EAGLE ROCK ENERGY PARTNERS L P - FORM 8-K - EX-99.1 - EXHIBIT 99.1

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8-K - FORM 8-K - EAGLE ROCK ENERGY PARTNERS L P	a8-kcoverpage.htm
EX-23.1 - EXHIBIT 23.1 CONSENT - EAGLE ROCK ENERGY PARTNERS L P	exhibit231a.htm

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Item 6. Selected Financial Data.

The following table shows selected historical financial data from our audited consolidated financial statements for the five fiscal years from January 1, 2006 to December 31, 2010. The following financial data should be read in conjunction with our consolidated financial statements and the accompanying notes and "Management's Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere in this report.

Our historical results of operations for the periods presented below may not be comparable either from period to period or going forward, for the following reasons:


•	On March 27, 2006, Eagle Rock Pipeline completed a private placement of 5,455,050 common units for $98.3 million.

•

On March 31, 2006 and April 7, 2006, a wholly-owned subsidiary of Eagle Rock Energy Partners, L.P. acquired certain natural gas gathering and processing assets from Duke Energy Field Services, L.P. and Swift Energy Corporation, consisting of the Brookeland gathering system and processing plant, the Masters Creek gathering system and the Jasper NGL pipeline. We refer to this acquisition as the Brookeland Acquisition. As a result, our historical financial results for the periods prior to March 31, 2006 do not include the financial results from the operation of these assets.

•

On June 2, 2006, we purchased all of the partnership interests in Midstream Gas Services, L.P., which we refer to as the MGS Acquisition, an NGP affiliate, for approximately $4.7 million in cash and 809,174 (recorded value of $20.3 million) common units in Eagle Rock Pipeline. As a result, financial results for the periods prior to June 2006 do not include the financial results from the operation of these assets.


•	On April 30, 2007, we acquired certain fee minerals, royalties and working interest properties through purchases directly from Montierra Minerals & Production, L.P. and through purchases directly from NGP-VII Income Co-Investment Opportunities, L.P., which we refer to as the Montierra Acquisition, for 6,458,946 (recorded value of $133.8 million) of our common units and $5.4 million in cash.


•	On May 3, 2007, we acquired Laser Midstream Energy, L.P. and certain of its subsidiaries, which we refer to as the Laser Acquisition, for $113.4 million in cash and 1,407,895 (recorded value of $29.2 million) of our common units. As a result, financial results for the periods prior to May 2007 do not include the financial results from these assets.


•	On May 3, 2007, we completed the private placement of 7,005,495 common units for $127.5 million.


•	On June 18, 2007, we acquired certain fee minerals and royalties from MacLondon Energy, L.P., which we refer to as the MacLondon Acquisition, for $18.2 million, financed with 757,065 (recorded value of $18.1 million) of our common units and cash of $0.1 million.

•

On July 31, 2007, we completed the acquisition of Escambia Asset Co. LLC and Escambia Operating Co. LLC, which we refer to as the EAC Acquisition, for approximately $224.6 million in cash and 689,857 (recorded value of $17.2 million) of our common units, subject to post-closing adjustment. As a result, financial results for the periods prior to July 31, 2007 do not include the financial results from these assets.

•

On July 31, 2007, we completed the acquisition of Redman Energy Holdings, L.P. and Redman Energy Holdings II, L.P. and certain assets owned by NGP Income Co-Investment Opportunities Fund II, L.P. (a Natural Gas Partners affiliate) which we refer to as the Redman Acquisition, for 4,428,334 (recorded value of $108.2 million) common units and $84.6 million. As a result, financial results for the periods prior to July 2007 do not include the financial results from these assets.


•	On July 31, 2007, we completed the private placement of 9,230,770 common units for approximately $204.0 million.


•	On April 30, 2008, we completed the acquisition of Stanolind Oil and Gas Corp., which we refer to as the Stanolind Acquisition, for an aggregate purchase price of $81.9 million in cash. As a result, financial results for the periods prior to May 2008 do not include the financial results from these assets.


•	On October 1, 2008 we completed the acquisition of Millennium Midstream Partners, L.P. (“MMP”), which we refer to as the Millennium Acquisition, for approximately $183.6 million in cash and 3,362,280 (recorded value of $29.3 million) of our common units. As a result, financial results for the periods prior to October 2008 do not include the financial results from these assets.

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•

On May 24, 2010, we completed the sale of our Minerals Business (assets acquired from Montierra and MacLondon Acquisitions) to Black Stone for approximately $171.6 million, and resulted in a pre-tax gain in the disposition of approximately $37.7 million. We used these proceeds to pay down amounts outstanding under our senior secured credit facility. Operations related to these assets for 2010 have been recorded as part of discontinued operations. Financial information for these assets for 2007, 2008 and 2009 have been retrospectively adjusted to reflect as assets and liabilities held-for-sale and discontinued operations.


•	On June 30, 2010, we closed our Rights Offering, for which we received gross proceeds of $53.9 million. We used these proceeds to pay down amounts outstanding under our senior secured credit facility.


•	On September 30, 2010, we acquired certain additional interest in the Big Escambia Creek Field (and the nearby Flomaton and Fanny Church fields) from Indigo Minerals, LLC for approximately $3.9 million in cash on hand. As a result, financial results for the periods prior to October 2010 do not include the financial results from the assets.


•	On October 19, 2010, we completed the acquisition of certain natural gas gathering systems and related facilities from Centerpoint Energy Field Services, Inc. for $27.0 million of cash. As a result, financial results for the periods prior to October 19, 2010 do not include the financial results from these assets.

•

In February 2011, our Wildhorse Gathering System in our South Texas Segment was reclassified as assets and liabilities held for sale and its operations as discontinued. The Wildhorse Gathering System was acquired as part of the Millennium Acquisition on October 1, 2008. Financial information for this asset for 2008, 2009 and 2010 has been retrospectively adjusted to be reflected as assets and liabilities held for sale and discontinued operations.

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	Year Ended December 31, 2006			Year Ended December 31, 2007			Year Ended December 31, 2008			Year Ended December 31, 2009			Year Ended December 31, 2010
Statement of Operations Data:
Sales to external customers	$	502,394		$	760,853		$	1,266,992		$	679,220		$	741,095
Unrealized derivative gains/(losses)	(26,306		)	(130,773		)	207,824			(189,590		)	8,224
Realized derivative gains/(losses)	2,302			(3,061		)	(46,059		)	83,300			(17,010		)
Total revenues	478,390			627,019			1,428,757			572,930			732,309
Cost of natural gas and NGLs	377,580			553,248			886,019			470,099			468,304
Operating and maintenance expense	32,905			52,793			73,203			71,496			76,415
Taxes other than income	2,301			7,569			18,210			10,709			12,226
General and administrative expense	10,860			27,740			45,618			45,819			45,775
Other operating expense (income)	6,000			2,847			10,699			(3,552		)	—
Impairment expense	—			—			142,116			21,788			6,666
Goodwill impairment	—			—			30,994			—			—
Depreciation, depletion and amortization	43,220			72,531			108,356			108,530			106,398
Operating income (loss)	5,524			(89,709		)	113,542			(151,959		)	16,525
Interest (income) expense, net	28,604			49,764			65,044			27,751			42,171
Other (income) expense	(996		)	8,244			(363		)	136			(450		)
Income (loss) from continuing operations before income taxes	(22,084		)	(147,717		)	48,861			(179,846		)	(25,196		)
Income tax provision (benefit)	1,230			13			(1,459		)	989			(2,585		)
Income (loss) from continuing operations	(23,314		)	(147,730		)	50,320			(180,835		)	(22,611		)
Discontinued operations, net of tax	—			2,096			37,200			9,577			17,262
Net income (loss)	$	(23,314	)	$	(145,634	)	$	87,520		$	(171,258	)	$	(5,349	)
Loss (income) from continuing operations per common unit - diluted	$	(0.98	)	$	(2.16	)	$	0.67		$	(2.38	)	$	(0.26	)

Balance Sheet Data (at period end):
Property, plant and equipment, net	$	554,063		$	1,070,120		$	1,197,945		$	1,124,695		$	1,137,239
Total assets	779,901			1,609,927			1,773,061			1,534,818			1,349,397
Long-term debt	405,731			567,069			799,383			754,383			530,000
Net equity	291,987			726,768			727,715			530,398			579,113

Cash Flow Data:
Net cash flows provided by (used in):
Operating activities	$	54,992		$	91,832		$	138,785		$	77,228		$	94,128
Investing activities	(134,873		)	(475,790		)	(330,667		)	(37,284		)	73,545
Financing activities	71,088			426,816			102,816			(73,260		)	(175,446		)
Discontinued operations	—			15,113			38,430			18,132			9,090
Other Financial Data:
Cash distributions per common unit (declared)	$	0.2679		$	1.485		$	1.63		$	0.10		$	0.23
Adjusted EBITDA(a)	$	81,192		$	118,042		$	206,418		$	172,587		$	126,026

________________________

(a) See Part II Item 6. Selection Financial Data – Non-GAAP Financial Measures for reconciliation of “Adjusted EBITDA” to net cash flows from operating activities and net income (loss).

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Non-GAAP Financial Measures

We include in this filing the following non-GAAP financial measure: Adjusted EBITDA (as defined on page 80). We provide reconciliations of this non-GAAP financial measure to its most directly comparable financial measures as calculated and presented in accordance with GAAP.

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

We define 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. We use Adjusted EBITDA as a measure of our core profitability to assess the financial performance of our assets. Adjusted EBITDA is also 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, Eagle Rock's lenders under its revolving credit facility use a variant of Eagle Rock's Adjusted EBITDA in a compliance covenant designed to measure the viability of Eagle Rock and its ability to perform under the terms of its revolving credit facility; Eagle Rock, therefore, uses Adjusted EBITDA to measure its compliance with its revolving credit facility. We believe that investors benefit from having access to the same financial measures that our management team uses in evaluating performance. Adjusted EBITDA is useful in determining our 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 our executed derivative instruments and is independent of our assets’ performance or cash flow generating ability, we believe Adjusted EBITDA reflects more accurately our ability to generate cash sufficient to pay interest costs, support our level of indebtedness, make cash distributions to our unitholders and general partner and finance our maintenance capital expenditures. We further believe that Adjusted EBITDA also describes more accurately the underlying performance of our operating assets by isolating the performance of our 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 our financial statements a more accurate picture of our current assets’ cash generation ability, independently from that of assets which are no longer a part of our 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, we include in Adjusted EBITDA the actual settlement revenue created from our commodity hedges by virtue of transactions undertaken by us to reset commodity hedges to higher prices or purchase puts or other similar floors despite the fact that we exclude from Adjusted EBITDA any charge for amortization of the cost of such commodity hedge reset transactions or puts. For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP (accounting principles generally accepted in the United States), please read “Summary—Non-GAAP Financial Measures.”

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	Year Ended December 31, 2006			Year Ended December 31, 2007			Year Ended December 31, 2008			Year Ended December 31, 2009			Year Ended December 31, 2010
Reconciliation of “Adjusted EBITDA” to net cash flows provided by (used in) operating activities and net income (loss):
Net cash flows provided by (used in) operating activities	$	54,992		$	91,832		$	138,785		$	77,228		$	94,128
Add (deduct):
Discontinued operations, net of tax	—			2,096			37,200			9,577			17,262
Depreciation, depletion, amortization and impairment	(43,220		)	(72,531		)	(281,466		)	(130,318		)	(113,064		)
Amortization of debt issue cost	(1,114		)	(1,777		)	(958		)	(1,068		)	(1,305		)
Risk management portfolio value changes	(23,531		)	(136,132		)	199,339			(147,751		)	9,195
Reclassing financing derivative settlements	978			(1,667		)	(11,063		)	8,939			1,131
Other	(7,566		)	(8,541		)	(4,811		)	(2,878		)	(5,319		)
Accounts receivable and other current assets	1,432			13,215			(45,688		)	(18,810		)	(10,500		)
Accounts payable, due to affiliates and accrued liabilities	(8,777		)	(31,464		)	57,041			34,903			3,418
Other assets and liabilities	3,492			(665		)	(859		)	(1,080		)	(295		)
Net income (loss)	(23,314		)	(145,634		)	87,520			(171,258		)	(5,349		)
Add:
Interest (income) expense, net	30,383			44,587			38,282			41,350			35,058
Depreciation, depletion, amortization and impairment	43,220			72,531			281,466			130,318			113,064
Income tax provision (benefit)	1,230			13			(1,459		)	989			(2,585		)
EBITDA	51,519			(28,503		)	405,809			1,399			140,188
Add:
Risk management portfolio value changes	23,531			144,176			(180,107		)	177,061			(1,060		)
Restricted unit compensation expense	142			2,395			7,694			6,685			5,407
Non-cash mark-to-market Upstream imbalances	—			—			841			1,505			(746		)
Discontinued operations, net of tax	—			(2,096		)	(37,200		)	(9,577		)	(17,262		)
Other income	—			18			(1,318		)	(934		)	(501		)
Other operating expense (income) (a)	6,000			2,052			10,699			(3,552		)	—
ADJUSTED EBITDA(b)	$	81,192		$	118,042		$	206,418		$	172,587		$	126,026

________________________

(a) Includes $6.0 million to terminate an advisory fee for the year ended December 31, 2006, a settlement of arbitration for $1.4 million, severance to a former executive for $0.3 million and $1.1 million for liquidated damage related to the late registration of our common units during the year ended December 31, 2007; $10.7 million related to bad debt expense taken against our outstanding accounts receivable from SemGroup during the year ended December 31, 2008 and $3.6 million due to the recovery of $2.2 million of assets previously written off and the release of $1.4 million of liabilities assumed as part of our purchase price allocation for our acquisitions of Escambia Asset Co. LLC and Redman Energy Holdings, L.P. during the year ended December 31, 2009.

(b) Adjusted EBITDA excludes amortization of commodity hedge costs (including costs of hedge reset transactions) for the years ended December 31, 2010, 2009, 2008, 2007 and 2006 of $4.0 million, $48.4 million, $13.3 million, $8.2 million and $19.2 million, respectively. Including these amortization costs, our Adjusted EBITDA for the years ended December 31, 2010, 2009, 2008, 2007 and 2006, would have been $122.1 million, $124.2 million, $193.1 million, $109.8 million and $62.0 million, respectively.

