adjusted EBITDA for the year ended December 31, 2009 was $188.6 million compared with $248.3 million for the year ended December 31, 2008, a decrease of 24%. Distributable Cash Flow for the year ended December 31, 2009 was $123.8 million compared to $181.6 million for the year ended December 31, 2008, which represents a decrease of 32%.

Adjusted EBITDA and Distributable Cash Flow for the year ended 2009 excludes $48.4 million of non-cash amortization of commodity hedge costs. Including these costs, 2009 Adjusted EBITDA would have been $140.2 million, and 2009 Distributable Cash Flow would have been $75.4 million.

Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures that are defined below and reconciled to the most directly comparable GAAP financial measure of net income (loss) at the end of this release.

Capitalization and Liquidity Update

Total debt outstanding under the Partnership’s revolving credit facility as of December 31, 2009 was approximately $754.4 million. Outstanding borrowings were reduced by $20 million during the fourth quarter of 2009. Including the additional $10 million repaid subsequent to year-end 2009, the Partnership has reduced outstanding borrowings by a total of $93 million since April 30, 2009 as a result of the reduction in the quarterly distribution.

The credit facility has aggregate commitments of approximately $971 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 and Minerals Businesses. The borrowing base for the Upstream Business was reaffirmed at $135 million effective October 1, 2009 as part of the Partnership’s semi-annual redetermination, with no increase in fees or borrowing costs. The Partnership is currently undergoing its semi-annual borrowing base redetermination, which will become effective on April 1, 2010. Unused capacity available under the credit facility, based on financial covenants, was approximately $61 million as of December 31, 2009.

Eagle Rock has entered into certain agreements, described below, to further enhance its liquidity. These agreements are contingent upon the affirmative vote of the Partnership’s unaffiliated unitholders. Should the agreements not be consummated,

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management will consider other alternatives to enhance the Partnership’s liquidity and address concerns surrounding its ability to remain in compliance with the financial covenants under its credit facility. These alternatives include potential asset sales, accessing external capital, if available, and additional adjustments to the Partnership’s hedging portfolio.

Recapitalization and Related Transactions

On December 21, 2009, Eagle Rock announced that the Partnership, through certain of its affiliates, had entered into definitive agreements with affiliates of Natural Gas Partners (NGP) and Black Stone Minerals Company (Black Stone) to improve its liquidity and simplify its capital structure. The definitive agreements include: (i) a Securities Purchase and Global Transaction Agreement, entered into between Eagle Rock and NGP, including Eagle Rock’s general partner entities controlled by NGP, and (ii) a Purchase and Sale Agreement (the “Minerals Business Sale Agreement”), entered into between Eagle Rock and Black Stone for the sale of Eagle Rock’s Minerals Business. The Securities Purchase and Global Transaction Agreement was amended on January 12, 2010 to allow for greater flexibility in the payment of the contemplated transaction fee to NGP (the amended Securities Purchase and Global Transaction Agreement is referred to herein as the “Global Transaction Agreement”).

The Global Transaction Agreement and Minerals Business Sale Agreement include the following key provisions:

• An option, through December 2012, in favor of Eagle Rock, exercisable by the issuance of 1,000,000 newly-issued common units, to capture the value of the Partnership’s controlling interest through (i) acquiring Eagle Rock’s general partner and thereby acquiring the 844,551 general partner units outstanding, and (ii) reconstituting the company’s board of directors to allow Eagle Rock’s common unitholders to elect the majority of its directors;

• The sale of Eagle Rock’s Minerals Business to Black Stone for total consideration of $174.5 million in cash;

• The simplification of Eagle Rock’s capital structure through the contribution, and resulting cancellation, of its existing incentive distribution rights and 20.7 million subordinated units currently held by NGP;

• A rights offering in which NGP will fully participate with respect to 9.5 million common and general partner units it controls as well as with respect to common units it receives as payment of the transaction fee, if any; and

• For a period of up to five months following unitholder approval of the amended Global Transaction Agreement, NGP’s commitment to back-stop up to $41.6 million, at a price of $3.10 per unit, in an Eagle Rock equity offering to be undertaken at the sole option of the Partnership’s Conflicts Committee.

