Eagle Rock Reports Third-Quarter 2009 Financial Results

HOUSTON - (BUSINESS WIRE) - Eagle Rock Energy Partners, L.P. ("Eagle Rock" or the "Partnership" ) (NASDAQ:EROC) today announced its unaudited financial results for the three and nine months ended September 30, 2009. Notable events with respect to third-quarter 2009 included the following:

• Adjusted EBITDA totaled $51.3 million, an increase of 15% as compared to the $44.7 million reported in second-quarter 2009 and a decrease of 32% as compared to the $74.9 million reported for third-quarter 2008.
• Repaid $30.0 million of outstanding borrowings during the quarter, reducing total debt outstanding under the revolving credit facility to $774.4 million as of September 30, 2009.
• Distributable Cash Flow totaled $36.6 million, an increase of 27% as compared to the $28.8 million reported in second-quarter 2009 and a decrease of 38% as compared to the $59.4 million reported for third-quarter 2008.
• Reported a net loss of $25.3 million, as compared to a net loss of $74.8 million for second-quarter 2009 and net income of $288.1 million for third quarter 2008.
• Announced a quarterly distribution with respect to the third quarter of 2009 of $0.025 per common and general partner unit, unchanged from the distribution paid with respect to second-quarter 2009.

Third-quarter 2009 Adjusted EBITDA and Distributable Cash Flow excluded $10.6 million in amortization of commodity hedge costs for the period (including costs of hedge reset transactions). Including the amortization costs, third-quarter 2009 Adjusted EBITDA would have been $40.7 million and Distributable Cash Flow would have been $26.1 million.

"We are pleased to report continued improvement in our financial performance in the third quarter, driven by higher crude and natural gas liquids prices, as well as by our sustained focus on reducing operating expenses. Our Adjusted EBITDA of $51 million for the quarter was above the high end of our guidance range," said Joseph A. Mills, Chairman and Chief Executive Officer.

Mr. Mills added, "While we are encouraged by the more positive outlook on commodities as reflected in the current forward curves, we continue to feel the effects of low natural gas prices in the form of reduced drilling activity by our producer customers in our Midstream Business. Given this fact, we believe the most prudent course of action remains directing the majority of our cash flow to debt reduction and to improving our liquidity, particularly given the growth opportunities we see in our core areas. To that end, we reduced our debt balance by an additional $30 million during the quarter, bringing the total debt repaid to $63 million since we made the decision to reduce our distribution."

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.

Third-Quarter 2009 Financial Results

Revenue for third-quarter 2009, including the impact of Eagle Rock's realized and unrealized derivative gains and losses, increased 72% to $163.9 million, compared with $95.5 million reported for second-quarter 2009 and a decrease of 73% from the $603.9 million reported for third-quarter 2008. Third-quarter 2009 revenues included a realized gain on commodity derivatives of $17.2 million, as compared to a realized gain of $22.5 million in second-quarter 2009 and a realized loss of $24.1 million in third-quarter 2008. Eagle Rock also recorded an unrealized loss on commodity derivatives of $26.0 million in third-quarter 2009, as compared to unrealized losses on commodity derivatives of $97.0 million in second-quarter 2009 and an unrealized gain of $256.0 million in third-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.

Adjusted EBITDA was $51.3 million and Distributable Cash Flow was $36.6 million for the third quarter of 2009. Third-quarter 2009 Distributable Cash Flow represents approximately 1.8 times the minimum quarterly distribution (the "MQD" ) of $0.3625 per common unit as established in the Eagle Rock partnership agreement, applied to only the common and general partner units and excluding subordinated units. Because the actual distribution paid for the quarter is below the MQD, the cumulative arrearage attributable to the common units will increase by $0.3375 per unit to a total of $1.0125 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 the Eagle Rock partnership agreement (filed as part of the Partnership's filings with the Securities and Exchange Commission).

Third-quarter 2009 Adjusted EBITDA and Distributable Cash Flow excluded $10.6 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, third-quarter 2009 Adjusted EBITDA would have been $40.7 million and Distributable Cash Flow would have been $26.1 million, representing approximately 1.3 times the MQD applied to only the common and general partner units.