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The following table summarizes our quarterly financial data for 2010:



	For the Quarters Ended
	March 31, 2010			June 30, 2010			September 30, 2010			December 31, 2010
	($ in thousands, except earnings per unit)
Sales of natural gas, NGLs and condensate	$	192,001		$	164,972		$	159,303		$	171,776
Gathering and treating services	12,483			16,230			12,093			9,802
Realized commodity derivative losses	(2,683		)	(5,813		)	(1,535		)	(6,979		)
Unrealized commodity derivative gains (losses)	13,478			41,405			(17,044		)	(29,615		)
Other revenues	36			(251		)	100			2,550
Total operating revenues	215,315			216,543			152,917			147,534
Cost of natural gas and NGLs	137,902			108,643			106,682			115,077
Operating and maintenance expense	22,405			22,732			21,323			22,181
General and administrative expense	13,011			12,806			10,674			9,284
Depreciation, depletion, amortization and impairment expense	27,444			30,599			29,324			25,697
Interest—net including realized risk management instrument	9,302			9,163			8,419			8,123
Unrealized interest rate derivative losses (gains)	4,822			4,354			3,112			(5,124		)
Income tax (benefit) provision	699			(425		)	(1,244		)	(1,615		)
Other expense (income)	(99		)	21			30			(402		)
(Income) loss from discontinued operations, net of tax	(4,152		)	(39,493		)	(166		)	26,549
Net income (loss)	$	3,981		$	68,143		$	(25,237	)	$	(52,236	)
Earnings per unit—diluted
Common units	$	0.06		$	0.96		$	(0.31	)	$	(0.62	)
Subordinated units	$	0.03		$	0.94		$	—		$	—
General partner	$	0.06		$	0.96		$	(0.33	)	$	—

During our fiscal year ended December 31, 2010, we recorded the following unusual or infrequently occurring items:

•

During our quarter ended June 30, 2010, we completed the sale of our Minerals Business for approximately $171.6 million, which resulted in a pre-tax gain in the disposition of approximately $37.7 million. We used these proceeds to pay down amounts outstanding under our senior secured credit facility. Operations related to these assets for 2010 have been recorded as part of discontinued operations.

•

On September 30, 2010, we acquired certain additional interest in the Big Escambia Creek Field (and the nearby Flomaton and Fanny Church fields) from Indigo Minerals, LLC for $3.9 million. During our fourth quarter ended December 31, 2010, we completed the acquisition of certain natural gas gathering systems and related facilities from Centerpoint Energy Field Services, Inc. for $27.0 million. We commenced recording results of operations relating to these acquisitions during our fourth quarter ended December 31, 2010.

•

During our fourth quarter ended December 31, 2010, we incurred impairment charges of $26.2 million, recorded as part of discontinued operations in our South Texas Segment and $0.1 million in our Upstream Segment. During our quarter ended September 30, 2010, we incurred impairment charges of $3.4 million related to our Upstream Segment. During our quarter ended June 30, 2010, we incurred impairment charges of $3.1 million related to our South Texas Segment. See Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview - Impairment for further discussion of our impairment charges during the year ended December 31, 2010.

•

We experienced significant fluctuations in our unrealized commodity derivative gains and losses from quarter to quarter as a result of the volatility that was experience by commodity prices during 2010. For example, we recorded unrealized gains of $13.5 million and $41.4 million during our quarters ended March 31, 2010 and June 30, 2010, respectively, while we recorded unrealized losses of $17.0 and $29.6 million during our quarters ended September 30, 2010 and December 31, 2010, respectively. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – General Trends and Outlook – Natural Gas Supply and Demand and Petroleum Supply, Demand and Outlook for further discussion regarding the volatility of commodity prices.

The following table summarizes our quarterly financial data for 2009:

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	For the Quarters Ended
	March 31, 2009			June 30, 2009			September 30, 2009			December 31, 2009
	($ in thousands, except earnings per unit)
Sales of natural gas, NGLs, condensate and sulfur	$	153,991		$	148,651		$	151,584		$	179,131
Gathering and treating services	11,288			11,214			11,478			10,025
Realized commodity derivative gains (losses)	30,778			22,483			17,170			12,869
Unrealized commodity derivative gains (losses)	(4,522		)	(97,044		)	(26,002		)	(62,022		)
Other revenues	42			1,678			50			88
Total operating revenues	191,577			86,982			154,280			140,091
Cost of natural gas and NGLs	129,144			111,539			105,309			124,107
Operating and maintenance expense	20,764			21,048			19,248			21,145
General and administrative expense	12,513			11,866			10,420			11,020
Other operating income	—			(3,552		)	—			—
Depreciation, depletion, amortization and impairment expense	28,033			25,726			26,522			50,037
Interest—net including realized risk management instrument	10,990			10,434			9,345			9,511
Unrealized interest rate derivative (gains) losses	(3,099		)	(11,954		)	5,308			(2,784		)
Income tax (benefit) provision	(2,771		)	(1,520		)	5,794			(514		)
Other expense (income)	183			68			(273		)	158
Discontinued operations, net of tax	(1,635		)	(1,886		)	(2,122		)	(3,934		)
Net loss	$	(2,545	)	$	(74,787	)	$	(25,271	)	$	(68,655	)
Earnings per unit—diluted
Common units	$	(0.03	)	$	(0.99	)	$	(0.33	)	$	(0.90	)
Subordinated units	$	(0.06	)	$	(1.02	)	$	(0.35	)	$	(0.93	)
General partner	$	(0.03	)	$	(0.99	)	$	(0.33	)	$	(0.90	)

During our fiscal year ended December 31, 2009, we recorded the following unusual or infrequently occurring items:

•

During our quarter ended December 31, 2009, we incurred impairment charges of $13.7 million in our Midstream Business and $7.9 million in our Upstream Segment. During our quarter ended March 31, 2009, we recorded an impairment charge of $0.2 million in our Upstream Segment and in our quarter ended September 30, 2009, we recorded an impairment charge of $0.3 million in our Minerals Segment as a result of the continued decline in natural gas prices. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – Impairment for further discussion of our impairment charges during the year ended December 31, 2009.

•

We experienced significant fluctuations in our unrealized commodity derivative gains and losses from quarter to quarter as a result of the volatility that was experience by commodity prices during 2009. For example, we recorded unrealized losses of $62.0 million, $26.0 million and $97.0 million during our quarters ended December 31, 2009, September 30, 2009 and June 30, 2009, respectively, while in our quarter ended March 31, 2009, we only recorded an unrealized loss of $4.5 million. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – General Trends and Outlook – Natural Gas Supply and Demand and Petroleum Supply, Demand and Outlook for further discussion regarding the volatility of commodity prices.


•	During our quarter ended June 30, 2009, we recorded other operating income of $3.6 million due to the recovery of $2.2 million of assets previously written off and the release of $1.4 million of liabilities assumed as part of our purchase price allocation for our acquisitions of Escambia Asset Co. LLC and Redman Energy Holdings, L.P.


•	Quarterly amounts generated during 2009 by our Minerals Business have been retrospectively adjusted to be included within discontinued operations as a result of the sale of our Minerals Business during our second quarter ended June 30, 2010.

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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion analyzes our financial condition and results of operations and should be read in conjunction with our historical consolidated financial statements and notes included elsewhere in this Annual Report.

OVERVIEW

We are a domestically-focused, growth-oriented, publicly-traded Delaware limited partnership engaged in the following two businesses:


•	Midstream Business—gathering, compressing, treating, processing and transporting of natural gas; fractionating and transporting of natural gas liquids (“NGLs”); and the marketing of natural gas, condensate and NGLs; and


•	Upstream Business—acquiring, developing and producing oil and natural gas property interests.

We report on our businesses in six accounting segments.

We conduct, evaluate and report on our Midstream Business within four distinct segments—the Texas Panhandle Segment, the East Texas/Louisiana Segment, the South Texas Segment and the Gulf of Mexico Segment. Our Texas Panhandle Segment consists of gathering and processing assets in the Texas Panhandle. Our East Texas/Louisiana Segment consists of gathering and processing assets in East Texas/Northern Louisiana. Our South Texas Segment consists of gathering systems and related compression and processing facilities in South Texas. Our Gulf of Mexico Segment consists of gathering and processing assets in Southern Louisiana, the Gulf of Mexico and Galveston Bay. During the year ended December 31, 2010, our Midstream Business generated operating income from continuing operations of $45.1 million, compared to operating income from continuing operations of $4.7 million generated during the year ended December 31, 2009, an increase of $40.4 million. In addition, during the year ended December 31, 2010, our Midstream Business incurred impairment charges of $29.3 million, of which $26.2 million is included as discontinued operations in our South Texas Segment, compared to $13.7 million during the year ended December 31, 2009.

We conduct, evaluate and report on our Upstream Business as one segment. Our Upstream Segment includes operated wells in Escambia County, Alabama as well as two treating facilities, one natural gas processing plant and related gathering systems. The Upstream Segment also includes operated and non-operated wells that are primarily located in West, East and South Texas in Ward, Crane, Pecos, Henderson, Rains, Van Zandt, Limestone, Freestone and Atascosa Counties. During the year ended December 31, 2010, our Upstream Business generated operating income of $28.0 million compared to an operating loss of $3.5 million generated during the year ended December 31, 2009. Of important note, our Upstream Business generated net revenue of $6.1 million from the sale of sulfur during the year ended December 31, 2010, compared to expense of $2.2 million during the year ended December 31, 2009. In addition, during the year ended December 31, 2010, our Upstream Business incurred impairment charges related to its unproved properties of $3.4 million, compared to $8.1 million for its proved properties during the year ended December 31, 2009.

The final segment that we report on is our Corporate Segment, which is where we account for our commodity derivative/hedging activity, intercompany eliminations and our general and administrative expenses. During the year ended December 31, 2010, our Corporate Segment generated an operating loss of $56.1 million compared to an operating loss of $153.2 million generated during the year ended December 31, 2009. Within these numbers were net losses, realized and unrealized, on commodity derivatives of $8.8 million during the year ended December 31, 2010 compared to losses, realized and unrealized, on commodity derivatives of $106.3 million during the year ended December 31, 2009.

On May 24, 2010, as part of the Recapitalization and Related Transactions (discussed below), we sold our Minerals Business, which had been broken out as a separate segment in prior filings. As a result of the sale, financial information related to the Minerals Business for 2010 has been classified as discontinued operations and financial information for previous years has been retrospectively adjusted to classify assets and liabilities as held-for-sale and operations as discontinued. For a further discussion of the sale of our Minerals Business, see Note 19, to our consolidated financial statements included in Part II, Item 8. Financial Statement and Supplementary Data starting on page F-1 of this Annual Report.

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Impairment

For the years ended December 31, 2010, 2009 and 2008, we determined that we needed to record an impairment charge for certain plants and pipelines within our Midstream Business and certain proved and unproved properties within our Upstream Business. As a result, we incurred impairment charges during the year ended December 31, 2010 of (i) $3.1 million in our South Texas Segment due to the termination of a significant gathering contract on our Raymondville system, (ii) $26.2 million, recorded within discontinued operations in our South Texas Segment, due to an anticipated decline in volumes on our Wildhorse gathering system, (iii) $3.4 million in our Upstream Segment related to certain fields in its unproved properties which we determined are not technologically feasible to develop and (iv) $0.1 million of proved properties in our Upstream segment due to adjustments to reserves. During the year ended December 31, 2009, we determined that we needed to record an impairment charge for certain plants and pipelines within our Midstream Business and certain fields within our proved properties within our Upstream Segment. As a result, we incurred impairment charges of (i) $13.7 million in our Midstream segment due to reduced throughput volumes as our producer customers curtailed their drilling activity in response to lower natural gas prices, and (ii) $8.1 million in our Upstream Segment, of which, $7.9 million was a result of a decline in natural gas prices, production declines and lower natural gas liquids yields at our Flomaton field and $0.2 million in other fields due to lower natural gas prices. During the year ended December 31, 2008, we recorded impairment charges related to certain processing plants, pipelines and contracts in its Midstream business of $35.1 million due to the substantial decline in commodity prices in the fourth quarter as well as declining drilling activity by its producer customers and $107.0 million in our Upstream Segment. Due to the impairment charge recorded in our Upstream Segment, we assessed our goodwill balance for impairment and recorded an impairment charge of $31.0 million for the year ended December 31, 2008.

Pursuant to generally accepted accounting principles in the United States, our impairment analysis does not take into account the value of our commodity derivative instruments, which generally increase as the estimates of future prices decline. Further declines in commodity prices and other factors could result in additional impairment charges and changes to the fair value of our derivative instruments.

Acquisitions

Historically, we have grown through acquisitions. On September 30, 2010, we acquired certain additional interests in

the Big Escambia Creek, Flomaton and Fanny Church fields in South Alabama from Indigo Minerals, LLC for $3.9 million. These interests are in wells in which we currently own a significant interest and are nearly 100% operated by us. On October 19, 2010, we acquired certain natural gas gathering systems and related facilities located primarily in Wheeler and Hemphill Counties in the Texas Panhandle (the "East Hemphill System") from Centerpoint Energy Field Services, Inc ("CEFS"). The purchase price for the assets was $27.0 million, subject to customary adjustments. We did not make any acquisitions during the year ended December 31, 2009. Refer to Part I, Item 1. Business – Table of Acquisitions/Dispositions in the past five years for a history of acquisitions.

Going forward, we will continue to assess acquisition opportunities for their potential accretive value. Our ability to complete acquisitions will depend on our ability to finance the acquisitions, either through the issuance of additional debt or equity securities or the incurrence of additional debt under our credit facilities, on terms acceptable to us.

Other Matters

Unscheduled Shut-Down of Third-Party Owned and Operated Eustace Processing Facility - On August 11, 2010, the Eustace processing facility, which processes substantially all of our East Texas oil and gas production, was shut down due to events stemming from an electrical failure. As a result, we were unable to produce from our East Texas upstream properties from that date through the end of the year. We estimate the shut-down of the Eustace facility impacted our Upstream Segment's net revenues by approximately $7.1 million in 2010. We recouped $3.0 million of this loss in 2010 under our business interruption insurance, which was recognized as other revenue, and expect to recoup an additional $2.0 million (to reach the total maximum recovery of $5.0 million under our business interruption insurance policy) in the first quarter of 2011. On March 10, 2011, the third-party operator of the Eustace Processing Facility was in the process of returning the facility to service.