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In exchange for NGP’s contributions and commitments under the Global Transaction Agreement, Eagle Rock will pay NGP a transaction fee of $29 million in newly-issued common units valued at the greater of (i) 90% of the volume-adjusted trailing 10-day average of the trading price of Eagle Rock’s common units calculated on the 20th day prior to the date of the special meeting to obtain unitholder approval of the Global Transaction Agreement and related proposals; and (ii) $3.10 per common unit, unless the Conflicts Committee of Eagle Rock’s Board of Directors elects, in its sole discretion, on or prior to the 20^th day prior to the unitholder meeting for us to pay the transaction fee in cash.

The Partnership’s Board of Directors has approved the applicable definitive agreements and has recommended, along with the Conflicts Committee, that Eagle Rock’s public unitholders approve the Global Transaction Agreement and related amendments to the Eagle Rock partnership agreement.

With the exception of the potential equity offering, if any, completion of the recapitalization and related transactions outlined above is expected to occur in the first half of 2010, subject to customary closing conditions including approval of the Global Transaction Agreement and the transactions contemplated therein, including certain partnership agreement amendments, by a majority of the common units held by non-affiliates of NGP. Each of the Minerals Business Purchase Agreement and the Global Transaction Agreement is conditioned upon the consummation of the transactions contemplated by the other.

The Partnership filed a copy of the Minerals Business Sale Agreement, and the Global Transaction Agreement and related ancillary agreements, on Form 8-K with the SEC on December 21, 2009 and January 12, 2010, respectively. See important additional information regarding the Revised Recapitalization and Related Transactions as described below.

Hedging Update

On December 17, 2009, Eagle Rock entered into several hedging transactions to reduce the risk and improve the performance of its commodity hedging portfolio related to its Midstream business. These transactions involved unwinding several crude derivatives that were proxy hedges for expected future natural gas liquids volumes in 2010, and subsequently re-hedging these volumes with direct NGL product swaps. These transactions did not affect Eagle Rock’s percentage liquid hedge levels in 2010.

Specifically, Eagle Rock unwound 35,000 barrels per month of an existing 40,000 barrels per month NYMEX WTI collar related to the twelve months ended December 31, 2010 and also unwound a 7,000 barrels per month NYMEX WTI swap related to the twelve months ended December 31, 2010. The cost of these transactions was approximately $5.6 million. In related transactions, Eagle Rock simultaneously entered into the following direct product hedges: i) 1,478,400 gallons per month OPIS TET Mt.

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Belvieu Propane swap with a $1.0915/gallon strike price; ii) 348,600 gallons per month OPIS non-TET Mt. Belvieu Iso-butane swap with a $1.4045/gallon strike price; iii) 705,600 gallons per month OPIS non-TET Mt. Belvieu N-butane swap with a $1.3745/gallon strike price; and iv) 184,800 gallons per month OPIS non-TET Mt. Belvieu natural gasoline swap with a $1.6462/gallon strike price.

In addition, on February 16, 2010, the Partnership entered into a costless collar for 12,000 barrels per month of WTI crude oil for the twelve months ending December 31, 2011 with a floor of $75.00/Bbl and a cap of $89.85/Bbl. On February 17, 2010, the Partnership entered into a costless collar for 16,000 barrels per month of WTI crude oil for the twelve months ending December 31, 2012 with a floor of $75.00/Bbl and a cap of $94.75/Bbl.

On March 5, 2010, Eagle Rock posted an update to its Commodity Hedging Overview presentation on its website to describe the details of its latest hedge transactions and its existing hedge portfolio. The presentation can be accessed by going to www.eaglerockenergy.com, select Investor Relations, then select Presentations.

Conference Call

Eagle Rock will hold a conference call to discuss its fourth-quarter and full-year 2009 financial and operating results on Monday, March 8, 2010 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 atwww.eaglerockenergy.com. To participate by telephone, the call-in number is 888-679-8034, confirmation code 79736791. 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=P67TDYYC6.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 call start. An audio replay of the conference call will also be available for thirty days by dialing 888-286-8010, confirmation code 85398878. 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 three 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

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includes acquiring, exploiting, developing, and producing interests in oil and natural gas properties; and c) minerals, which includes acquiring and managing fee mineral and royalty interests, either through direct ownership or through investment in other partnerships, in properties located in multiple producing trends across the United States. Its corporate office is located in Houston, Texas.