Third-Quarter 2009 Operating Results by Business

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. Please refer to the financial tables at the end of this release for further detailed information.

The following discussion of Eagle Rock's operating income by business segment compares the Partnership's financial results in the third quarter of 2009 to those of the second 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 third quarter of 2008.

Midstream Business - Segment operating income for the Midstream Business in the third quarter of 2009 increased by $4.9 million, or 143%, compared to the second quarter of 2009. The increase was caused by higher condensate and NGL prices across all the Midstream segments, in addition to certain positive adjustments in the third quarter related to prior periods. The weighted average realized condensate and NGL prices for the third-quarter 2009 were approximately 10% and 18%, respectively, above those realized in the second-quarter 2009. These factors more than offset sequential quarter gas gathered volume declines of 4.8%. During September 2009 approximately 17.5 MMcf/d of gas was curtailed by producers in the East Texas segment due to low natural gas prices. Absent the curtailed volumes, the gathered gas volume would have declined by 3.8% during the quarter. The equity NGL and condensate volumes declined by a lesser amount of 1.6% as the decrease in gathered volumes impacted the fee based volumes to a greater extent than the processed gas volumes. The Gulf of Mexico Segment gas gathering volumes increased by approximately 33% due to the completion of repairs to damaged offshore pipelines and platforms caused by Hurricanes Ike and Gustav in late 2008.

Upstream Business - Segment operating income for Eagle Rock's Upstream Business in the third quarter of 2009 increased by $3.0 million compared to the second quarter of 2009, excluding the impact of other operating income items related to adjustments of entries booked in prior periods. The increase was caused by improved realized crude oil, natural gas and NGL prices as well as higher total net production volumes. 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. Management expects sulfur disposal costs to be an ongoing issue until sulfur demand improves.

Operating income for the Upstream Business in third-quarter 2009 was positively impacted by a reversal of $1.6 million in environmental reserves determined to no longer be necessary, as well as a credit of $0.7 million for overbilling related to a non-operated asset.

During the third quarter of 2009, the Big Escambia Creek (BEC) plant underwent unanticipated repairs and overhauls to the plant's residue gas compressors. Sales of oil, residue gas and NGLs from the BEC, Flomaton and Fanny Church fields were partially curtailed for 44 days during the quarter due to the compressors' downtime. The reduced sales during this period negatively impacted Upstream revenues by approximately $1.1 million during the quarter. Despite the downtime, total production for the third quarter of 2009 increased by 6% over the second quarter of 2009.

Minerals Business - Segment operating income from the Minerals Business in the third quarter of 2009 increased by $0.2 million compared to the second quarter of 2009. The increase was due to higher realized crude oil and NGL prices, and to higher lease bonus income. These benefits were partially offset by lower oil and gas production volumes for the quarter.

Capitalization and Liquidity Update

Total debt outstanding under the Partnership's revolving credit facility as of September 30, 2009 was approximately $774.4 million. Outstanding borrowings were reduced by $30 million during the third quarter of 2009 and by a total of $63 million over the past two quarters as a result of the decision to lower the quarterly distribution and redirect those cash flows to debt repayment.

The credit facility has aggregate commitments of approximately $971 million after adjusting for the unfunded portion of Lehman Brothers' commitment. On August 21, 2009, BBVA Compass Bank purchased certain assets and liabilities of Guaranty Bank, a wholly owned subsidiary of Guaranty Financial Group Inc. Guaranty Bank had a commitment under the Partnership's revolving credit facility of $30 million, of which approximately $25 million had been funded. BBVA Compass has assumed Guaranty Bank's commitment under the facility, resulting in no change in the aggregate commitments.

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. Unused capacity available under the credit facility, based on financial covenants, was approximately $35 million as of September 30, 2009.

Management is continuing to consider 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, which could include small, discrete midstream assets or all or certain portions of the Partnership's Upstream or Minerals Businesses, and additional adjustments to the Partnership's hedging portfolio. The Partnership's decision to enter into any asset sales will depend on numerous factors, including the potential purchase price for the assets, the extent to which the sales would be credit enhancing, the type of consideration offered and the likelihood of successfully completing the transaction.