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Recent Transactions

Recapitalization and Related Transactions

On December 21, 2009, we announced that we, through certain of our affiliates, had entered into definitive agreements

with affiliates of Natural Gas Partners ("NGP" and collectively with such affiliates, the “NGP Parties”) and Black Stone

Minerals Company, L.P. to improve our liquidity and simplify our capital structure. The definitive agreements included: (i) a

Securities Purchase and Global Transaction Agreement, entered into between us and the NGP Parties, including our general

partner entities controlled by NGP, and (ii) a Purchase and Sale Agreement (the “Minerals Business Sale Agreement”), entered

into between us and Black Stone for the sale of our Minerals Business. The Securities Purchase and Global Transaction

Agreement was amended and restated on January 12, 2010 to allow for greater flexibility in the payment of the contemplated

transaction fee to Eagle Rock Holdings, L.P. ("Holdings"), which is controlled by NGP (we refer to the amended Securities

Purchase and Global Transaction Agreement throughout this document as the “Global Transaction Agreement”).

On May 21, 2010, a majority of our unitholders who are not affiliated with our general partner approved, among other

things, the Global Transaction Agreement, which contemplated a series of transactions that sought to simplify and recapitalize the Partnership, including:


•	the simplification of our capital structure through the contribution, and resulting cancellation, of our incentive distribution rights and all 20,691,495 subordinated units held by Holdings, which occurred on May 24, 2010;

•

the sale of all of our fee mineral and royalty interests, as well as our equity investment in Ivory Working Interests, L.P. (collectively, the “Minerals Business”) to Black Stone Minerals Company, L.P., which was completed on May 24, 2010 and for which we received net proceeds of $171.6 million. We retained approximately $2.9 million of cash received from net revenues received from the Minerals Business after the effective date of the sale, making our total proceeds from the sale of the Minerals Business $174.5 since January 1, 2010;


•	a rights offering, which was launched on June 1, 2010 and expired on June 30, 2010, and for which we received gross proceeds of $53.9 million and issued 21,557,164 common units and warrants;

•

the GP Acquisition Option, exercisable by the issuance of 1,000,000 newly-issued common units to Holdings, to capture the value of the controlling interest in us through (a) acquiring our general partner entities from Holdings and immediately thereafter eliminating our 844,551 outstanding general partner units and (b) reconstituting our Board to allow our common unitholders not affiliated with NGP to elect the majority of our directors. On July 27, 2010, notice was given to Holdings of our intention to exercise the GP Acquisition Option, and we closed the transaction on July 30, 2010. In connection with the completion of the GP Acquisition Option, our board of directors was expanded to include two additional independent directors who were appointed by the conflicts committee on July 30, 2010; and


•	the obligation of NGP, at the sole discretion of our conflicts committee, to purchase up to $41.6 million, at a price of $3.10 per unit, of an Eagle Rock Energy equity offering. Our conflicts committee determined that it was not in our best interests to require NGP to purchase equity at the $3.10 per unit price, and the obligation expired on September 21, 2010.

Credit Facility Amendment

On March 8, 2010, we entered into the Second Amendment (the “Credit Facility Amendment”) to our credit

agreement, dated as of December 13, 2007, with Wachovia Bank, N.A., Bank of America, N.A., HSH NordBank AG, New

York Branch, The Royal Bank of Scotland, PLC, BNP Paribas and the other lenders party thereto. In connection with our

unitholders' approval of the Global Transaction Agreement and related matters, the Credit Facility Amendment became

effective.

The Credit Facility Amendment modified the definition of “Change in Control” in such a way that our exercise of the

GP Acquisition Option did not trigger a “Change in Control” event and potential default; see “General Partner Acquisition

Option.” In addition to modifying the definition of “Change in Control,” the Credit Facility Amendment also:

•

reduced the maximum permitted Senior Secured Leverage Ratio (as such term is defined in our credit agreement) from 4.25 to 1.0 under the current credit agreement to 3.75 to 1.0 (and from 4.75 to 1.0 to 4.25 to 1.0 for specified periods following certain permitted acquisitions). The Senior Secured Leverage Ratio covenant is only relevant if we have unsecured senior or subordinated notes outstanding;

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•	obligated us to use $100 million of the proceeds from the sale of our Minerals Business (described above) to make a mandatory prepayment towards our outstanding borrowings under the revolving credit facility, which mandatory prepayment was made on May 25, 2010; and


•	reduced, upon such mandatory prepayment, our borrowing capacity under the revolving credit facility by the $100 million amount of such mandatory prepayment; however, this did not impact our availability under our revolving credit facility because it is limited by compliance with financial covenants.

•

The Credit Facility Amendment further clarified that the proceeds from the sale of our Minerals Business in excess of$100 million may be used to immediately reduce debt, but did not result in a mandatory prepayment unless such proceeds were not reinvested in Property (as defined in our credit agreement) within the 270-day post-closing period (i.e. by February 18, 2011) provided in our credit agreement. On May 28, 2010, we repaid an additional $72 million towards our outstanding borrowings under the revolving credit facility from proceeds from the sale of our Minerals Business. We do not anticipate any further reductions in commitments under the Credit Facility resulting from the sale of the Minerals Business.

Borrowing Base Redetermination

On October 19, 2010, we announced that the borrowing base under our revolving credit facility, which relates to our

Upstream Business, was set at $140 million as part of our regularly scheduled semi-annual borrowing base redetermination. This was an increase from the $130 million our borrowing base was set at during the April 2010 redetermination. The redetermined borrowing base was effective October 1, 2010, with no additional fees or increase in interest rate spread incurred.

How We Evaluate Our Operations

Our management uses a variety of financial and operational measurements to analyze our performance. We view these measurements as important factors affecting our profitability and review these measurements on a monthly basis for consistency and trend analysis. These measures include volumes, margin, operating expenses and Adjusted EBITDA (defined on page 78) on a company-wide basis.

Volumes (by Business)

Midstream Volumes. In our Midstream Business, due to the natural production decline of the wells connected to our systems we must continually obtain new supplies of natural gas to maintain or increase throughput volumes on our gathering and processing systems in order to achieve our distribution objectives. Our ability to maintain existing supplies of natural gas and obtain new supplies is impacted by (1) the level of workovers or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to our pipelines, (2) our ability to compete for volumes from successful new wells in other areas and (3) our ability to obtain natural gas that has been released from other commitments. We routinely monitor producer activity in the areas served by our gathering and processing systems to pursue new supply opportunities.

We rely on producer drilling activity to maintain and grow our midstream volumes. Generally, producer drilling activity is correlated to the current and expected price of natural gas, and to the current and expected price of crude oil in producing basins that have liquids-rich gas reservoirs. As such, throughput volume in our existing midstream assets will typically increase in times of rising gas prices and will typically decrease in times of falling gas prices, except that in liquids-rich basins we may continue to experience a high level of drilling activity during periods when oil prices are high, even if gas prices are relatively low.

Upstream Volumes. In the Upstream Segment, we continually monitor the production rates of the wells we operate. This information is a critical indicator of the performance of our wells, and we evaluate and respond to any significant adverse changes. We employ an experienced team of engineering and operations professionals to monitor these rates on a well-by-well basis and to design and implement remediation activities when necessary. We also design and implement workover and drilling operations to increase production in order to offset the natural decline of our currently producing wells.

Margin

Commodity Pricing. The margins in our Midstream Business generally are positively correlated to NGL and condensate prices, and may be adversely impacted to the extent the price of NGLs decline in relation to the price of natural gas. We refer to the price of NGLs in relation to the price of natural gas as the "fractionation spread." In our Upstream Segment,

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increases in crude oil, natural gas and NGL prices will generally have a favorable impact on our revenues, conversely, decreases in crude oil, natural gas and NGL prices will generally unfavorably impact our revenue.

Risk Management. We conduct risk management activities to mitigate the effect of commodity price and interest rate fluctuations on our cash flows. Our primary method of risk management in this respect is entering into derivative contracts. The impact of our risk management activities are captured in our Corporate Segment. For a further discussion of our risk management activities, see Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Operating Expenses

Midstream Operating Expenses. We monitor midstream operating expenses as a measure of the operating efficiency of our field operations. Direct labor, repair and maintenance, utilities and contract services comprise the most significant portion of our operating expenses. These expenses are largely independent of the volumes through our systems, but fluctuate depending on the activities performed during a specific period.

Upstream Operating Expenses. We monitor and evaluate our Upstream Segment operating costs routinely, both on a total cost and unit cost basis. Many of the operating costs we incur are not directly related to the quantity of hydrocarbons that we produce, so we strive to maximize our production rates in order to improve our unit operating costs. The most significant portion of our Upstream Segment operating costs is associated with the operation of the Big Escambia Creek treating and processing facilities. These facilities are overseen by members of our midstream engineering and operations staff. The majority of the cost of operating these facilities is independent of their throughput. This includes items such as labor, chemicals, utilities and materials.

Adjusted EBITDA

See discussion of Adjusted EBITDA in Part II, Item 6. Selected Financial Data.

General Trends and Outlook

We expect our business to be affected by the following key trends. This expectation is based on assumptions made by us and information currently available to us; however, our actual results may vary materially from our expectations.

Although the global economic weakness that began in late 2008 and continued through 2009 has improved, we expect to continue to feel its effects for several years. Specifically, we expect relatively low economic growth in the United States and other developed economies and relatively high levels of unemployment. We expect the current low interest rate environment to persist throughout 2011 and that credit will remain widely available. However, we expect international sovereign credit concerns and domestic local and state credit concerns to continue to be a source of uncertainty in global credit markets. We further believe that persistent unemployment and housing concerns of U.S. consumers will result in sluggish domestic demand, and that business investment in capacity expansion will remain depressed until demand increases. The issues of low demand and excess productive capacity may be worsened by fiscal austerity measures taken to address national budget deficits.

Within the developing economies, we expect levels of growth to continue at pre-recession levels. In the case of China, many economists believe that its economy is growing at an annual rate of 10% and showing signs of significant inflation. We believe that the Chinese government will take steps to attempt to reduce inflation, but that the factors that are influencing the high level of growth in the Chinese economy will generally continue. The increased demand for commodities that this growth is expected to cause has significant implications for commodity prices in general and for oil prices, in particular.

Natural Gas Supply and Demand

Natural gas prices are more dependent than crude oil prices on regional supply and demand due to the relative difficulty in transporting natural gas from producing to consuming regions of the world. In the United States, where we produce natural gas, the outlook for natural gas demand has improved since the depths of the recession, but we do not expect significant increases in the demand for natural gas during 2011. Over the longer term, however, we believe that the environmental advantages that natural gas has over coal will result in the construction of additional natural gas-fired electricity generation capacity, both for new capacity and to replace aging coal-fired facilities.

During 2010, natural gas prices remained relatively low compared to the prices experienced prior to the recession. Our expectation was that these low prices would lead to reduced gas well drilling and lower natural gas supply, and that the resumption of growth in the United States economy would provide support to natural gas prices. This has not yet occurred,

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however, as operators continue to drill gas wells in emerging shale gas plays such as the Haynesville, Marcellus and Eagle Ford in order to place their leases into production before they expire. In addition, producers have increased their drilling in liquids-rich gas plays such as the Granite Wash and the Eagle Ford in order to extract the more valuable NGLs from the raw gas stream. We now expect that these plays will continue to provide a source of future natural gas supply for the next several years and expect prices to remain near their current level for some time.

In addition to North American drilling activity, imported liquefied natural gas ("LNG") has the potential to increase the supply of natural gas in the United States. At the end of 2010, LNG imports were approximately 1.0 Bcf/d which some forecasters previously predicted might increase to as much as 4.0 Bcf/d in the next few years. However, some of the large LNG projects that are under construction to provide this supply are reported to have been delayed due to the global economic weakness, and the relatively low price of natural gas in the United States compared to other countries that import natural gas make a significant increase in LNG imports in the U.S. unlikely. Recently, there has been some speculation in the industry that the United States may begin to export LNG.

Crude Oil Supply, Demand and Outlook

The majority of the world's crude oil production and reserves is controlled by foreign governments and state-owned oil companies. Many of these countries rely on crude oil exports to fund the majority of their governmental expenditures, and in some of these the export of crude oil represents the bulk of their economic output. Certain exporting countries have seen declines in their production rates due to low levels of capital re-investment in their oil industry. We believe that, while some oil exporting countries will be able to increase their production to meet future increases in demand, that others will have a difficult time maintaining their production levels and that this may result in an undersupplied market for crude oil within a few years.

There are several factors which influence the demand for crude oil, but ultimately the continued growth of the developing economies will result in much greater demand for crude oil. It is uncertain how quickly demand will exceed supply, but we believe that crude oil prices may remain high relative to historical averages or further strengthen over the next one to two years.

Natural gas liquids prices tend to have a high correlation to crude oil prices, especially for propane and heavier NGLs, and we expect this trend to continue. Ethane prices historically have been less correlated to crude oil than have the heavier NGLs. Ethane demand is primarily driven by global petrochemical production and specifically by its use as a feedstock for ethylene. Ethane's low price relative to heavier ethylene feedstocks such as naptha has resulted in strong worldwide demand, and chemical manufacturers have recently announced projects to increase their ethylene production capacity using ethane. We believe this trend will provide support to ethane prices throughout 2011. The increase in drilling activity focused on liquids-rich areas, however, is projected to substantially increase the supply of ethane, which could result in downward pressure on ethane prices over the longer-term.

Sulfur Supply, Demand and Outlook

Much of the natural gas that we produce in our Upstream Segment contains high, naturally-occurring concentrations of hydrogen sulfide. This is a corrosive, poisonous gas that must be removed from the natural gas stream before it can be processed for NGL extraction or sale. The process of removing the hydrogen sulfide yields a large amount of elemental sulfur, which we sell or otherwise dispose of. The process of removing hydrogen sulfide from natural gas, and similar processes for the removal of hydrogen sulfide from sour crude oils (prior to refining), is the primary source of sulfur production in the United States and the world.

The primary use of sulfur is the production of sulfuric acid, and one of the major uses of sulfuric acid is the production of phosphoric acid. Phosphoric acid is a key raw material in the manufacture of phosphate fertilizers. Therefore, one of the major factors influencing the demand for sulfur is the demand for fertilizer. The region around Tampa, Florida contains a large amount of fertilizer manufacturing facilities, and Tampa also serves as an export port for sulfur. For many years, the supply of sulfur was greater than the available demand, such that Tampa prices fluctuated within a narrow band of $20 to $40 per long ton. Depending on a seller's proximity to Tampa, transportation charges may have equaled or exceeded the selling price of the sulfur under this pricing environment.