“Board” and “Board of Directors” in this press release refer to the Board of Directors of the general partner of the general partner of the Partnership.

Contacts:

Eagle Rock Energy Partners, L.P.
Jeff Wood, 281-408-1203
Senior Vice President and Chief Financial Officer

Adam Altsuler, 281-408-1350
Senior Financial Analyst

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

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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 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 general partner and finance its maintenance capital expenditures. Eagle Rock further believes that Adjusted EBITDA also describes 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 describe 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 higher prices or 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

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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.

Important Additional Information Regarding the Proposed Restructuring Transactions will be Filed with the Securities and Exchange Commission (“SEC”):

In connection with the proposed recapitalization described in the Partnership’s Current Report on Form 8-K filed with the SEC on January 12, 2010, Eagle Rock has filed a preliminary proxy statement and will file a definitive proxy statement and other documents with the SEC. INVESTORS AND SECURITY HOLDERS ARE ADVISED TO READ THE DEFINITIVE PROXY STATEMENT WHEN IT BECOMES AVAILABLE BECAUSE IT WILL CONTAIN IMPORTANT INFORMATION ABOUT EAGLE ROCK AND THE RECAPITALIZATION. Investors and security holders may obtain copies of the definitive proxy statement and other documents that Eagle Rock files with the SEC (when they are available) free of charge at the SEC’s web site at http://www.sec.gov. The definitive proxy statement and other relevant documents may also be obtained (when available) free of charge on Eagle Rock’s web site at http://www.eaglerockenergy.com or by directing a request to Eagle Rock Energy Partners, L.P., P.O. Box 2968, Houston, Texas 77252-2968, Attention: Investor Relations.

Eagle Rock and its directors, executive officers and other members of its management and employees may be deemed participants in the solicitation of proxies from the unitholders of Eagle Rock in connection with the proposed transactions. Information regarding the special interests of persons who may be deemed to be such participants in the proposed transactions will be included in the proxy statement when it becomes available. Information regarding the directors and executive officers of Eagle Rock is also included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2008, and will be included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2009, when filed with the SEC, and subsequent statements of changes in beneficial ownership on file with the SEC. These documents are available free of charge at the SEC’s web site at http://www.sec.gov and from Investor Relations at Eagle Rock as described above.

This document shall not constitute an offer to sell or the solicitation of an offer to buy any securities, nor shall there be any sale of securities in any jurisdiction in which such

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offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction. No offering of securities shall be made except by means of a prospectus meeting the requirements of the Securities Act of 1933, as amended. This news release may include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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, which may cause the Partnership’s actual results to differ materially from those implied or expressed by the 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 SEC for the year ended December 31, 2008, and the Partnership’s Forms 10-Q filed with the SEC for subsequent quarters, as well as any other public filings and press releases.