In addition, the Partnership has received proposals from Natural Gas Partners ("NGP" ) and Black Stone Minerals Company which would, among other items, involve the sale of the Partnership's Minerals Business and the potential issuance of new equity. These proposals are currently being evaluated by the Conflicts Committee of the Partnership's Board. The Partnership cautions its unitholders, and others considering trading in its securities, that the proposals are not binding at this time, that neither the Board nor the Conflicts Committee has made any decision with respect to the Partnership's response to the proposals, and that there can be no assurance that any agreement will be executed or that any transaction will be approved or consummated.

Hedging Update

On July 30, 2009, Eagle Rock entered into additional natural gas hedges covering 2011 and 2012. The Partnership entered into natural gas swaps for 190,000 MMBtu per month in 2011 at $6.57 / MMBtu and 260,000 MMBtu per month in 2012 at $6.77 / MMBtu. On October 8, 2009, Eagle Rock unwound 3,000 barrels per month of an existing 60,000 barrels per month NYMEX WTI swap related to November and December of 2009 and reset the strike price on the remaining 57,000 barrels per month from $97 per barrel to $135 per barrel at a net fee of approximately $4.2 million. On October 22, 2009, the Partnership entered into (i) a costless collar for 30,000 barrels per month of WTI crude oil in 2011 with a floor of $80.00/Bbl and a cap of $92.40/Bbl, and (ii) a costless collar for 30,000 barrels per month of WTI crude oil in 2012 with a floor of $80.00/Bbl and a cap of $98.50/Bbl. On November 2, 2009, the Partnership paid approximately $5.7 million to reset the strike price from $53.55 to $95.00 on an existing 45,000 barrel per month NYMEX WTI swap relating to the first quarter of 2010.

On November 5, 2009, 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.

Unit Distributions

On October 28, 2009, Eagle Rock announced a third-quarter 2009 cash distribution of $0.025 per unit, or $0.10 per unit on an annualized basis, for all of its outstanding common and general partner units. Eagle Rock will not pay a distribution on the subordinated units for the third quarter of 2009. The distribution will be paid on November 13, 2009 to the general partner and all common unitholders of record on November 9, 2009.

Because Eagle Rock's 20.7 million outstanding subordinated units have not yet converted into common units, each common unit carries a cumulative arrearage equal to the sum of the amount by which each actual quarterly distribution (starting with the distribution for the first quarter of 2009) is below the MQD of $0.3625, per the provisions of Eagle Rock's partnership agreement. The third quarter 2009 Common Unit Arrearage is $0.3375 per common unit. The Cumulative Common Unit Arrearage as of the third quarter of 2009 is $1.0125 per common unit. Both Common Unit Arrearage and Cumulative Common Unit Arrearage are terms defined in Eagle Rock's partnership agreement. In general, before the Partnership can make any distributions to the subordinated units, the Cumulative Common Unit Arrearage must first be paid to common unitholders, and the distribution rate to the common unitholders must equal the MQD. However, the Partnership is not required to pay the Cumulative Common Unit Arrearage, except in certain circumstances described in the partnership agreement, and the Partnership may choose not to pay the arrearages.

"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.

Conference Call

Eagle Rock will hold a conference call to discuss its third-quarter 2009 financial results on Thursday, November 5, 2009 at 10 a.m. Eastern Time (9 a.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 888-679-8033, confirmation code 12987851. Investors are advised to dial into the call at least 15 minutes prior to the call to register. Participants may use the following link to pre-register and view important information about this conference call. 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 immediately prior to and after the call start. To pre-register, please click https://www.theconferencingservice.com/prereg/key.process?key=PLFJ9NP8Y. (Due to its length, this URL may need to be copied/pasted into your internet browser's address field. Remove extra space if one exists.) An audio replay of the conference call will also be available for thirty days by dialing 888-286-8010, confirmation code 63957087. In addition, a replay of the audio webcast will be available within a few days after the call on Eagle Rock's website.

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 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.

Contact:

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

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 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 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" 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.