Beginning in the second half of 2007, global demand for fertilizer increased significantly, and as a result, Tampa prices also rose to record levels. In late 2008, sulfur prices at Tampa peaked at over $600 per long ton. The global economic recession greatly reduced fertilizer demand; however, much of this demand has returned. As with many commodities, the developing economies are responsible for much of this demand growth. By the end of 2008, Tampa sulfur prices had fallen to $0 (zero dollars) per long ton, and they remained low throughout 2009. By the first quarter of 2010, prices had risen to $90 per

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long ton and ended the year at over $150 per long ton. We expect demand to remain relatively strong in 2011, but not as great as that in 2007. Nevertheless, over the next few years, continued rapid growth in emerging economies could result in supply/demand imbalances that could lead to the types of prices spikes we experienced in 2007.

Outlook for Interest Rates and Inflation

In response to the global recession which began in 2008, the governments and central banks of the world's large economies adopted fiscal and monetary policies that introduced unprecedented amounts of liquidity into their financial systems. Most of these efforts have been substantially completed and, other than certain monetary efforts in the United States, we believe it is unlikely that significant amounts of additional liquidity will be injected. Because these economies have excess productive capacity due to the reduction in demand caused by the recession, this liquidity has not led to inflationary pressures. In addition, some of these economies have already begun, or are contemplating, tightening their fiscal policies. This reduction in spending is also likely to reduce inflationary pressures. Eventually, however, as the economies recover and demand increases, policymakers will need to remove excess liquidity from their economies to avoid significant levels of inflation. This will be a delicate task and will require a high degree of coordination among central banks.

It is impossible to predict when these policy changes will occur or how successful they will be. In the near term, however, we expect that unemployment and underemployment will remain high, and this will act as a brake on inflation. As inflationary pressures arise, however, we expect that one of the responses will be higher interest rates, and this could increase our interest expenses.

Impact of Regulation of Greenhouse Gas Emissions

The operations of and use of the products produced by the natural gas and oil industry are sources of emissions of certain greenhouse gases ("GHGs"), namely carbon dioxide and methane. Regulation of GHG emissions has not had an impact on our operations in the past, and the regulation of our GHG emissions as such has not occurred. However, there is a trend towards government-imposed limitation of GHG emissions at the state, regional, and federal level.

The United States Environmental Protection Agency ("EPA"), by virtue of a 2007 Supreme Court decision, was deemed to have authority to regulate carbon dioxide and other GHG emissions under the Clean Air Act, and they are drafting and preparing to implement regulations. It is possible that legislation will be proposed to amend the Clean Air Act to exclude GHGs, although the probability of the enactment of such legislation is uncertain.

In addition, in 2009 there was a significant effort in the United States Congress to enact legislation to establish a cap-and-trade system as a means to regulate GHG emissions. A cap-and-trade bill was approved by the House of Representatives, but was not approved in the Senate. Given the House of Representatives is now under control of the Republican Party which has historically opposed GHG regulation, the probability of of enactment of a cap-and-trade bill during the next two years at least is extremely low. Because of the uncertainty of the nature of any potential future federal GHG regulations at this time, we are unable to forecast how future regulation of GHG emissions would negatively impact our operations. We will continue to monitor regulatory developments and to assess our ability to reasonably predict the economic impact of these developments on our business.

The commercial risk associated with the exploration and production of fossil fuels lies in the uncertainty of regulations that may affect our customers, which could affect the demand for crude oil and natural gas. Such an impact on demand could have an adverse impact on the demand for our services, and could have an impact on our financial condition, results of operations and cash flows.

On the other hand, when burned, natural gas produces less greenhouse gas emissions than other fossil fuels, such as refined petroleum products or coal. As a result, climate change legislation or GHG emissions regulations could create an increased demand for natural gas.

Critical Accounting Policies

Conformity with accounting principles generally accepted in the United States ("GAAP") requires management to make estimates and judgments that affect the amounts reported in the financial statements and notes. On an ongoing basis, we make and evaluate estimates and judgments based on management's best available knowledge of previous, current, and expected future events. We base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates, and estimates are subject to change due to modifications in the underlying conditions or assumptions. Currently, we do not foresee any reasonably likely changes to our

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current estimates and assumptions which would materially affect amounts reported in the financial statements and notes. We have selected the following critical accounting policies that currently affect our financial condition and results of operations for discussion.

Successful Efforts. We utilize the successful efforts method of accounting for our oil and natural gas properties. Leasehold costs are capitalized when incurred. Costs incurred to drill and complete development wells are capitalized. Unproved properties are assessed periodically within specific geographic areas and, if necessary, impairments are charged to expense. Geological and geophysical expenses and delay rentals are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if the well is determined to be unsuccessful. We carry the costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well as long as we are making sufficient progress towards assessing the reserves and the economic and operating viability of the project.

Depletion of producing oil and natural gas properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for acquisition costs using all proved reserves. U.S. GAAP authoritative guidance requires that acquisition costs of proved properties be amortized on the basis of all proved reserves (developed and undeveloped) and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves. Since our units of production depletion and amortization rate are a function of our proved reserves, we experience a higher depletion and amortization rate than we would if we claimed undeveloped or non-producing reserves.

Upon sale or retirement of complete fields of depreciable or depleted property, the book value thereof, less proceeds or salvage value, is charged or credited to income.

We assess proved oil and natural gas properties in our Upstream Segment for possible impairment when events or circumstances indicate that the recorded carrying value of the properties may not be pre-tax recoverable. We recognize an impairment loss as a result of a triggering event and when the estimated undiscounted pre-tax future cash flows from a property are less than the carrying value. If impairment is indicated, the fair value is compared to the carrying value for determining the amount of the impairment loss to record. Estimated future cash flows are based on management's expectations for the future and include estimates of oil and natural gas reserves and future commodity prices and operating costs. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate property impairment. During the year ended December 31, 2010, we incurred $0.1 million of impairment charges in our Upstream segment as a result of adjustments to our reserves. During the year ended December 31, 2009, we incurred impairment charges of $8.1 million in our Upstream segment as a result of a decline in natural gas prices, production declines and lower natural gas liquids yields. During the year ended December 31, 2008, we incurred impairment charges related to certain fields of $107.0 million in our Upstream Segment due to the substantial decline in commodity prices during the fourth quarter of 2008.

Unproved properties that are individually insignificant are amortized. Unproved properties that are individually significant are assessed for impairment on a property-by-property basis. If considered impaired, costs are charged to expense when such impairment is deemed to have occurred. During the year ended December 31, 2010, we recorded $3.4 million in impairment charges for certain undrilled wells within our Upstream Segment's unproved properties because we determined it would not be economical to develop these unproved locations.

Our estimates of proved reserves are based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic conditions. Annually, and on other occasions, Cawley, Gillespie & Associates, Inc. prepares an estimate of the proved reserves on all our properties, based on information provided by us.

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. We prepare our reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing their reserve reports. The accuracy of our reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves.

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Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of natural gas, natural gas liquids and oil eventually recovered.

Revenue and Cost of Goods Sold Recognition. Within our Midstream and Upstream businesses, sales of oil, natural gas, NGLs and sulfur are recognized when their is persuasive evidence of an arrangement, the product has been delivered, the sales price is fixed and determinable and collection of revenue from the sale is reasonably assured. In our Midstream Business, we record revenue and cost of goods sold on the gross basis for those transactions where we act as the principal and take title to natural gas, NGLs or condensates that is purchased for resale. Our service-related revenue is recognized in the period when the service is provided and includes our fee-based service revenue for services such as transportation, compression, treating and processing.

Risk Management Activities. We have structured our hedging activities in order to minimize our commodity pricing and interest rate risks and to help maintain compliance with certain financial covenants in our revolving credit facility. These hedging activities rely upon forecasts of our expected operations and financial structure over the next few years. If our operations or financial structure are significantly different from these forecasts, we could be subject to adverse financial results as a result of these hedging activities. We mitigate this potential exposure by retaining an operational cushion between our forecasted transactions and the level of hedging activity executed. Based on our current production estimates, we have hedged approximately 91% of our 2011 expected hedgeable crude, condensate and natural gas liquids (heavier than propane) volumes and 63% of our natural gas and ethane production. Similarly based on the production estimates in our current forecast, we have hedged approximately 78% of our 2012 expected hedgeable crude, condensate and natural gas liquids (heavier than propane) volumes and 50% of our natural gas and ethane production.

From the inception of our hedging program, we used mark-to-market accounting for our commodity hedges and interest rate swaps. We record monthly realized gains and losses on hedge instruments based upon cash settlement information. The settlement amounts vary due to the volatility in the commodity market prices throughout each month. We also record unrealized gains and losses monthly based upon the future value on mark-to-market hedges through their expiration dates. The expiration dates vary but are currently no later than December 2012 for our interest rate hedges and December 2013 for our commodity hedges. Option premiums and costs incurred to reset contract prices or purchase swaps are amortized during the contract period through the unrealized risk management instruments in total revenue. We monitor and review hedging positions regularly.

Depreciation Expense and Cost Capitalization Policies. Our midstream assets consist primarily of natural gas gathering pipelines and processing plants. We capitalize all construction-related direct labor and material costs, as well as indirect construction costs. Indirect construction costs include general engineering and the cost of funds used in construction. The cost of funds used in construction represent capitalized interest. These costs are then expensed over the life of the constructed asset through the recording of depreciation expense.

As discussed in Note 2 to our consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data starting on page F-1 of this Annual Report, depreciation of our midstream assets is generally computed using the straight-line method over the estimated useful life of the assets. The costs of renewals and betterments which extend the useful life of property, plant and equipment are also capitalized. The costs of repairs, replacements and maintenance projects are expensed as incurred.

The computation of depreciation expense requires judgment regarding the estimated useful lives and salvage value of assets. As circumstances warrant, depreciation estimates are reviewed to determine if any changes are needed. Such changes could involve an increase or decrease in estimated useful lives or salvage values which would impact future depreciation expense.

Impairment of Long-Lived Assets. We assess our long-lived assets for impairment whenever events or changes in circumstances indicate its carrying amount may not be recoverable.

Examples of events or changes in circumstances include:


•	a significant decrease in the market price of a long-lived asset or asset group;


•	a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition;

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•	a significant adverse change in legal factors or in the business climate could affect the value of a long-lived asset or asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the rate-making process;


•	an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset or asset group;


•	a current-period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group; and


•	a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

The carrying value of a long-lived asset is determined to not be recoverable when the carrying value of a long-lived asset exceeds our estimate of the undiscounted cash flows expected to result from the use and eventual disposition of the long-lived asset. If the carrying value of a long-lived asset is determined not to be recoverable, the impairment loss is measured as the excess of the carrying value over its fair value. For our the long-lived assets in our Midstream Business, our estimate of cash flows is based on assumptions regarding the long-lived asset, including future commodity prices and estimate future natural gas production in the region (which is dependent in part on commodity prices). Our estimate of natural gas volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to: (i) changes in the general economic conditions in which the long-lived asset is located, (ii) the availability and prices of the natural gas supply, (iii) our dependence on certain significant customers and producers of natural gas and (iv)improvements in exploration and production technologies.

During the year ended December 31, 2010, we recorded $29.3 million in impairment charges within our Midstream Segment due to (i) $3.1 million related to the loss of a significant gathering contract in our South Texas Segment and (ii) $26.2 million, recorded within discontinued operations in our South Texas Segment, related to an anticipated decline in volumes on our Wildhorse gathering system. During the year ended December 31, 2009, we incurred impairment charges of $13.7 million in our Midstream segment as a result of reduced throughput volumes as our producer customers curtailed their drilling activity in response to lower natural gas prices. During the year ended December 31, 2008, the Partnership recorded an impairment charge related to certain processing plants, pipelines and contracts in its Midstream business of $35.1 million due to the substantial decline in commodity prices in the fourth quarter as well as declining drilling activity by its producer customers.

Goodwill Impairment. We assess our goodwill for impairment annually or whenever events indicate impairment may have occurred based on authoritative guidance. We performed our annual assessment in May 2008 and no impairment was evident at that point in time. As a result of the impairment charge recorded in our Upstream Segment, we performed an assessment of our goodwill during the fourth quarter and recorded an impairment charge of $31.0 million, or our entire goodwill balance, during the fourth quarter of 2008.

Environmental Remediation. Current accounting guidelines require us to recognize a liability and expense associated with environmental remediation if (i) government agencies mandate such activities or one of our properties were added to the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) database, (ii) the existence of a liability is probable and (iii) the amount can be reasonably estimated. As of December 31, 2010, we have recorded a $4.0 million liability for remediation expenditures. If governmental regulations change, we could be required to incur additional remediation costs which may have a material impact on our profitability. Accrued environmental costs represent our best estimate as to the total costs of remediation and the time period over which these costs will be incurred.

Asset Retirement Obligations. We have recorded liabilities of $24.7 million for future asset retirement obligations in our midstream and upstream operations as of December 31, 2010. Related accretion expense has been recorded in operating expenses, as discussed in Note 5 to our consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data starting on page F-1 of this Annual Report. The recognition of an asset retirement obligation requires that management make numerous estimates, assumptions and judgments regarding such factors as costs of remediation, timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates. In periods subsequent to initial measurement of the asset retirement obligation, we must recognize period-to-period changes in the liability resulting from changes in the timing of settlement to changes in the estimate of the costs of remediation. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis and an adjustment in our DD&A expense in future periods. During the year ended December 31, 2010, we recorded revisions to our estimated obligations that resulted in a increase to our capitalized assets and corresponding liabilities of $2.6 million

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Presentation of Financial Information

For a description of the presentation of our financial information in this report, please see Part II, Item 6. Selected Financial Data.

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Year Ended December 31, 2010 Compared with Year Ended December 31, 2009

Summary of Consolidated Operating Results

Below is a table of a summary of our consolidated operating results for the years ended December 31, 2010 and 2009. Operating results for our individual operating segments are presented in tables in this Item 7.



	Year Ended December 31,
	2010			2009
	($ in thousands)
Revenues:
Sales of natural gas, NGLs, oil, condensate and sulfur	$	688,052		$	633,357
Gathering, compression, processing and treating fees	50,608			44,005
Realized commodity derivative (losses) gains	(17,010		)	83,300
Unrealized commodity derivative gains (losses)	8,224			(189,590		)
Other	2,435			1,858
Total revenues	732,309			572,930
Cost of natural gas and natural gas liquids	468,304			470,099
Costs and expenses:
Operating and maintenance	76,415			71,496
Taxes and other income	12,226			10,709
General and administrative	45,775			45,819
Other operating income	—			(3,552		)
Impairment expense	6,666			21,788
Depreciation, depletion and amortization	106,398			108,530
Total costs and expenses	247,480			254,790
Total operating income (loss)	16,525			(151,959		)
Other income (expense):
Interest income	111			187
Other income	501			934
Interest expense	(15,147		)	(21,591		)
Unrealized interest rate derivatives (losses) gains	(7,164		)	12,529
Realized interest rate derivative losses	(19,971		)	(18,876		)
Other expense	(51		)	(1,070		)
Total other income (expense)	(41,721		)	(27,887		)
Loss from continuing operations before income taxes	(25,196		)	(179,846		)
Income tax (benefit) provision	(2,585		)	989
Loss from continuing operations	(22,611		)	(180,835		)
Discontinued operations, net of tax	17,262			9,577
Net loss	$	(5,349	)	$	(171,258	)
Adjusted EBITDA(a)	$	126,026		$	172,587

________________________


(a)	See Part II, Item 6. Selected Financial Data – Non-GAAP Financial Measures for a definition and reconciliation to GAAP.