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

	Three Months						Twelve Months						Three Months
	Ended December 31,						Ended December 31,						Ended
	2009			2008			2009			2008			September 30, 2009
REVENUE:
Natural gas, NGLs, condensate, oil and sulfur sales	$	185,123		$	225,028		$	653,712		$	1,233,919		$	156,779
Gathering, compression, processing and treating fees		10,433			11,130			45,476			38,871			11,814
Minerals and royalty income		4,920			8,388			15,708			42,994			4,050
Unrealized commodity derivative gains (losses)		(62,022	)		241,205			(189,590	)		207,824			(26,002	)
Realized commodity derivative gains (losses)		12,869			18,329			83,300			(46,059	)		17,170
Other income		88			106			1,858			716			50
Total Revenue		151,411			504,186			610,464			1,478,265			163,861
COSTS AND EXPENSES:
Cost of natural gas and NGLs		129,428			165,033			488,230			891,433			109,945
Operations and maintenance (1)		18,572			18,848			73,196			73,620			16,934
Taxes other than income		3,257			4,961			12,047			19,936			2,934
Impairment		21,546			174,851			22,062			174,851			274
General and administrative		11,306			14,540			46,188			45,701			10,449
Other operating (income) expense		—			565			(3,552	)		10,699			—
Depreciation, depletion and amortization		30,025			35,955			116,262			116,754			28,586
Total Costs and Expenses		214,134			414,753			754,433			1,332,994			169,122
OPERATING INCOME (LOSS)		(62,723	)		89,433			(143,969	)		145,271			(5,261	)
Other Income (Expense):
Interest income		5			120			188			793			10
Other income		493			2,461			2,328			5,328			725
Interest expense, net		(4,309	)		(9,308	)		(21,591	)		(32,884	)		(4,315	)
Unrealized interest rate derivative gains (losses)		2,784			(27,245	)		12,529			(27,717	)		(5,308	)
Realized interest rate derivative gains (losses)		(5,207	)		(311	)		(18,876	)		(5,214	)		(5,040	)
Other expense		(269	)		(303	)		(1,070	)		(955	)		(267	)
Total Other Income (Expense)		(6,503	)		(34,586	)		(26,492	)		(60,649	)		(14,195	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		(69,226	)		54,847			(170,461	)		84,622			(19,456	)
Income tax (benefit) provision		(547	)		363			1,087			(1,134	)		5,841
INCOME (LOSS) FROM CONTINUING OPERATIONS		(68,679	)		54,484			(171,548	)		85,756			(25,297	)
DISCONTINUED OPERATIONS		24			313			290			1,764			26
NET INCOME (LOSS)	$	(68,655	)	$	54,797		$	(171,258	)	$	87,520		$	(25,271	)

(1) Includes costs of $0.7 million and $2.2 million for disposal of sulfur in our Upstream Segment for the three and twelve months ended December 31, 2009, respectively.

13

Eagle Rock Energy Partners, L.P.
Consolidated Balance Sheets
($ in thousands)
(unaudited)

	December 31,			December 31,
	2009			2008
Assets
Current assets:
Cash and cash equivalents	$	2,732		$	17,916
Accounts receivable		91,164			115,932
Risk management assets		2,479			76,769
Prepayments and other current assets		2,790			2,607
		99,165			213,224
Property plant and equipment — net		1,275,881			1,357,609
Intangible assets — net		132,343			154,206
Deferred tax asset		1,562			—
Risk management assets		3,410			32,451
Other assets		21,967			15,571
Total assets	$	1,534,328		$	1,773,061
Liabilities and Members’ Equity
Current liabilities:
Accounts payable	$	78,096		$	116,578
Due to affiliate		12,910			4,473
Accrued liabilities		11,110			19,565
Taxes payable		2,416			1,559
Risk management liabilities		51,650			13,763
		156,182			155,938
Long-term debt		754,383			799,383
Asset retirement obligations		19,829			19,872
Deferred tax liability		40,246			42,349
Risk management liabilities		32,715			26,182
Other Long-term liabilities		575			1,622
Members’ equity
Common unitholders		484,282			625,590
Subordinated unitholders		52,058			105,839
General partner		(5,942	)		(3,714	)
		530,398			727,715
Total Liabilities and Members’ Equity	$	1,534,328		$	1,773,061

14

Eagle Rock Energy Partners, L.P.
Midstream Segment
Operating Income
($ in thousands)
(unaudited)