Eagle Rock Energy Partners, L.P.
Consolidated Statements of Operations
($ in thousands)
(unaudited)
		Three Months								Nine Months								Three Months
		Ended September 30,								Ended September 30,								Ended
		2009				2008				2009				2008				June 30, 2009
REVENUE:
Natural gas, NGLs, condensate, oil and sulfur sales		$	156,779			$	341,700			$	468,589			$	1,008,891			$	153,320
Gathering, compression, processing and treating fees			11,814				12,513				35,043				27,741				11,562
Minerals and royalty income			4,050				17,393				10,788				34,606				3,499
Unrealized commodity derivative gains (losses)			(26,002	)			255,956				(127,568	)			(33,381	)			(97,044	)
Realized commodity derivative gains (losses)			17,170				(24,105	)			70,431				(64,388	)			22,483
Other income			50				428				1,770				610				1,678
Total Revenue			163,861				603,885				459,053				974,079				95,498
COSTS AND EXPENSES:
Cost of natural gas and NGLs			109,945				237,742				358,802				726,400				115,640
Operations and maintenance (1)			16,934				21,475				54,624				54,772				19,049
Taxes other than income			2,934				5,365				8,790				14,975				2,878
Impairment			274				-				516				-				-
General and administrative			10,449				9,893				34,882				31,161				11,895
Other operating (income) expense			-				3,920				(3,552	)			10,134				(3,552	)
Depreciation, depletion and amortization			28,586				28,597				86,237				80,799				27,588
Total Costs and Expenses			169,122				306,992				540,299				918,241				173,498
OPERATING INCOME (LOSS)			(5,261	)			296,893				(81,246	)			55,838				(78,000	)
Other Income (Expense):
Interest income			10				212				183				673				141
Other income			725				434				1,835				2,867				550
Interest expense, net			(4,315	)			(7,498	)			(17,282	)			(23,576	)			(5,428	)
Unrealized interest rate derivative gains (losses)			(5,308	)			(501	)			9,745				(472	)			11,954
Realized interest rate derivative gains (losses)			(5,040	)			(2,358	)			(13,669	)			(4,903	)			(5,147	)
Other expense			(267	)			(205	)			(801	)			(652	)			(267	)
Total Other Income (Expense)			(14,195	)			(9,916	)			(19,989	)			(26,063	)			1,803
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES			(19,456	)			286,977				(101,235	)			29,775				(76,197	)
Income tax (benefit) provision			5,841				(500	)			1,634				(1,497	)			(1,477	)
INCOME (LOSS) FROM CONTINUING OPERATIONS			(25,297	)			287,477				(102,869	)			31,272				(74,720	)
DISCONTINUED OPERATIONS			26				594				266				1,451				(67	)
NET INCOME (LOSS)		$	(25,271	)		$	288,071			$	(102,603	)		$	32,723			$	(74,787	)

(1) Includes costs of $348K and $1,505K for disposal of sulfur in our Upstream Segment for the three and nine months ended September 30, 2009, respectively.

Eagle Rock Energy Partners, L.P.
Consolidated Balance Sheets
($ in thousands)
(unaudited)
		September 30,				December 31,
		2009				2008
Assets
Current assets:
Cash and cash equivalents		$	9,168			$	17,916
Accounts receivable			73,792				115,932
Risk management assets			26,017				76,769
Prepayments and other current assets			2,140				2,607
			111,117				213,224
Property plant and equipment - net			1,313,386				1,357,609
Intangible assets - net			139,273				154,206
Deferred tax asset			1,663				-
Risk management assets			5,725				32,451
Other assets			19,678				15,571
Total assets		$	1,590,842			$	1,773,061
Liabilities and Members' Equity
Current liabilities:
Accounts payable		$	65,666			$	116,578
Due to affiliate			10,859				4,473
Accrued liabilities			11,364				19,565
Taxes payable			992				1,559
Risk management liabilities			34,988				13,763
			123,869				155,938
Long-term debt			774,383				799,383
Asset retirement obligations			19,728				19,872
Deferred tax liability			42,051				42,349
Risk management liabilities			31,406				26,182
Other Long-term liabilities			568				1,622
Members' equity
Common unitholders			533,651				625,590
Subordinated unitholders			70,360				105,839
General partner			(5,174	)			(3,714	)
			598,837				727,715
Total Liabilities and Members' Equity		$	1,590,842			$	1,773,061