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Midstream Business (Four Segments)

Texas Panhandle Segment



	Twelve Months Ending December 31,
	2010			2009
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Sales of natural gas, NGLs, oil and condensate	$	346,278		$	282,916
Gathering and treating services	11,957			11,036
Total revenues	358,235			293,952
Cost of natural gas, natural gas liquids, oil & condensate (a)	243,054			206,985
Operating costs and expenses:
Operations and maintenance	35,032			31,873
Depreciation and amortization	45,876			46,085
Total operating costs and expenses	80,908			77,958
Operating income	$	34,273		$	9,009

Capital expenditures	$	29,282		$	7,293

Realized prices:
Oil and condensate (per Bbl)	$	66.68		$	60.14
Natural gas (per Mcf)	$	3.92		$	3.23
NGLs (per Bbl)	$	45.85		$	33.45
Production volumes:
Gathering volumes (Mcf/d)(b)	131,925			138,450
NGLs (net equity gallons) (c)	38,025,937			46,376,433
Condensate (net equity gallons) (c)	43,439,551			35,292,388
Natural gas short position (MMbtu/d)(b)	(4,811		)	(6,010		)

________________________


(a)	Includes purchase of oil and condensate of $5,587 from the Upstream Segment for the year ended December 31, 2010.


(b)	Gathering volumes (Mcf/d) and natural gas short position (MMbtu/d) are calculated by taking the total volume and then dividing by the number of days in the respective period.


(c)	Installation of additional measurement facilities in January 2010 has improved the measurement of NGLs and condensate volumes, resulting in increased equity condensate volumes and a corresponding decrease in equity NGL volumes.

Revenue and Cost of Natural Gas and Natural Gas Liquids. For the year ended December 31, 2010, revenues minus cost of natural gas and natural gas liquids for our Texas Panhandle Segment operations totaled $115.2 million compared to $87.0 million for the year ended December 31, 2009. The increase is primarily driven by the higher NGL, natural gas and condensate pricing offset by lower gathering and equity volumes. As footnoted above, additional measurement facilities installed in January 2010 have resulted in improved measurement of NGLs and condensate volumes, which in turn resulted in increased equity condensate volumes and a corresponding decrease in equity NGL volumes versus the prior year ending December 31, 2009.

Our Texas Panhandle Segment lies within ten counties in Texas and consists of our East Panhandle System and our

West Panhandle System. The limited drilling activity in the West Panhandle System is not sufficient to offset the natural declines experienced on this system. While our contract mix in the West Panhandle System provides us with a higher equity share of the production, the overall decline will continue. In the East Panhandle, volumes were lower in the first half of 2010 due to falling natural gas prices which constrained drilling activity by our producer customers as they evaluated the economics of the Granite Wash play. We saw a resurgence of drilling activity by our producer customers beginning in the third quarter of 2010 as NGL prices increased dramatically due to improved demand in the United States for NGLs by the petrochemical industry. Given the improvements in horizontal drilling technology and fracturing practices, our producer customers are active in the development of the Granite Wash play. We began to see the benefit of this increase in drilling activity during the fourth

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quarter of 2010, as we saw volumes increasing through our gathering and processing facilities. These increases through our gathering and processing facilities were somewhat slowed during the fourth quarter of 2010 as some of our producer customers experienced delays in contracting well completion services. We expect this to improving drilling environment to carry into 2011.

We have extensive gathering and processing facilities in the Granite Wash play, especially in Wheeler, Roberts and Hemphill Counties, Texas and have long-term acreage dedications from several large producers, so we are focused on improving our processing capabilities in the Texas Panhandle. The processing plants in our East Panhandle System, given the current drilling activity, have sufficient processing capacity to accommodate our customers' current needs until drilling levels increase. In order to provide additional processing capacity to our East Panhandle System, we initiated a project to refurbish the Stinnett cryogenic processing plant, located in the West Panhandle System, and relocate it to the East Panhandle System to replace the existing Arrington lean oil processing plant (the "Phoenix Plant"), resulting in additional processing capacity and improved processing economics. This project was temporarily postponed in early 2009, but in February 2010, we announced our intention to deploy the Phoenix Plant to increase efficiency and accommodate volume growth from the Granite Wash play. The Phoenix Plant began operations in October 2010 with an initial capacity of 50 MMcf/d and the ability to expand to 80 MMcf/d. In support of this project we installed a three mile pipeline to interconnect our System 97 gathering system and the new East Hemphill gathering system, as discussed below, to the new Phoenix Plant providing access to drilling activity in Wheeler and Hemphill counties in Texas and adjoining counties in Oklahoma.

On October 19, 2010, we acquired our East Hemphill system from CEFS. This acquisition provided (i) an immediate increase in gathered volumes of approximately 18.2 MMBtu/d; (ii) a significant extension of our gathering infrastructure in the area; (iii) high and low pressure gathering services to accommodate growing volumes in the Wheeler County area; and (iv) a stronger platform from which we will be able to provide our customers the flexibility to direct liquids-rich gas to one or more of our processing facilities.

In the West Panhandle, the Super Drip and Cargray condensate collection stabilization facilities receive condensate collected from various gathering systems where it is then separated from the collected water and treated. We currently stabilize approximately 2,000 barrels per day combined at our Superdrip and Cargray Stabilizers. The Cargray Stabilizer became operational in October 2010 and has increased our stabilization capacity by 2,400 barrels per day. The additional condensate stabilization capacity at Cargray also allows us to increase operating efficiencies at the Superdrip Stabilizer. Condensate stabilization lowers the product's vapor pressure, resulting in a higher value product for sale. We continue to review additional condensate stabilization projects that may provide an opportunity to handle third party condensate for a fee. We continue to review additional plant consolidation projects in order to rationalize plant processing capacity and operating costs in an area where the gas decline continues in the range of 6% to 8% per year.

During the fourth quarter of 2010, we launched our own marketing company, Eagle Rock Marketing, LLC ("Eagle Rock Marketing") which initiated a condensate marketing operation that involves developing, implementing, and launching marketing uplift strategies surrounding (i) our Upstream Segment's equity production in Alabama and (ii) our equity production in the Texas Panhandle. These plans involve several phases: marketing, operations, transportation, and venturing into third party condensate/liquids purchasing to insure the greatest possible opportunity for repeatable earnings growth. Each area has unique challenges which offer opportunities to enhance product net-back prices for our own equity production as well as third-party production.

Alabama: Our Upstream Segment owns and controls certain condensate produced in the Big Escambia Creek, Fanny Church and Flomaton fields in Escambia County, Alabama. We formed a new subsidiary in late 2010, i.e. Eagle Rock Marketing, that now operates as part of our Midstream Business. In part, this new subsidiary was formed to create alternative market outlets for the condensate produced from these Alabama fields (both by our Upstream Segment and by other working interest owners) and to take advantage of these alternative market outlets to benefit our Upstream Segment, the other working interest owners in the fields and our Midstream Business. To do this, Eagle Rock Marketing purchases product from our Upstream Segment and the other working interest owners in the fields, at an uplift to the highest price that could have been received from existing markets for the product as it exists prior to the purchase by Eagle Rock Marketing. Eagle Rock Marketing is able to pay more for the product on account of Eagle Rock Marketing's business strategy, which includes (i) blending the purchased condensate to lower the concentration of contaminants and create a new and improved condensate that is more marketable when relocated to an appropriate market and (ii) transporting the new and improved condensate to a better market location for further resale. In this regard, neither our Upstream Segment nor the other working interest owners in the fields bear any of the increased risk in blending and relocating, including the heightened risk of loss in transporting the product for blending and further resale or the market risk with respect to resale of the improved product, all of which is born by Eagle Rock Marketing within our Midstream Business. Eagle Rock Marketing launched this project in November 2010, and Eagle

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Rock Marketing has been successful, so far, in blending and relocating the product to create market optionality. As a result, Eagle Rock Marketing has enhanced the price received by our Upstream Segment and the other working interest owners in the Alabama fields, while realizing a good return for its own investment and efforts. Eagle Rock Marketing currently takes delivery of the unimproved condensate at a newly-constructed truck loading facility at our Big Escambia Creek processing plant and delivers it to a leased storage facility at Mobile, Alabama where the condensate is blended to lower the concentration of contaminants and create an improved condensate product. Thereafter, the improved product is relocated to a suitable market for resale at an improved price.

Texas Panhandle: In the Texas Panhandle many dynamics are impacting natural gas liquids and condensate prices, especially product quality and location. Eagle Rock has seen an increased price erosion given the gravity, vapor pressure and over-supply of condensate in the Granite Wash and other shale plays in Texas. Consequently, the regional markets are saturated. Eagle Rock Marketing's strategy for Texas Panhandle condensate is again an organic growth initiative. In October 2010, we installed a new stabilizer at our Cargray Plant to lower the vapor pressure of our equity and third-party condensate, thereby increasing our received price for the condensate. In addition, we are currently evaluating various storage and transportation opportunities to aggregate our product along with other third party condensate and move it to more attractive markets outside the Panhandle.

Operating Expenses. Operating expenses, including taxes other than income, for the year ended December 31, 2010 increased $3.2 million as compared to the year ended December 31, 2009. The increase was due to increased compressor rental expenses as we expanded the compressor station at our Roberts County Plant with leased units and replaced aging compressors at our Stinnett facility with more efficient leased units. In addition, the increase was also due to increased maintenance costs as we worked to improve our existing infrastructure to support our new Phoenix Plant and extraordinary mechanical breakdowns of our Goad Treater. The installation of a new 26 MMcf/d treating facility, the Goad Treater, was completed in November 2010 and replaces an older original facility. This facility removes hydrogen sulfide and carbon dioxide from the natural gas prior to delivery to interstate pipelines.

Depreciation and Amortization. Depreciation and amortization expenses for the year ended December 31, 2010 decreased $0.2 million from the year ended December 31, 2009. The major item impacting the decrease was a reduction in amortization expense due to the completion of the amortization of certain intangible assets. This decrease was offset by depreciation expense associated with the capital expenditures placed into service during the period.

Capital Expenditures. Capital expenditures for the year ended December 31, 2010 increased $22.0 million compared to the year ended December 31, 2009. The increase was primarily driven by spending related to the Phoenix Plant in 2010, including an interconnect between our System 97 gathering system and the Phoenix Plant and spending related to improvements to the Cargray Stabilizer and Goad Treater.

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East Texas/Louisiana Segment



	Twelve Months Ending December 31,
	2010		2009
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Sales of natural gas, NGLs, oil and condensate	$	168,922	$	181,550
Gathering and treating services	35,427		27,968
Total revenues	204,349		209,518
Cost of natural gas and natural gas liquids	151,236		162,957
Operating costs and expenses:
Operations and maintenance	17,275		17,985
Depreciation and amortization	18,452		17,188
Impairment	—		5,941
Total operating costs and expenses	35,727		41,114
Operating income	$	17,386	$	5,447

Capital expenditures	$	15,756	$	18,188

Realized prices:
Oil and condensate (per Bbl)	$	79.89	$	63.34
Natural gas (per Mcf)	$	4.87	$	3.83
NGLs (per Bbl)	$	34.68	$	35.87
Production volumes:
Gathering volumes (Mcf/d)(a)	205,868		248,597
NGLs (net equity gallons)	18,217,505		19,924,820
Condensate (net equity gallons)	1,617,996		2,381,123
Natural gas short position (MMbtu/d)(a)	833		2,851

________________________


(a)	Gathering volumes (Mcf/d) and natural gas short position (MMbtu/d) are calculated by taking the total volume and then dividing by the number of days in the respective period.

Revenue and Cost of Natural Gas and Natural Gas Liquids. For the year ended December 31, 2010, revenues minus cost of natural gas and natural gas liquids for our East Texas/Louisiana Segment totaled $53.1 million compared to $46.6 million for the year ended December 31, 2009. During the year ended December 31, 2010 and 2009, we recorded revenues associated with deficiency payments of $10.4 million and $1.1 million, respectively, from certain of our producers. We receive deficiency payments under certain of our gathering contracts when delivered volumes fail to meet certain thresholds. These amounts are included within gathering and treating services revenue. Excluding these deficiency payments, revenues minus cost of natural gas and NGLs for the year ended December 31, 2010 and 2009 would have been $42.7 million and $45.5 million, respectively. The decrease for the year ended December 31, 2010 compared to the year ended December 31, 2009, excluding the impact of the deficiency payments, is primarily due to a decrease in gathering and equity volumes and lower NGL prices, partially offset by higher condensate and natural gas prices. In addition, during the first two months of 2009, we elected to not recover the ethane component in the natural gas stream in our plants and instead chose to leave the ethane component in the residue gas stream sold at the tailgate of our plants. We operate in this manner when the value of ethane is worth more in the gas stream than as a liquid.

Our gathering volumes on our ETML system and certain other East Texas/Louisiana systems for the year ended December 31, 2010 decreased as compared to the year ended December 31, 2009, due to natural declines in the production of the existing wells and to reduced drilling activity in lean gas formations as a result of the continued depressed natural gas price environment. Our Brookeland and associated systems have seen a modest rebound in gathered volumes beginning in the fourth quarter of 2010. During the second half of 2010, we saw an increase in drilling activity by our producer customers as NGL

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prices increased dramatically as a result of the improved demand in the United States for NGL' by the petrochemical industry. Given the improvements in horizontal drilling technology and fracturing practices, our producer customers are active in the development of the Austin Chalk play. We have an extensive gathering footprint in the Austin Chalk play and we believe we have sufficient processing capacity today to accommodate increasing liquids rich natural gas volumes. We began to see the benefit of this increased drilling activity during the fourth quarter of 2010, as we saw volumes increasing through our gathering and processing facilities. These increases were somewhat slowed as some of our producer customers encountered delays due to permitting or water production issues. We expect this improving drilling environment to carry into 2011.