	Three Months						Twelve Months						Three Months
	Ended December 31,						Ended December 31,						Ended
	2009			2008			2009			2008			September 30, 2009
Texas Panhandle
Revenues:
Natural gas, NGLs, oil and condensate sales	$	86,125		$	78,547		$	282,916		$	592,997		$	67,468
Gathering, compression, processing, and treating services		2,827			2,405			11,036			10,069			2,795
Total revenues		88,952			80,952			293,952			603,066			70,263
Cost of natural gas and NGLs		59,091			60,236			206,985			459,064			46,540
Operating costs and expenses:
Operations and maintenance		7,466			8,616			31,873			34,269			8,206
Depreciation, depletion and amortization		12,425			11,101			46,085			43,688			11,602
Total operating costs and expenses		19,891			19,717			77,958			77,957			19,808
Operating income	$	9,970		$	999		$	9,009		$	66,045		$	3,915
East Texas/Louisiana (1)
Revenues:
Natural gas, NGLs, oil and condensate sales	$	46,601		$	66,724		$	181,550		$	298,720		$	46,253
Gathering, compression, processing, and treating services		6,017			6,264			27,968			23,320			7,367
Total revenues		52,618			72,988			209,518			322,040			53,620
Cost of natural gas and NGLs		41,050			59,093			162,957			269,030			39,665
Operating costs and expenses:
Operations and maintenance		4,098			5,058			17,985			16,569			4,727
Impairment		5,941			26,994			5,941			26,994			—
Depreciation, depletion and amortization		3,719			4,713			17,188			13,559			4,458
Total operating costs and expenses		13,758			36,765			41,114			57,122			9,185
Operating income	$	(2,190	)	$	(22,870	)	$	5,447		$	(4,112	)	$	4,770
South Texas (1)
Revenues:
Natural gas, NGLs, oil and condensate sales	$	20,828		$	46,233		$	94,691		$	168,922		$	17,324
Gathering, compression, processing, and treating services		1,397			1,758			5,608			4,779			1,348
Other		—			13			3			15			—
Total revenues		22,225			48,004			100,302			173,716			18,672
Cost of natural gas and NGLs		20,186			44,328			91,916			161,963			16,842
Operating costs and expenses:
Operations and maintenance		715			1,062			3,661			2,924			896
Impairment		7,733			8,105			7,733			8,105			—
Depreciation, depletion and amortization		1,329			1,616			5,324			4,428			1,287
Total operating costs and expenses		9,777			10,783			16,718			15,457			2,183
Operating income (loss) from continuing operations		(7,738	)		(7,107	)		(8,332	)		(3,704	)		(353	)
Discontinued Operations		24			316			290			1,782			26
Operating income	$	(7,714	)	$	(6,791	)	$	(8,042	)	$	(1,922	)	$	(327	)
Gulf of Mexico(1)
Revenues:
Natural gas, NGLs, oil and condensate sales	$	10,781		$	952		$	31,161		$	952		$	8,314
Gathering, compression, processing, and treating services		192			703			864			703			304
Other		—			—			1,616			—			—
Total revenues		10,973			1,655			33,641			1,655			8,618
Cost of natural gas and NGLs		9,101			1,376			26,372			1,376			6,898
Operating costs and expenses:
Operations and maintenance		521			605			1,907			605			310
Depreciation, depletion and amortization		2,131			1,521			6,576			1,521			1,480
Total operating costs and expenses		2,652			2,126			8,483			2,126			1,790
Operating income	$	(780	)	$	(1,847	)	$	(1,214	)	$	(1,847	)	$	(70	)

(1) Includes operations related to the Millennium Acquisition beginning October 1, 2008.

15

Eagle Rock Energy Partners, L.P.
Segment Summary
Operating Income
($ in thousands)
(unaudited)