Eagle Rock Energy Partners, L.P.
Midstream Segment
Operating Income
($ in thousands)
(unaudited)
		Three Months							Nine Months							Three Months
		Ended September 30,							Ended September 30,							Ended
		2009				2008			2009				2008			June 30, 2009
Texas Panhandle
Revenues:
Natural gas, NGLs, oil and condensate sales		$	67,468			$	179,608		$	196,791			$	514,450		$	66,373
Gathering, compression, processing, and treating services			2,795				2,671			8,209				7,664			2,601
Total revenues			70,263				182,279			205,000				522,114			68,974
Cost of natural gas and NGLs			46,540				138,428			147,894				398,828			49,407
Operating costs and expenses:
Operations and maintenance			8,206				9,190			24,407				25,653			8,056
Depreciation, depletion and amortization			11,602				10,984			33,660				32,587			10,962
Total operating costs and expenses			19,808				20,174			58,067				58,240			19,018
Operating income		$	3,915			$	23,677		$	(961	)		$	65,046		$	549
East Texas/Louisiana (1)
Revenues:
Natural gas, NGLs, oil and condensate sales		$	46,253			$	71,861		$	134,949			$	231,996		$	41,245
Gathering, compression, processing, and treating services			7,367				8,908			21,951				17,056			7,375
Total revenues			53,620				80,769			156,900				249,052			48,620
Cost of natural gas and NGLs			39,665				66,007			121,907				209,937			37,233
Operating costs and expenses:
Operations and maintenance			4,727				4,194			13,887				11,511			4,608
Depreciation, depletion and amortization			4,458				2,989			13,469				8,846			4,240
Total operating costs and expenses			9,185				7,183			27,356				20,357			8,848
Operating income		$	4,770			$	7,579		$	7,637			$	18,758		$	2,539
South Texas (1)
Revenues:
Natural gas, NGLs, oil and condensate sales		$	17,324			$	35,253		$	73,863			$	122,689		$	24,751
Gathering, compression, processing, and treating services			1,348				934			4,211				3,021			1,306
Other			-				-			3				2			-
Total revenues			18,672				36,187			78,077				125,712			26,057
Cost of natural gas and NGLs			16,842				33,307			71,730				117,635			23,819
Operating costs and expenses:
Operations and maintenance			896				635			2,946				1,862			989
Depreciation, depletion and amortization			1,287				939			3,995				2,812			1,284
Total operating costs and expenses			2,183				1,574			6,941				4,674			2,273
Operating income (loss) from continuing operations			(353	)			1,306			(594	)			3,403			(35	)
Discontinued Operations			26				601			266				1,436			(67	)
Operating income		$	(327	)		$	1,907		$	(328	)		$	4,839		$	(102	)
Gulf of Mexico (1)
Revenues:
Natural gas, NGLs, oil and condensate sales		$	8,314			$	-		$	20,380			$	-		$	5,844
Gathering, compression, processing, and treating services			304				-			672				-			280
Other			-				-			1,616				-			1,616
Total revenues			8,618				-			22,668				-			7,740
Cost of natural gas and NGLs			6,898				-			17,271				-			5,181
Operating costs and expenses:
Operations and maintenance			310				-			1,386				-			658
Depreciation, depletion and amortization			1,480				-			4,445				-			1,477
Total operating costs and expenses			1,790				-			5,831				-			2,135
Operating income		$	(70	)		$	-		$	(434	)		$	-		$	424