Operating Expenses. Operating expenses for the year ended December 31, 2010 decreased $0.7 million compared to the year ended December 31, 2009 as a result of reduced volumes.

Depreciation and Amortization. Depreciation and amortization expenses for the year ended December 31, 2010 increased $1.3 million compared to the year ended December 31, 2009. The major items impacting the increase were (i) depreciation expense associated with the capital expenditures placed into service and (ii) an acceleration of the amortization related to certain intangibles (e.g., rights-of-ways) due to the cancellation of the ETML expansion project. These increases were offset by an adjustment of $0.9 million recorded during the three months ended June 30, 2009 to correct an overstatement of depreciation expense in a prior period.

Impairment. During the year ended December 31, 2009, we incurred impairment charges of $5.9 million of pipeline assets in our East Texas/Louisiana Segment as a result of reduced throughput volumes as our producer customers curtailed their drilling activity in response to lower natural gas prices. No impairment charges were incurred during the year ended December 31, 2010.

Capital Expenditures. Capital expenditures for the year ended December 31, 2010 decreased $2.4 million compared to the year ended December 31, 2009 due primarily to our overall lower capital spending on account of the reduced drilling activity of our producer customers.

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South Texas Segment



	Twelve Months Ending December 31,
	2010			2009
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Sales of natural gas, NGLs, oil and condensate	$	54,690		$	74,336
Gathering and treating services	2,195			4,137
Other	—			3
Total revenues	56,885			78,476
Cost of natural gas and natural gas liquids	51,573			73,785
Operating costs and expenses:
Operations and maintenance	1,839			1,904
Depreciation and amortization	3,258			3,599
Impairment	3,130			7,733
Total operating costs and expenses	8,227			13,236
Operating loss from continuing operations	(2,915		)	(8,545		)
(Loss) income from discontinued operations (a)	(25,781		)	503
Operating loss	$	(28,696	)	$	(8,042	)

Capital expenditures	$	90		$	69

Realized prices:
Oil and condensate (per Bbl)	$	75.41		$	50.83
Natural gas (per Mcf)	$	4.38		$	3.76
NGLs (per Bbl)	$	45.91		$	32.26
Production volumes:
Gathering volumes (Mcf/d)(b)	47,689			77,622
NGLs (net equity gallons)	301,983			338,981
Condensate (net equity gallons)	461,967			526,094
Natural gas short position (MMbtu/d)(a)	865			902

________________________


(a)	Includes sales of natural gas of $47 to the Upstream Segment for the year ended December 31, 2010.


(b)	Gathering volumes (Mcf/d) and natural gas short position (MMbtu/d) are calculated by taking the total volume and then dividing by the number of days in the respective period.

Revenue and Cost of Natural Gas and Natural Gas Liquids. During the year ended December 31, 2010 the South Texas Segment contributed revenues minus cost of natural gas and natural gas liquids of $5.3 million, as compared to $4.7 million for the year ended December 31, 2009. The variance of $0.6 million was positively impacted by adjustments relating to prior periods. Our South Texas Segment was negatively impacted by declining gathering volumes, offset by increased commodity prices during the year ended December 31, 2010, as compared to 2009. Our gathered volumes for the year ended December 31, 2010 decreased by 39% as compared to the year ended December 31, 2009. This decrease is due to natural declines from existing wells and to the loss of a significant producer during the third quarter of 2010. The reduction in natural gas prices throughout 2010, the low liquid content of the natural gas from the existing reservoirs that we gather and our lack of processing capabilities have negatively impacted the drilling activity around our assets in South Texas. As natural gas prices level or recover from the current levels, we expect to see improving natural gas volumes in the future. At this point we are unable to predict when we will see increasing natural gas volumes through our gathering systems in South Texas.

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Operating Expenses. Operating expenses for the year ended December 31, 2010 decreased $0.1 million as compared to the year ended December 31, 2009. The decrease was primarily as a result of operating the gathering systems at lower volumes.

Depreciation and Amortization. Depreciation and amortization expenses for the year ended December 31, 2010 as compared to the year ended December 31, 2009 decreased $0.3 million.

Impairment. During the year ended December 31, 2010, we incurred impairment charges of $3.1 million due to the termination of a significant gathering contract in the third quarter. During the year ended December 31, 2009, we incurred impairment charges of $7.7 million in our South Texas segment as a result of reduced throughput volumes as our producer customers curtailed their drilling activity in response to lower natural gas prices.

Capital Expenditures. Capital expenditures remained consistent for the year ended December 31, 2010 and 2009.

Discontinued Operations. On April 1, 2009, we sold our producer services line of business, and thus have retrospectively classified the revenues minus the cost of natural gas and natural gas liquids as discontinued operations. During the year ended December 31, 2010, this business generated revenues of $0.1 million, as compared to revenues of $19.2 million and cost of natural gas and natural gas liquids of $18.9 million during the year ended December 31, 2009.

In February 2011, we classified the assets and liabilities of our Wildhorse Gathering System as held for sale and thus we have retrospectively classified the operations as discontinued. During the year ended December 31, 2010, the Wildhorse Gathering System generated revenues of $26.1 million and an operating loss of $25.9 million, which includes an impairment charge of $26.2 million. During the year ended December 31, 2009, the Wildhorse Gathering System generated revenues of $21.8 million and operating income of $0.2 million.

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Gulf of Mexico Segment



	Twelve Months Ending December 31,
	2010			2009
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Sales of natural gas, NGLs, oil and condensate	$	31,925		$	31,161
Gathering and treating services	1,029			864
Other	—			1,616
Total revenues	32,954			33,641
Cost of natural gas and natural gas liquids	28,028			26,372
Operating costs and expenses:
Operations and maintenance	1,771			1,907
Depreciation and amortization	6,838			6,576
Total operating costs and expenses	8,609			8,483
Operating loss	$	(3,683	)	$	(1,214	)

Capital Expenditures	$	180		$	358

Realized average prices:
NGLs (per Bbl)	$	46.00		$	35.52
Production volumes:
Gathering volumes (Mcf/d)(a)	103,846			116,492
NGLs and condensate (net equity gallons)	4,398,467			5,768,018

________________________


(a)	Gathering volumes (Mcf/d) are calculated by taking the total volume and then dividing by the number of days in the respective period.

Revenues and Cost of Natural Gas and Natural Gas Liquids. During the year ended December 31, 2010, the Gulf of Mexico Segment contributed $4.9 million in revenues minus cost of natural gas and natural gas liquids compared to $7.3 million in the year ended December 31, 2009. During the year ended December 31, 2009, we recorded other revenue of approximately $1.6 million from business interruption insurance related to damages caused by Hurricanes Gustav and Ike. Excluding this other revenue, revenues minus cost of natural gas and NGLs would have been $5.7 million for the year ended December 31, 2009. The decrease, exclusive of the business interruption insurance recovery, can be attributed to a reduction in gathering volumes offset by higher NGL prices during the year ended December 31, 2010, as compared to the year ended December 31, 2009. The reduction in volumes is due to natural declines in the underlying existing wells, reduced drilling activity during 2010 and 2009, on account of workovers and new shallow water drilling being generally reduced due to permitting delays by the federal government, and an adjustment downward in our ownership percentage at the North Terrebonne Plant. Our ownership percentage in North Terrebonne and Yscloskey adjusts up or down annually based upon our volume of gas from committed leases as compared to the total volumes of gas from all plant owners committed leases. Our ownership in Yscloskey decreased from 13.78% to 11.45% in 2010. Our ownership in North Terrebonne Plant decreased to 1.67% in 2010 from 5.16% for 2009 but increased in January 2011 to 2.63%.

Operating Expenses. Operating expenses for the year ended December 31, 2010 compared to the year ended December 31, 2009 decreased $0.1 million.

Depreciation and Amortization. Depreciation and amortization expenses for in the year ended December 31, 2010 compared to the year ended December 31, 2009 increased $0.3 million.

Capital Expenditures. Capital expenditures for the year ended December 31, 2010 for the Gulf of Mexico Segment compared to the year ended December 31, 2009 decreased $0.2 million.

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Upstream Segment



	Twelve Months Ending December 31,
	2010		2009
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Oil and condensate (a) (b)	$	50,507	$	35,316
Natural gas (c)	15,027		12,021
NGLs (d)	19,973		16,057
Sulfur (e)	6,793		—
Other	2,435		239
Total revenues	94,735		63,633
Operating Costs and expenses:
Operations and maintenance (f)	32,042		26,336
Sulfur disposal costs	729		2,200
Other operating income	—		(3,552		)
Depletion, depreciation and amortization	30,424		34,009
Impairment	3,536		8,114
Total operating costs and expenses	66,731		67,107
Operating income (loss)	$	28,004	$	(3,474	)

Capital expenditures	$	26,772	$	8,437

Realized average prices (h):
Oil and condensate (per Bbl)	$	62.35	$	45.30
Natural gas (per Mcf)	$	4.43	$	3.69
NGLs (per Bbl)	$	47.00	$	31.90
Sulfur (per Long ton) (g)	$	88.36	—
Production volumes:
Oil and condensate (Bbl)	808,077		811,075
Natural gas (Mcf)	3,514,078		3,659,431
NGLs (Bbl)	437,375		504,669
Total (Mcfe)	10,986,790		11,553,895
Sulfur (Long ton) (g)	84,065		119,812

________________________


(a)	Includes sales of oil and condensate to the Texas Panhandle Segment of $6,063 for the year ended December 31, 2010.


(b)	Revenues include a change in the value of product imbalances by $(102) and $(260) for the year ended December 31, 2010 and 2009, respectively.


(c)	Revenues include a change in the value of product imbalances by $430 and $(1,273) for the year ended December 31, 2010 and 2009, respectively.


(d)	Revenues include a change in the value of product imbalances by $370 and $28 for the year ended December 31, 2010 and 2009, respectively.


(e)	Revenues include a change in the value of product imbalances by $48 for year ended December 31, 2010.


(f)	Includes purchases of natural gas of $47 from the South Texas Segment for the year ended December 31, 2010.


(g)	During year ended December 31, 2010, an adjustment was made to decrease sulfur volumes by 5,230 long tons related to a prior period. This adjustment is excluded from the calculation of realized prices.


(h)	Calculation does not include impact of product imbalances. In addition, volumes and realized price for the year ended December 31, 2009 and the three months ended March 31, 2010 have been revised from prior period reported amounts due to a reallocation of historical production results based on more accurate well tests of our Alabama properties.

Revenue. For the year ended December 31, 2010, Upstream Segment revenues increased by $31.1 million, as compared to the year ended December 31, 2009. The increase in revenue was due to higher realized prices for oil, natural gas, NGLs and sulfur during year ended December 31, 2010 compared to the year ended December 31, 2009. This increase was partially offset by the shut-in of our East Texas production beginning August 11, 2010 (see further discussion of the shut-in

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below) and the turnarounds at our Big Escambia Creek and Flomaton facilities during the year ended December 31, 2010, as discussed below.

During late April and early May 2010, we completed a scheduled turnaround (i.e., a complete shutdown of the facility to perform certain standard plant repairs and routine inspections of equipment) of our Big Escambia Creek facility in Southern Alabama. During the plant turnaround, all wells in the Big Escambia Creek field were shut-in. The duration of both the plant turnaround and the well shut-in was approximately 12 days. The negative impact to our production during this period was a loss of approximately 48 MMcf of residue gas, 14 MBbls of oil, 8.7 MBbls of plant liquids and 2,000 long tons of sulfur. The

revenue impact of the loss in production was approximately $1.8 million during the year ended December 31, 2010. In addition, during the year ended December 31, 2010, we completed a reallocation of historical production results based on more accurate tests and product analyses for our Big Escambia Creek wells for the period from August 2007 through March 2010. As a result of this reallocation of historical production, our revenues for the year ended December 31, 2010 were negatively impacted by $1.3 million.

In August 2010, we announced that our East Texas oil and natural gas production was temporarily shut-in due to an unscheduled shutdown of the Eustace processing facility owned and operated by a third-party. The shutdown involved replacing all of the tubes in the reaction furnace's waste heat recovery unit, replacing the catalyst in the sulfur recovery unit and other equipment repairs. The operator originally estimated that the shutdown would take 30 to 45 days to complete. Subsequently, we were informed by the operator that more extensive repairs would be required and that the shutdown would last through mid-November of 2010. This estimate was later revised to late December 2010 and again to late-February 2011. As of March 10, 2011, the third-party operator was in the process of returning the facility to service. We estimate that the shut-in negatively impacted our 2010 net revenues by approximately $7.1 million (excluding recoveries) and assuming the latest estimate holds, we expect that our 2011 net revenues will be negatively impacted by approximately $3.4 million (excluding potential recoveries). We maintain business interruption insurance and are pursuing recovery of the lost net revenue above our 30-day deductible. As of December 31, 2010, we have recognized $3.0 million related to our business interruption insurance claim in other revenue. The maximum recovery under our business interruption insurance policy for this named facility is $5.0 million for each claimed event.

During the year ended December 31, 2010, sulfur revenue was $6.8 million. During the year ended December 31, 2009, however, sulfur prices were sufficiently low that we experienced costs to dispose of sulfur which exceeded their sales revenues by $2.2 million. In addition, during the year ended December 31, 2010, we recorded sulfur disposal costs of $0.7 million to adjust for a shortfall in a prior period accrual of sulfur disposal costs. Historically, sulfur was viewed as a low value byproduct in the production of oil and natural gas. During the year ended December 31, 2010, we saw a recovery in sulfur prices, with prices ranging from $90 per long ton on February 10, 2010 to $185 per long ton on February 12, 2011 at the Tampa, Florida market. Our net realized price will always be lower than the price set at the Tampa, Florida hub due to transportation and marketing deductions and charges. These charges vary depending on the distance our product is produced from the Tampa, Florida market.

Operating Expenses. Operating expenses, including severance and ad valorem taxes, increased by $5.7 million for the year ended December 31, 2010, as compared to the year ended December 31, 2009. The increase in operating expense for the year ended December 31, 2010, as compared to the same period in the prior year can be attributed increased well workovers in our Alabama operations and to $2.3 million of expenses related to the turnarounds at our facilities at Big Escambia Creek and Flomaton, as discussed above. In addition, during the year ended December 31, 2010, we recorded a reversal of $0.6 million of operating costs due to the reallocation of historical production for our Big Escambia Creek wells, as discussed above. During the year ended December 31, 2009, operating expenses were reduced due to the reversal of $1.6 million of environmental reserves determined to no longer be necessary and receipt of a $0.7 million credit for overbillings related to a non-operated asset. Also, during the year ended December 31, 2010, our severance taxes increased due to (i) the increase in revenue from the same periods in the prior year and (ii) additional severance taxes as a result of the reallocation of historical production discussed above. This increase for the year ended December 31, 2010 was offset by a refund of severance taxes from the state of Alabama for overpayment in prior periods.