	Three Months						Twelve Months						Three Months
	Ended December 31,						Ended December 31,						Ended
	2009			2008			2009			2008			September 30, 2009
Midstream
Revenues:
Natural gas, NGLs, oil and condensate sales	$	164,335		$	192,456		$	590,318		$	1,061,591		$	139,359
Gathering, compression, processing and treating services		10,433			11,130			45,476			38,871			11,814
Other		—			13			1,619			15			—
Total revenues		174,768			203,599			637,413			1,100,477			151,173
Cost of natural gas and NGLs		129,428			165,033			488,230			891,433			109,945
Operating costs and expenses:
Operations and maintenance		12,800			15,341			55,426			54,367			14,139
Impairment		13,674			35,099			13,674			35,099			—
Depletion, depreciation and amortization		19,604			18,951			75,173			63,196			18,827
Total operating costs and expenses		46,078			69,391			144,273			152,662			32,966
Operating income (loss) from continuing operations		(738	)		(30,825	)		4,910			56,382			8,262
Discontinued Operations		24			316			290			1,782			26
Operating income	$	(714	)	$	(30,509	)	$	5,200		$	58,164		$	8,288
Upstream (1)
Revenues:
Oil and condensate	$	9,943		$	10,373		$	35,316		$	72,526		$	10,817
Natural gas (2)		4,940			8,159			12,021			32,513			2,221
NGLs		5,905			4,006			16,057			29,530			4,382
Sulfur		—			10,034			—			37,759			—
Other		88			93			239			701			50
Total revenues		20,876			32,665			63,633			173,029			17,470
Operating costs and expenses:
Operations and maintenance		7,980			8,112			26,291			37,481			5,178
Sulfur disposal costs		740			—			2,245			—			348
Impairment		7,872			138,011			8,114			138,011			—
Other operating income		—			—			(3,552	)		—			—
Depreciation, depletion and amortization		8,890			15,488			34,009			44,997			7,768
Total operating costs and expenses		25,482			161,611			67,107			220,489			13,294
Operating income	$	(4,606	)	$	(128,946	)	$	(3,474	)	$	(47,460	)	$	4,176
Minerals
Revenues:
Oil and condensate	$	2,868		$	1,848		$	9,004		$	14,337		$	2,228
Natural gas		1,400			1,633			3,854			10,451			749
NGLs		215			317			582			1,376			169
Lease bonus, rentals and other		437			4,590			2,268			16,830			904
Total revenues		4,920			8,388			15,708			42,994			4,050
Operating costs and expenses:
Operations and maintenance		309			356			1,281			1,708			203
Impairment		—			1,741			274			1,741			274
Depreciation, depletion and amortization		1,226			1,314			6,007			7,774			1,654
Total operating costs and expenses		1,535			3,411			7,562			11,223			2,131
Operating income	$	3,385		$	4,977		$	8,146		$	31,771		$	1,919
Corporate
Revenues:
Unrealized commodity derivative gains (losses)	$	(62,022	)	$	241,205		$	(189,590	)	$	207,824		$	(26,002	)
Realized commodity derivative gains (losses)		12,869			18,329			83,300			(46,059	)		17,170
Total revenues		(49,153	)		259,534			(106,290	)		161,765			(8,832	)
General and administrative		11,306			14,540			46,188			45,701			10,449
Depreciation, depletion and amortization		305			202			1,073			787			337
Other operating expense		—			565			—			10,699			—
Operating income (loss)	$	(60,764	)	$	244,227		$	(153,551	)	$	104,578		$	(19,618	)

(1)	Includes operations from the Stanolind acquisition beginning on May 1, 2008.
(2)	Revenues include a change in the value of product imbalances of ($1,104) and $841 for the three months ended December 31, 2009 and 2008, respectively.
	Revenues include a change in the value of product imbalances of $1,505 and $841 for the years ended December 31, 2009 and 2008, respectively.
	Revenues include a change in the value of product imbalances $780 for the years ended December 31, 2009 and 2008, respectively.

16

Eagle Rock Energy Partners, L.P.
Midstream Operations Information
(unaudited)