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

Eagle Rock Energy Partners, L.P.
Segment Summary
Operating Income
($ in thousands)
(unaudited)
		Three Months								Nine Months								Three Months
		Ended September 30,								Ended September 30,								Ended
		2009				2008				2009				2008				June 30, 2009
Midstream
Revenues:
Natural gas, NGLs, oil and condensate sales		$	139,359			$	286,722			$	425,983			$	869,135			$	138,213
Gathering, compression, processing and treating services			11,814				12,513				35,043				27,741				11,562
Other			-				-				1,619				2				1,616
Total revenues			151,173				299,235				462,645				896,878				151,391
Cost of natural gas and NGLs			109,945				237,742				358,802				726,400				115,640
Operating costs and expenses:
Operations and maintenance			14,139				14,019				42,626				39,026				14,311
Impairment			-				-				-				-				-
Depletion, depreciation and amortization			18,827				14,912				55,569				44,245				17,963
Total operating costs and expenses			32,966				28,931				98,195				83,271				32,274
Operating income (loss) from continuing operations			8,262				32,562				5,648				87,207				3,477
Discontinued Operations			26				601				266				1,436				(67	)
Operating income		$	8,288			$	33,163			$	5,914			$	88,643			$	3,410
Upstream (1)
Revenues:
Oil and condensate (2)		$	10,817			$	22,694			$	25,373			$	62,153			$	8,598
Natural gas (3)			2,221				11,168				7,081				27,725				2,965
NGLs (4)			4,382				8,059				10,152				24,354				3,544
Sulfur			-				13,057				-				25,524				-
Other			50				428				151				608				62
Total revenues			17,470				55,406				42,757				140,364				15,169
Operating costs and expenses:
Operations and maintenance			5,178				12,394				18,311				29,369				6,601
Sulfur disposal costs			348				-				1,505				-				717
Impairment			-				-				242				-				-
Other operating income			-				-				(3,552	)			-				(3,552	)
Depreciation, depletion and amortization			7,768				11,170				25,119				29,509				7,955
Total operating costs and expenses			13,294				23,564				41,625				58,878				11,721
Operating income		$	4,176			$	31,842			$	1,132			$	81,486			$	3,448
Minerals
Revenues:
Oil and condensate		$	2,228			$	4,390			$	6,136			$	12,489			$	2,232
Natural gas			749				3,044				2,454				8,818				840
NGLs			169				413				367				1,059				69
Lease bonus, rentals and other			904				9,546				1,831				12,240				358
Total revenues			4,050				17,393				10,788				34,606				3,499
Operating costs and expenses:
Operations and maintenance			203				427				972				1,352				298
Impairment			274				-				274				-				-
Depreciation, depletion and amortization			1,654				2,321				4,781				6,460				1,452
Total operating costs and expenses			2,131				2,748				6,027				7,812				1,750
Operating income		$	1,919			$	14,645			$	4,761			$	26,794			$	1,749
Corporate
Revenues:
Unrealized commodity derivative gains (losses)		$	(26,002	)		$	255,956			$	(127,568	)		$	(33,381	)		$	(97,044	)
Realized commodity derivative gains (losses)			17,170				(24,105	)			70,431				(64,388	)			22,483
Total revenues			(8,832	)			231,851				(57,137	)			(97,769	)			(74,561	)
General and administrative			10,449				9,893				34,882				31,161				11,895
Depreciation, depletion and amortization			337				194				768				585				218
Other operating expense			-				3,920				-				10,134				-
Operating income (loss)		$	(19,618	)		$	217,844			$	(92,787	)		$	(139,649	)		$	(86,674	)

(1) Includes operations from the Stanolind acquisition beginning on May 1, 2008.

(2) Revenues include a change in the value of product imbalances of $0 and $(260) for the three and nine months ended September 30, 2009, respectively. No changes in the value of the product imbalances were recognized during the three and nine months ended September 30, 2008.

(3) Revenues include a change in the value of product imbalances of $(780) and $(2,377) for the three and nine months ended September 30, 2009, respectively. No changes in the value of the product imbalances were recognized during three and nine months ended September 30, 2008.

(4) Revenues include a change in the value of product imbalances of $0 and $28 for the three and nine months ended September 30, 2009, respectively. No changes in the value of the product imbalances were recognized during the three and nine months ended September 30, 2008.