Depletion, Depreciation and Amortization. Depletion, depreciation and amortization expense decreased by $3.6 million for the year ended December 31, 2010, as compared to the same period in the prior year. The decrease for the year ended December 31, 2010, as compared to the comparable period in 2009 is due to decreases in production as a result of our East Texas wells being shut-in, as discussed above.

Other Operating Income. Other operating income for the year ended December 31, 2009, includes the recovery of $2.2 million of assets previously written off and the release of $1.4 million of liabilities assumed as part of our purchase price allocation for our acquisitions of Escambia Asset Co. LLC and Redman Energy Holdings, L.P. During the period, we received

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additional information about collectability of the referenced assets which enabled us to recover on them and we determined that we no longer had any obligation under the referenced liabilities which enabled us to release them.

Impairment. Impairment charges of $3.5 million incurred during the year ended December 31, 2010 of which (i) $3.4 million related to certain fields in our unproved properties we determined it would not be technologically feasible to develop these unproved locations and (ii) $0.1 million related to proved properties due to adjustments to our reserves. During the year ended December 31, 2009, we incurred impairment charges of $8.1 million of which (i) $7.9 million was a result of a decline in natural gas prices, production declines and lower natural gas liquids yields at our Flomaton field and (ii) $0.2 million in other fields due to lower natural gas prices.

Capital Expenditures. Capital expenditures increased by $18.3 million for the year ended December 31, 2010, as compared to the year ended December 31, 2009. The increase in capital expenditures is due to drilling activity in our Permian and Alabama operations, recompletions in our Jourdanton and Edgewood fields, leasing in our Edgewood and Flomaton fields, and the acquisition of compression equipment for the turnaround at our Big Escambia Creek facility, as discussed above. The two new compressors will provide improved reliability and backup for the existing residue gas and plant inlet compression. The new backup compression was placed in service in November 2010. During the year ended December 31, 2010, we drilled and completed five wells in our Permian operations. During the three months ended September 30, 2010 we drilled and plugged a dry hole in our Permian operations. As of December 31, 2010, we were in the process of drilling one additional well in our Big Escambia Creek field.

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Corporate and Other Segment



	Twelve Months Ending December 31,
	2010			2009
	($ in thousands)
Revenues:
Realized commodity derivatives (losses) gains	$	(17,010	)	$	83,300
Unrealized commodity derivatives gains (losses)	8,224			(189,590		)
Intersegment elimination - Sales of natural gas, oil and condensate	(6,063		)	—
Total revenues	(14,849		)	(106,290		)
Intersegment elimination - Cost of oil and condensate	(5,587		)	—
General and administrative	45,775			45,819
Intersegment elimination - Operations and maintenance	(47		)	—
Depreciation and amortization	1,550			1,073
Operating loss	(56,540		)	(153,182		)
Other income (expense):
Interest income	111			187
Other income	501			934
Interest expense	(15,147		)	(21,591		)
Unrealized interest rate derivative (losses) gains	(7,164		)	12,529
Realized interest rate derivative losses	(19,971		)	(18,876		)
Other expense	(51		)	(1,070		)
Total other income (expense)	(41,721		)	(27,887		)
Loss from continuing operations before taxes	(98,261		)	(181,069		)
Income tax (benefit) provision	(2,585		)	989
Loss from continuing operations	(95,676		)	(182,058		)
Discontinued operations, net of tax	43,043			9,074
Segment loss	$	(52,633	)	$	(172,984	)

Revenue. Our Corporate and Other Segment's revenue consists of our intersegment eliminations, see further discussion below, and our commodity derivatives activity. Our commodity hedging activities impact our Corporate segment revenues through (i) the unrealized, non-cash, mark-to-market of our commodity derivatives scheduled to settle in future periods; and (ii) the realized gains or losses on our commodity derivatives settled in the indicated period. Our unrealized commodity gains and losses reflect (i) the change in the mark-to-market value of our derivative position from the beginning of a period to the end and (ii) the amortization of put premiums and other derivative costs. In general, the change in the mark-to-market value of our derivative position may be due to several factors including the settlement of derivative instruments during the period, the addition of new derivative positions during the period, changes in the forward curves of the underlying commodities from the beginning to the end of the period, changes in interest rates used in the mark to market calculations from the beginning to the end of the period, and the passage of time during the period.

During the year ended December 31, 2010, we experienced an unrealized gain on our commodity derivative portfolio due the difference in value between the contracts that settled and the new contracts added to our portfolio and decreases in the natural gas forward curve, offset by increases in the crude oil and natural gas liquids forward curves. This compares to the year ended December 31, 2009 during which we experienced an unrealized loss on our commodity derivative portfolio due to increases in the crude oil and natural gas liquids forward curves, partially offset by a decline in the natural gas forward curve. Included with our unrealized commodity derivative gains (losses) are the amortization of put premiums and other derivative costs, including the costs of hedge resets, of $4.0 million and $48.4 million for the years ended December 31, 2010 and 2009, respectively. The unrealized commodity derivative gains (losses), including the amortization of put premiums and other derivative costs, for the years ended December 31, 2010 and 2009, had no impact on cash activities for those periods and are excluded from our calculation of Adjusted EBITDA.

We recognized realized commodity derivative losses during the year ended December 31, 2010, as compared to realized commodity gains for the year ended December 31, 2009, primarily due to lower strike prices on our derivatives that

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settled during the year ended December 31, 2010 as a result of our hedging strategy in which we entered into hedges with strike prices above market during the year ended December 31, 2009, in addition to higher index prices for crude and NGLs in the year ended December 31, 2010 as compared to the year ended December 31, 2009.

Given the uncertainty surrounding future commodity prices, and the general inability to predict future commodity prices as they relate to the strike prices at which we have hedged our exposure, it is difficult to predict the magnitude and impact that marking our hedges to market will have on our income from operations in future periods.

Intersegment Eliminations. During the year ended December 31, 2010, our South Texas Segment within our Midstream Business began selling natural gas to our Upstream Segment to be used as fuel, and our Upstream Segment began selling oil and condensate to the marketing group within our Midstream Business for resale. We have included the eliminations of these transactions within our Corporate Segment.

General and Administrative Expenses. General and administrative expenses decreased by less than $0.1 million for the year ended December 31, 2010 as compared to the same period in 2009. During the year ended December 31, 2010, our salary and benefit expense, excluding equity based compensation, increased by $3.5 million. This increase was primarily the result of increased headcount in accounting, back-office, engineering, land and operations-related corporate personnel and due to increased health insurance costs. This increase was offset by a decrease in equity-based compensation expense of approximately $1.3 million during the year ended December 31, 2010, as compared to the year ended December 31 2009. This decrease was primarily the result of natural run-off (through vesting) of restricted common units granted in prior periods at higher prices. In addition, equity based compensation during the years ended December 31, 2010 and 2009 included an allocation of expense of $0.1 million and $0.4 million, respectively, from Holdings on account of Holdings' issuance of incentive interests to certain of our executives. The increase in overall compensation and benefit was partially offset by a reduction of our allowance for bad debts. Also, due to the increase in headcount, we were able to reduce our contract labor and other professional services expenses by approximately $1.3 million during the year ended December 31, 2010, as compared to the year ended December 31, 2009. In addition, included within our general and administrative expenses for the year ended December 31, 2010 and 2009 are non-capitalizable legal and other professional advisory fees of $2.1 million and $0.7 million, respectively, related to the Recapitalization and Related Transactions and the related lawsuit.

At the present time, we do not allocate our general and administrative expenses cost to our operational segments. The Corporate Segment bears the entire amount.

Total Other Expense. Total other expense primarily consists of both realized and unrealized gains and losses from our interest rate swaps and interest expense related to our senior secured credit facility. During 2010, our realized settlements decreased by about $1.1 million, as compared to 2009, as a result of lower LIBOR rates in 2010. For the year ended December 31, 2010, we recognized an unrealized loss of $7.2 million, as compared to an unrealized gain of $12.5 million during the same period in 2009, as a result of a decrease to the forward interest rate curves. These unrealized mark-to-market losses did not have any impact on cash activities for the period, and are excluded by definition from our calculation of Adjusted EBITDA.

Interest expense decreased by $6.4 million during the year ended December 31, 2010, as compared to the same period in the prior year. Interest expense is shown before the impact of our interest rate derivatives, which convert a portion of our outstanding debt from variable-rate interest obligations to fixed-rate interest obligations. All of our outstanding debt consists of borrowings under our revolving credit facility, which bears interest primarily based on a LIBOR rate plus the applicable margin. The decrease in interest expense is due to lower LIBOR rates during 2010, as compared to the same period in 2009, and lower outstanding debt balances as a result of our efforts to pay down debt over the past 21 months.

Income Tax (Benefit) Provision. Income tax provision for the 2010 and 2009 relates to (i) state taxes due by us and (ii) federal taxes due by Eagle Rock Energy Acquisition Co., Inc. (acquiring entity of certain entities acquired in the acquisition of Redman Energy Corporation “Redman Acquisition” in 2008) and Eagle Rock Energy Acquisition Co. II, Inc. (acquiring entity of certain entities acquired in the Stanolind Acquisition) and their wholly-owned corporations, Eagle Rock Upstream Development Company, Inc. (successor entity to certain entities acquired in the Redman acquisition) and Eagle Rock Upstream Development Company II, Inc. (successor entity to certain entities acquired in the Stanolind acquisition), which are subject to federal income taxes (the “C Corporations”). During 2010, our tax provision decreased by $3.6 million as compared to the same periods in the prior year, primarily due to the reduction of the deferred tax liabilities created by the book/tax differences as a result of the federal income taxes associated with the Redman and Stanolind Acquisitions, receipt of state tax refunds and true-ups related to our prior year provision. For further discussion of our income tax (benefit) provision, see Note 15 to our consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data staring on page F-1 of this Annual Report.

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Discontinued Operations. On May 24, 2010, we completed the sale of our Minerals Business. We recorded a gain of $37.7 million on the sale, which is recorded as part of discontinued operations for the year ended December 31, 2010. Further upward or downward adjustments to the purchase price may occur post-closing to reflect customary true-ups. Subsequent to the sale, we received payments of $0.3 million related to pre-effective date operations and have recorded this amount as part of discontinued operations for the period. For the year ended December 31, 2010, we generated revenues of $8.9 million and income from operations of $5.5 million. For the year ended December 31, 2009, we generated revenues of $15.7 million and income from operations of $7.8 million. During the years ended December 31, 2010 and 2009, the Partnership incurred state tax expense on discontinued operations of $0.4 million and $0.2 million, respectively. During the years ended December 31, 2010 and 2009, we recorded income to discontinued operations, excluding the gain recognized by us on the sale of the Minerals Business, of $5.5 million and $9.1 million, respectively.

Adjusted EBITDA

Adjusted EBITDA, as defined under Part II, Item 6. Selected Financial Data - Non-GAAP Financial Measures, decreased by $46.6 million from $172.6 million for the year ended December 31, 2009 to $126.0 million for the year ended December 31, 2010.

As described above, revenues minus cost of natural gas and natural gas liquids for the Midstream Business (including the Texas Panhandle, East Texas/Louisiana, South Texas and Gulf of Mexico Segments) increased by $33.0 million during the year ended December 31, 2010, as compared to the comparable period in 2009. The Upstream Segment revenues increased $28.9 million during the year ended December 31, 2010, as compared to the comparable period in 2009. Intersegment eliminations revenues minus cost of natural gas and natural gas liquids resulted in a $0.5 million decrease. Our Corporate Segment's realized commodity derivatives gain decreased by $100.3 million during the year ended December 31, 2010 as compared to the comparable period in 2009. This resulted in total incremental revenues minus cost of natural gas and natural gas liquids decreasing by $38.9 million during the year ended December 31, 2010 as compared to the comparable period in 2009. The incremental revenue amounts are adjusted to exclude the impact of unrealized commodity derivatives, which includes the amortization of put premiums and other derivative costs, and the non-cash mark-to-market Upstream Segment imbalances, none of which are included in the calculation of Adjusted EBITDA.

Operating expenses (including taxes other than income) for our Midstream Business increased by $2.2 million for the year ended December 31, 2010, as compared to the same period in 2009, while Operating Expenses (including taxes other than income) for the Upstream Segment increased $4.2 million for the year ended December 31, 2010, as compared to the comparable period in 2009.

General and administrative expense, excluding the impact of non-cash compensation charges related to our long-term incentive program, Holding's Tier I incentive units and other non-recurring items and captured within our Corporate Segment, increased during the year ended December 31, 2010 by $1.2 million, as compared to the respective period in 2009.

As a result, revenues (excluding the impact of unrealized commodity derivative activity) minus cost of natural gas and natural gas liquids for the year ended December 31, 2010, as compared to the same period in 2009 decreased by $38.9 million, operating expenses increased by $6.4 million and general and administrative expenses increased by $1.2 million. The decreases in revenues minus the cost of natural gas and natural gas liquids, the decreases in operating costs offset by the increase in general and administrative expenses resulted in a decrease to Adjusted EBITDA during the year ended December 31, 2010, as compared to the year ended December 31, 2009. Adjusted EBITDA excludes amortization of commodity hedge costs (including costs of hedge reset transactions) for the years ended December 31, 2010 and 2009 of $4.0 million and $48.4 million, respectively. Including these amortization costs, our Adjusted EBITDA for the years ended December 31, 2010 and 2009 would have been $122.1 million and $124.2 million, respectively.

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Year Ended December 31, 2009 Compared with Year Ended December 31, 2008

Summary of Consolidated Operating Results

Below is a table of a summary of our consolidated operating results for the years ended December 31, 2009 and December 31, 2008. Operating results for our individual operating segments are presented in tables in this Item 7.