	Three Months						Twelve Months						Three Months
	Ended December 31,						Ended December 31,						Ended
	2009			2008			2009			2008			September 30, 2009
Gas gathering volumes — (Average Mcf/d)
Texas Panhandle		131,626			144,155			138,450			151,964			134,690
East Texas/Louisiana		220,639			275,592			248,597			198,365			236,561
South Texas		75,661			111,111			83,307			88,488			66,680
Gulf of Mexico		119,193			47,796			116,492			12,014			131,527
Total		547,119			578,654			586,846			450,831			569,458
NGLs — (Net equity gallons)
Texas Panhandle		11,755,661			12,831,985			46,376,433			51,351,966			12,170,309
East Texas/Louisiana		5,253,365			9,416,499			19,924,820			27,038,450			6,394,474
South Texas		319,332			591,683			1,248,783			591,683			252,005
Gulf of Mexico		1,487,348			176,962			5,768,018			176,962			1,376,512
Total		18,815,706			23,017,129			73,318,054			79,159,061			19,628,868
Condensate — (Net equity gallons)
Texas Panhandle		9,347,564			9,395,225			35,292,388			35,162,578			9,938,819
East Texas/Louisiana		605,820			506,793			2,381,123			1,580,928			563,790
South Texas		275,430			422,617			1,443,060			1,821,800			210,984
Gulf of Mexico		—			—			—			—			—
Total		10,228,814			10,324,635			39,116,571			38,565,306			10,118,672
Natural gas short position — (Average MMbtu/d)
Texas Panhandle		(7,469	)		(6,054	)		(6,010	)		(5,607	)		(4,685	)
East Texas/Louisiana		3,033			3,041			2,851			1,427			2,295
South Texas		822			500			902			500			1,784
Total		(3,614	)		(2,513	)		(2,257	)		(3,680	)		(606	)
Average realized NGL price — per Bbl
Texas Panhandle	$	46.58		$	28.89		$	33.45		$	58.34		$	33.55
East Texas/Louisiana	$	56.50		$	29.37		$	35.87		$	54.66		$	41.37
South Texas	$	44.86		$	32.52		$	32.26		$	52.66		$	30.71
Gulf of Mexico	$	45.65		$	20.58		$	35.52		$	20.58		$	37.70
Weighted average	$	48.54		$	29.34		$	34.18		$	56.77		$	35.63
Average realized condensate price — per Bbl
Texas Panhandle	$	66.85		$	64.53		$	60.14		$	94.27		$	65.13
East Texas/Louisiana	$	73.78		$	63.18		$	63.34		$	101.62		$	65.49
South Texas	$	67.33		$	53.40		$	50.83		$	92.10		$	58.06
Gulf of Mexico	$	71.14		$	—		$	59.11		$	—		$	65.67
Weighted average	$	67.50		$	64.00		$	60.17		$	94.82		$	65.03
Average realized natural gas price — per MMbtu
Texas Panhandle	$	4.14		$	4.08		$	3.23		$	7.44		$	2.78
East Texas/Louisiana	$	4.19		$	6.59		$	3.83		$	8.75		$	3.42
South Texas	$	4.23		$	6.08		$	3.76		$	8.99		$	3.06
Gulf of Mexico	$	2.03		$	6.64		$	4.64		$	6.64		$	3.46
Weighted average	$	4.18		$	6.75		$	3.57		$	8.76		$	3.09

17

Eagle Rock Energy Partners, L.P.
Upstream and Minerals Operations Information
(unaudited)

	Three Months						Twelve Months						Three Months
	December 31,						December 31,						Ended
	2009			2008			2009			2008			September 30, 2009
Upstream
Production: (1)
Oil and condensate (Bbl)		189,988			214,652			811,075			823,316			211,689
Gas (Mcf)		893,409			1,163,701			3,659,431			4,117,247			982,909
NGLs (Bbl)		123,783			114,591			504,669			480,450			130,960
Total Mcfe		2,776,035			3,139,159			11,553,895			11,939,843			3,038,803
Sulfur (Long ton)		23,801			33,007			119,812			104,613			27,634
Realized prices, excluding derivatives: (1) (2)
Oil and condensate (per Bbl)	$	61.22		$	48.22		$	45.30		$	87.04		$	50.73
Gas (per Mcf)	$	4.40		$	7.67		$	3.69		$	8.09		$	3.02
NGLs (per Bbl)	$	46.44		$	34.60		$	31.90		$	61.39		$	34.29
Sulfur (per Long ton)	$	—		$	301.94		$	—		$	359.96
Operating statistics:
Operating costs per Mcfe (incl production taxes) (3)	$	2.87		$	2.58		$	2.28		$	3.14		$	1.70
Operating costs per Mcfe (excl production taxes) (3)	$	2.05		$	1.40		$	1.60		$	1.86		$	1.05
Operating Income per Mcfe	$	(1.66	)	$	(41.08	)	$	(0.30	)	$	(3.97	)	$	1.37
Drilling program (gross wells):
Development wells		2			6			5			24			—
Completions		2			5			4			23			—
Workovers		2			1			10			13			4
Recompletions		1			1			1			13			—
Minerals
Production:
Oil and condensate (Bbl)		40,063			35,407			158,041			156,118			34,841
Gas (Mcf)		371,768			298,414			1,225,339			1,277,046			264,082
NGLs (Bbl)		5,293			8,917			20,403			26,298			5,739
Total Mcfe		643,904			564,358			2,296,003			2,371,542			507,562
Realized prices, excluding derivatives:
Oil and condensate (per Bbl)	$	71.59		$	52.19		$	56.97		$	91.83		$	63.96
Gas (per Mcf)	$	3.77		$	5.47		$	3.15		$	8.18		$	2.31
NGLs (per Bbl)	$	40.62		$	35.55		$	28.53		$	52.32		$	29.44