Eagle Rock Energy Partners, L.P.
Midstream Operations Information
(unaudited)
		Three Months								Nine Months								Three Months
		Ended September 30,								Ended September 30,								Ended
		2009				2008				2009				2008				June 30, 2009
Gas gathering volumes - (Average Mcf/d)
Texas Panhandle			134,690				159,254				140,725				154,190				143,281
East Texas/Louisiana			236,561				173,728				257,957				172,434				265,740
South Texas			66,680				80,097				85,496				81,228				90,395
Gulf of Mexico			131,527				-				115,591				-				98,619
Total			569,458				413,079				599,769				407,852				598,035
NGLs - (Net equity gallons)
Texas Panhandle			12,170,309				12,728,821				34,620,772				38,519,981				11,815,414
East Texas/Louisiana			5,830,042				6,387,873				14,672,928				17,321,951				6,166,467
South Texas			252,005				-				929,452				-				452,942
Gulf of Mexico			1,376,512				-				4,280,670				-				1,192,008
Total			19,628,868				19,116,694				50,223,152				55,841,932				19,626,831
Condensate - (Net equity gallons)
Texas Panhandle			9,938,819				10,023,469				25,944,824				25,767,353				9,813,579
East Texas/Louisiana			(31,131	)			380,164				870,508				1,074,135				466,348
South Texas			210,984				571,615				1,167,630				1,399,183				309,186
Gulf of Mexico			-				-				-				-				-
Total			10,118,672				10,975,248				27,982,962				28,240,671				10,589,113
Natural gas short position - (Average MMbtu/d)
Texas Panhandle			(4,685	)			(4,150	)			(5,524	)			(5,458	)			(5,748	)
East Texas/Louisiana			2,295				747				2,790				885				2,798
South Texas			1,784				500				928				1,500				500
Total			(606	)			(2,903	)			(1,806	)			(3,073	)			(2,450	)
Average realized NGL price - per Bbl
Texas Panhandle		$	33.55			$	66.36			$	29.33			$	67.62			$	29.82
East Texas/Louisiana		$	41.37			$	57.54			$	30.63			$	56.28			$	31.50
South Texas		$	30.71			$	83.16			$	28.74			$	77.70			$	29.68
Gulf of Mexico		$	37.70			$	-			$	31.79			$	-			$	29.57
Weighted average		$	35.63			$	64.26			$	29.87			$	64.26			$	30.22
Average realized condensate price - per Bbl
Texas Panhandle		$	65.13			$	106.43			$	57.79			$	105.03			$	59.08
East Texas/Louisiana		$	65.49			$	125.29			$	59.35			$	117.16			$	60.87
South Texas		$	58.06			$	112.20			$	45.02			$	106.54			$	55.55
Gulf of Mexico		$	65.67			$	-			$	54.50			$	-			$	48.20
Weighted average		$	65.03			$	108.23			$	57.57			$	106.09			$	59.07
Average realized natural gas price - per MMbtu
Texas Panhandle		$	2.78			$	8.81			$	2.98			$	8.85			$	2.66
East Texas/Louisiana		$	3.42			$	9.69			$	3.74			$	10.37			$	3.45
South Texas		$	3.06			$	9.42			$	3.66			$	9.58			$	3.31
Gulf of Mexico		$	3.46			$	-			$	4.64			$	-			$	3.87
Weighted average		$	3.09			$	9.22			$	3.42			$	9.29			$	3.09

Eagle Rock Energy Partners, L.P.
Upstream and Minerals Operations Information
(unaudited)
		Three Months						Nine Months						Three Months
		September 30,						September 30,						Ended
		2009			2008			2009			2008			June 30, 2009
Upstream
Production:
Oil and condensate (Bbl)			213,351			230,727			628,527			616,643			204,725
Gas (Mcf)			991,827			1,233,951			2,792,316			2,949,241			909,928
NGLs (Bbl)			128,379			119,664			375,215			365,761			123,057
Total Mcfe			3,042,207			3,336,297			8,814,768			8,843,665			2,876,620
Sulfur (Long ton)			27,634			25,816			96,063			71,772			39,823
Realized prices, excluding derivatives: (1)
Oil and condensate (per Bbl)		$	50.78		$	98.36		$	40.79		$	100.79		$	43.20
Gas (per Mcf)		$	3.25		$	9.05		$	3.47		$	9.41		$	2.95
NGLs (per Bbl)		$	34.67		$	67.35		$	27.07		$	66.58		$	27.44
Sulfur (per Long ton)					$	505.77					$	355.63		$	-
Operating statistics:
Operating costs per Mcfe (incl production taxes)		$	1.70		$	3.71		$	2.08		$	3.32		$	4.57
Operating costs per Mcfe (excl production taxes)		$	1.05		$	2.94		$	1.45		$	2.53		$	3.95
Operating Income per Mcfe		$	1.37		$	9.54		$	0.13		$	9.21		$	(1.06	)
Drilling program (gross wells):
Development wells			-			6			5			12			-
Completions			-			6			4			12			-
Workovers			4			1			10			1			4
Recompletions			-			3			4			7			3
Minerals
Production:
Oil and condensate (Bbl)			34,841			42,004			117,979			120,744			40,112
Gas (Mcf)			264,082			336,060			853,571			991,534			307,287
NGLs (Bbl)			5,739			6,981			15,110			17,381			3,660
Total Mcfe			507,562			629,970			1,652,106			1,820,288			569,919
Realized prices, excluding derivatives:
Oil and condensate (per Bbl)		$	63.96		$	104.62		$	52.87		$	103.47		$	55.69
Gas (per Mcf)		$	2.31		$	9.36		$	2.76		$	8.99		$	2.90
NGLs (per Bbl)		$	29.44		$	59.16		$	23.62		$	60.92		$	18.83