(1)	Volumes and realized prices for the three and twelve months ended December 31, 2008 and three months ended September 30, 2009 have been adjusted from prior reported amounts for a reallocation which was recorded in December 2009.
(2)	Calculation does not include impact of product imbalances.
(3)	Excludes sulfur disposal costs of $0.6 million and $2.1 million, respectively, for the three and twelve months ended December 31, 2009.

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).

18

Eagle Rock Energy Partners, L.P.
GAAP to Non-GAAP Reconciliations
($ in thousands)
(unaudited)

	Three Months						Twelve Months						Three Months
	Ended December 31,						Ended December 31,						Ended
Net income (loss) to adjusted EBITDA	2009			2008			2009			2008			September 30, 2009
Net income (loss), as reported	$	(68,655	)	$	54,797		$	(171,258	)	$	87,520		$	(25,271	)
Depreciation, depletion and amortization expense		30,025			35,955			116,262			116,754			28,586
Impairment		21,546			174,851			22,062			174,851			274
Risk management interest related instruments-unrealized		(2,784	)		27,245			(12,529	)		27,717			5,308
Risk management commodity related instruments-unrealized, including amortization of commodity derivative costs		62,022			(241,205	)		189,590			(207,824	)		26,002
Other operating (income) expenses (non-recurring)		—			565			(3,552	)		10,699			—
Non-cash mark-to-market of Upstream product imbalances		(1,104	)		841			1,505			841			780
Restricted units non-cash amortization expense		1,661			3,547			6,685			7,694			904
Income tax provision (benefit)		(547	)		363			1,087			(1,134	)		5,841
Interest — net including realized risk management instruments and other expense		9,780			9,802			41,349			38,260			9,612
Other (income)/expense		(493	)		(2,461	)		(2,328	)		(5,328	)		(725	)
Discontinued operations		(24	)		(313	)		(290	)		(1,764	)		(26	)
Adjusted EBITDA	$	51,427		$	63,987		$	188,583		$	248,286		$	51,285
Net income (loss) to distributable cash flow
Net income (loss), as reported	$	(68,655	)	$	54,797		$	(171,258	)	$	87,520		$	(25,271	)
Depreciation, depletion and amortization expense		30,025			35,955			116,262			116,754			28,586
Impairment		21,546			174,851			22,062			174,851			274
Risk management interest related instruments-unrealized		(2,784	)		27,245			(12,529	)		27,717			5,308
Risk management commodity related instruments-unrealized, including amortization of commodity derivative costs		62,022			(241,205	)		189,590			(207,824	)		26,002
Capital expenditures-maintenance related		(6,816	)		(6,038	)		(21,843	)		(27,485	)		(4,392	)
Non-cash mark-to-market of Upstream product imbalances		(1,104	)		841			1,505			841			780
Restricted units non-cash amortization expense		1,661			3,547			6,685			7,694			904
Other operating (income) expenses (non-recurring)		—			565			(3,552	)		10,699			—
Income tax provision (benefit)		(547	)		363			1,087			(1,134	)		5,841
Other (income)/expense		(493	)		(2,461	)		(2,328	)		(5,328	)		(725	)
Cash income taxes		(617	)		(456	)		(1,609	)		(989	)		(635	)
Discontinued operations		(24	)		(313	)		(290	)		(1,764	)		(26	)
Distributable cash flow	$	34,214		$	47,691		$	123,782		$	181,552		$	36,646

Supplemental Information
($ in thousands)

									Three Months
	Three Months				Twelve Months				Ended
	Ended December 31,				Ended December 31,				September 30, 2009
	2009		2008		2009		2008		2009
Amortization of commodity derivative costs		14,477		6,510		48,363		13,288		10,590

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