(1) Calculation does not include impact of product imbalances.

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								Nine Months								Three Months
		Ended September 30,								Ended September 30,								Ended
Net income (loss) to adjusted EBITDA		2009				2008				2009				2008				June 30, 2009
Net income (loss), as reported		$	(25,271	)		$	288,071			$	(102,603	)		$	32,723			$	(74,787	)
Depreciation, depletion and amortization expense			28,586				28,597				86,237				80,799				27,588
Impairment			274				-				516				-				-
Risk management interest related instruments-unrealized			5,308				501				(9,745	)			472				(11,954	)
Risk management commodity related instruments-unrealized, including amortization of commodity derivative costs			26,002				(255,956	)			127,568				33,381				97,044
Other operating (income) expenses (non-recurring)			-				3,920				(3,552	)			10,134				(3,552	)
Non-cash mark-to-market of Upstream product imbalances			780				-				2,609								(203	)
Restricted units non-cash amortization expense			904				1,427				5,024				4,147				1,889
Income tax provision (benefit)			5,841				(500	)			1,634				(1,497	)			(1,477	)
Interest - net including realized risk management instruments and other expense			9,612				9,849				31,569				28,458				10,701
Other (income)/expense			(725	)			(434	)			(1,835	)			(2,867	)			(550	)
Discontinued operations			(26	)			(594	)			(266	)			(1,451	)			(33	)
Adjusted EBITDA		$	51,285			$	74,881			$	137,156			$	184,299			$	44,666
Net income (loss) to distributable cash flow
Net income (loss), as reported		$	(25,271	)		$	288,071			$	(102,603	)		$	32,723			$	(74,787	)
Depreciation, depletion and amortization expense			28,586				28,597				86,237				80,799				27,588
Impairment			274				-				516				-				-
Risk management interest related instruments-unrealized			5,308				501				(9,745	)			472				(11,954	)
Risk management commodity related instruments-unrealized, including amortization of commodity derivative costs			26,002				(255,956	)			127,568				33,381				97,044
Capital expenditures-maintenance related			(4,392	)			(5,434	)			(12,011	)			(21,447	)			(4,836	)
Non-cash mark-to-market of Upstream product imbalances			780				-				2,609				-				(203	)
Restricted units non-cash amortization expense			904				1,427				5,024				4,147				1,889
Other operating (income) expenses (non-recurring)			-				3,920				(3,552	)			10,134				(3,552	)
Income tax provision (benefit)			5,841				(500	)			1,634				(1,497	)			(1,477	)
Other (income)/expense			(725	)			(434	)			(1,835	)			(2,867	)			(550	)
Cash income taxes			(635	)			(229	)			(992	)			(533	)			(280	)
Discontinued operations			(26	)			(594	)			(266	)			(1,451	)			(33	)
Distributable cash flow		$	36,646			$	59,369			$	92,584			$	133,861			$	28,849
Supplemental Information
($ in thousands)
		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008				2009
Amortization of commodity derivative costs			10,590				2,260				33,886				6,780				11,137

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