	Year Ended December 31,
	2009			2008
	($ in thousands)
Revenues:
Sales of natural gas, NGLs, oil, condensate and sulfur	$	633,357		$	1,227,779
Gathering, compression, processing and treating fees	44,005			38,497
Realized commodity derivative gains (losses)	83,300			(46,059		)
Unrealized commodity derivative gains (losses)	(189,590		)	207,824
Other	1,858			716
Total revenues	572,930			1,428,757
Cost of natural gas and natural gas liquids	470,099			886,019
Costs and expenses:
Operating and maintenance	71,496			73,203
Taxes and other income	10,709			18,210
General and administrative	45,819			45,618
Other operating (income) expense	(3,552		)	10,699
Depreciation, depletion and amortization	108,530			108,356
Impairment expense	21,788			142,116
Goodwill impairment expense	—			30,994
Total costs and expenses	254,790			429,196
Total operating income (loss)	(151,959		)	113,542
Other income (expense):
Interest income	187			771
Other income	934			1,318
Interest expense	(21,591		)	(32,884		)
Unrealized interest rate derivatives (gains) losses	12,529			(27,717		)
Realized interest rate derivative losses	(18,876		)	(5,214		)
Other expense	(1,070		)	(955		)
Total other income (expense)	(27,887		)	(64,681		)
Income (loss) from continuing operations before income taxes	(179,846		)	48,861
Income tax (benefit) provision	989			(1,459		)
Income (loss) from continuing operations	(180,835		)	50,320
Discontinued operations, net of tax	9,577			37,200
Net income (loss)	$	(171,258	)	$	87,520
Adjusted EBITDA(a)	$	172,587		$	206,418

__________________________


(a)	See Part II, Item 6. Selected Financial Data – Non-GAAP Financial Measures for a definition and reconciliation to GAAP.

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Midstream Business (Four Segments)

Texas Panhandle Segment



	Twelve Months Ending December 31,
	2009			2008
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Sales of natural gas, NGLs, oil and condensate	$	282,916		$	592,997
Gathering and treating services	11,036			10,069
Total revenues	293,952			603,066
Cost of natural gas and natural gas liquids	206,985			459,064
Operating costs and expenses:
Operations and maintenance	31,873			34,269
Depreciation and amortization	46,085			43,688
Total operating costs and expenses	77,958			77,957
Operating income	$	9,009		$	66,045

Capital expenditures	$	7,293		$	30,738

Realized prices:
Oil and condensate (per Bbl)	$	60.14		$	94.27
Natural gas (per Mcf)	$	3.23		$	7.44
NGLs (per Bbl)	$	33.45		$	58.34
Production volumes:
Gathering volumes (Mcf/d)(a)	138,450			151,964
NGLs and condensate (net equity gallons)	46,376,433			51,351,966
Condensate (net equity gallons)	35,292,388			35,162,578
Natural gas short position (MMbtu/d)(a)	(6,010		)	(5,607		)

________________________


(a)	Gathering volumes (Mcf/d) and natural gas short position (MMbtu/d) are calculated by taking the total volume and then dividing by the number of days in the respective period.

Revenue and Cost of Natural Gas and Natural Gas Liquids. For the year ended December 31, 2009, the revenues minus cost of natural gas and natural gas liquids for our Texas Panhandle Segment operations totaled $87.0 million compared to $144.0 million for the year ended December 31, 2008. 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 as compared to production in 2008. The lower NGL equity production was primarily due to approximately 9% lower gathered volumes in 2009 as compared to 2008 and due to operating certain plants in ethane rejection mode for much of the first two months of 2009. Ethane rejection operations occur when we elect to not recover the ethane component in the natural gas stream in our plants and instead choose to leave the ethane component in the residue gas stream sold at the tailgates of our plants. Ethane rejection operations result in a lower volume of equity NGLs with a correspondingly smaller natural gas short position. We operate in this manner when the value of ethane is worth more in the gas stream than as a separate product.

The lower gathering volumes during the twelve months ended December 31, 2009 compared to the same period in the prior year were due to natural declines in the underlying existing wells in addition to reduced drilling activity during 2009. The dramatic fall in commodity prices experienced in the latter part of 2008 and continuing throughout into 2009 has resulted in many of our producer customers significantly reducing drilling activity in the Texas Panhandle, presumably not to be resumed

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until commodity prices rise to levels which justify drilling. While oil prices have recovered from the lows seen in the three months ended March 31, 2009, natural gas prices have improved during the fourth quarter of 2009; however, not to levels that have caused our producers to increase drilling activity back to the 2008 levels.

Our Texas Panhandle Segment primarily covers ten counties in Texas and consists of our East Panhandle System and our West Panhandle System. The drilling activity in the West Panhandle System is not sufficient to offset the natural declines experienced on this system. While our contract mix in the West Panhandle System provides us with a higher equity share of the production, the overall decline will continue and we expect to recover smaller equity production in the future on the West Panhandle System.

The East Panhandle System experienced growth in volumes and equity production due to the active Granite Wash drilling play located in Roberts, Hemphill and Wheeler Counties, Texas through much of 2008; however, due to lower commodity values during the fourth quarter of 2008 continuing through the twelve months of 2009, we experienced a significant decline in drilling activity in this area.

Recent drilling by the largest operators in the Granite Wash play, utilizing horizontal drilling technologies, has resulted in initial natural gas production rates of 6 MMcf/d. These operators believe the economics of the Granite Wash play will be significantly enhanced due to the fewer number of wells and lower capital required to develop the same amount of acreage versus conventional vertical drilling results. We have extensive gathering and processing facilities in Roberts and Hemphill Counties, Texas and long term acreage dedications from several of the larger producers. We believe the Partnership will benefit in the future due to the application of this technology in the Granite Wash play with increased natural gas and condensate production in the East Panhandle System.

The liquids content of the natural gas is lower in the East Texas Panhandle System and our contract mix provides us with a smaller share of equity production as compared to the West Panhandle System. At the current lower drilling activity in the East Panhandle System we would be unable to offset the continued decline on the West Panhandle System of NGL and condensate equity gallons. Our current goal is to aggressively contract for new volumes in the East Panhandle System to offset the decline in volumes and our share of equity production in the West Panhandle System.

Operating Expenses. Operating expenses, including taxes other than income, for the year ended December 31, 2009 were $31.9 million compared to $34.3 million for the year ended December 31, 2008. The major items impacting the $2.4 million decrease in operating expenses for the year ended December 31, 2009 were primarily due to overall cost reduction initiatives implemented by the Partnership across the segment.

Depreciation and Amortization. Depreciation and amortization expenses for the year ended December 31, 2009 were $46.1 million compared to $43.7 million for the year ended December 31, 2008. The major item impacting the $2.4 million increase was depreciation expense associated with the capital expenditures placed into service during the period.

Capital Expenditures. Capital expenditures for the year ended December 31, 2009 were $7.3 million as compared to $30.7 million for the year ended December 31, 2008. We classify capital expenditures as either maintenance capital (which represents routine well connects and capitalized maintenance activities) or as growth capital (which represents organic growth projects). In the year ended December 31, 2009, growth capital represented 39% of our capital expenditures as compared to 70%, respectively, in the year ended December 31, 2008. The decrease in capital expenditures of $23.4 million was driven by reduced maintenance capital associated with fewer new well connects due to the lower drilling activity and by less growth capital due to expenditures related to our Stinnett - Cargray plant consolidation project having occurred in the year ended December 31, 2008.

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East Texas/Louisiana Segment



	Twelve Months Ending December 31,
	2009		2008(b)
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Sales of natural gas, NGLs, oil and condensate	$	181,550	$	298,720
Gathering and treating services	27,968		23,320
Total revenues	209,518		322,040
Cost of natural gas and natural gas liquids	162,957		269,030
Operating costs and expenses:
Operations and maintenance	17,985		16,569
Depreciation and amortization	17,188		13,559
Impairment	5,941		26,994
Total operating costs and expenses	41,114		57,122
Operating (loss) income	$	5,447	$	(4,112	)

Capital expenditures	$	18,188	$	17,391

Realized prices:
Oil and condensate (per Bbl)	$	63.34	$	101.62
Natural gas (per Mcf)	$	3.83	$	8.75
NGLs (per Bbl)	$	35.87	$	54.66
Production volumes:
Gathering volumes (Mcf/d)(a)	248,597		198,365
NGLs and condensate (net equity gallons)	19,924,820		27,038,450
Condensate (net equity gallons)	2,381,123		1,580,928
Natural gas short position (MMbtu/d)(a)	2,851		1,427

________________________


(a)	Gathering volumes (Mcf/d) and natural gas short position (MMbtu/d) are calculated by taking the total volume and then dividing by the number of days in the respective period.


(b)	Includes operations related to the Millennium Acquisition starting on October 1, 2008.

Revenue and Cost of Natural Gas and Natural Gas Liquids. For the year ended December 31, 2009, revenues minus cost of natural gas and natural gas liquids for our East Texas/Louisiana Segment totaled $46.6 million compared to $53.0 million for the year ended December 31, 2008.

In October 1, 2008, we acquired Millennium Midstream Partners, L.P. (the "Millennium Acquisition"). With this acquisition, we acquired a natural gas gathering and processing business, with assets located in East, Central and West Texas and South Louisiana. The Millennium Acquisition positively impacted the East Texas/Louisiana Segment's revenue minus cost of natural gas and natural gas liquids by $15.3 million during the year ended December 31, 2009. Our lower NGL equity gallons for 2009 were primarily due to operating the facilities in ethane rejection mode during much of the first two months of 2009. Ethane rejection mode is when we elect to not recover the ethane component in the natural gas stream in our plants and instead choose to leave the ethane component in the residue gas stream sold at the tailgates of our plants. We operate in this manner when the value of ethane is worth more in the gas stream than as a separate product.

We were negatively impacted by lower NGL and condensate pricing during 2009 as compared to 2008. We were positively impacted by 38% growth in gathering volume during 2009 compared to 2008 due to the Millennium Acquisition. Other East Texas/Louisiana Segment gathering systems realized a reduction in volumes. Excluding the Millennium Acquisition, our gathering volumes decreased by 11%. The offsetting reduction in higher margin gas volumes is being replaced with lower

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margin, fixed fee volumes from the Millennium Acquisition. The 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 in order to meet the pipelines' gas quality tariff requirements. The lower margin gas, though contributing to a significant increase in overall gathered volumes, has not offset the lower revenues and margins due to the lower NGL, condensate and natural gas prices during 2009 as compared to the same time period in 2008. During the last three months of 2008 and continuing into 2009, we saw a significant reduction in our customer's drilling activity due to lower commodity values.

During the month of September 2009, two producers curtailed their gas production due to low natural gas prices by a total of approximately 17,500 Mcf/d for the month delivered to the Brookeland Plant and Tyler County gathering system. As of December 31, 2009, no production remains curtailed due to natural gas prices.

Operating Expenses. Operating expenses for the year ended December 31, 2009 were $18.0 million compared to $16.6 million for the year ended December 31, 2008. The major item impacting the $1.4 million increase in operating expense for 2009 was due to expenses associated with operating the assets acquired as part of the Millennium Acquisition. The year ended December 31, 2009 includes twelve months of activity for the assets acquired as part of the Millennium Acquisition compared to three months in the year ended December 31, 2008. Excluding operating expenses related to the assets acquired as part of the Millennium Acquisition, operating expenses were relatively flat for 2009 as compared to the same period in 2008.

Depreciation and Amortization. Depreciation and amortization expenses for the year ended December 31, 2009 were $17.2 million compared to $13.6 million for the year ended December 31, 2008. The major items impacting the $3.6 million increase were (i) twelve months of depreciation and amortization of the assets acquired as part of Millennium Acquisition and (ii) depreciation expense associated with the capital expenditures placed into service. These increases were offset by an adjustment of $0.9 million recorded during the three months ended June 30, 2009 to correct an overstatement of depreciation expense in a prior period.

Impairment. During the year ended December 31, 2009, we incurred impairment charges of $5.9 million in our Midstream segment as a result of reduced throughput volumes as our producer customers curtailed their drilling activity in response to lower natural gas prices. During the year ended December 31, 2008, the Partnership recorded an impairment charge related to certain processing plants, pipelines and contracts in its Midstream business of $27.0 million due to the substantial decline in commodity prices in the fourth quarter as well as declining drilling activity by its producer customers.

Capital Expenditures. Capital expenditures for the year ended December 31, 2009 were $18.2 million compared to $17.4 million for the year ended December 31, 2008. During 2009, of our capital spending in this segment, we spent $10.8 million on growth capital and $7.4 million on maintenance capital. We classify capital expenditures as either maintenance capital, which represents routine well connects and capitalized maintenance activities, or as growth capital, which represents organic growth projects. Our increase in capital spending for 2009 is due primarily to the construction of gathering lines to producers in the Brookeland and Tyler County gathering systems.

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South Texas Segment



	Twelve Months Ending December 31,
	2009			2008
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Sales of natural gas, NGLs, oil and condensate	$	74,336		$	162,782
Gathering and treating services	4,137			4,405
Other	3			15
Total revenues	78,476			167,202
Cost of natural gas and natural gas liquids	73,785			156,549
Operating costs and expenses:
Operations and maintenance	1,904			2,489
Depreciation and amortization	3,599			3,804
Impairment	7,733			8,105
Total operating costs and expenses	13,236			14,398
Operating income (loss) from continuing operations	(8,545		)	(3,745		)
Discontinued operations	503			1,823
Operating income (loss)	$	(8,042	)	$	(1,922	)

Capital expenditures	$	69		$	1,145

Realized volumes:
Oil and condensate (per Bbl)	$	50.83		$	92.10
Natural gas (per Mcf)	$	3.76		$	8.99
NGLs (per Bbl)	$	32.26		$	52.66
Production volumes:
Gathering volumes (Mcf/d)(a)	77,622			84,970
NGLs and condensate (net equity gallons)	338,981			201,683
Condensate (net equity gallons)	526,094			1,620,117
Natural gas short position (MMbtu/d)(a)	902			500

________________________


(a)	Gathering volumes (Mcf/d) and natural gas short position (MMbtu/d) are calculated by taking the total volume and then dividing by the number of days in the respective period.

Revenue and Cost of Natural Gas and Natural Gas Liquids. During the year ended December 31, 2009 the South Texas Segment contributed revenues minus cost of natural gas and natural gas liquids of $4.7 million, as compared to $10.7 million for the year ended December 31, 2008. We were negatively impacted by lower NGL, natural gas and condensate pricing during 2009 as compared to the same period in 2008.

Operating Expenses. Operating expenses for the year ended December 31, 2009 were $1.9 million, as compared to $2.5 million for the year ended December 31, 2008.

Depreciation and Amortization. Depreciation and amortization expenses for the year ended December 31, 2009 were $3.6 million, as compared to $3.8 million for the year ended December 31, 2008.

Impairment. During the year ended December 31, 2009, we incurred impairment charges of $7.7 million in our Midstream segment as a result of reduced throughput volumes as our producer customers curtailed their drilling activity in response to lower natural gas prices. During the year ended December 31, 2008, the Partnership recorded an impairment charge related to certain processing plants, pipelines and contracts in its Midstream business of $8.1 million due to the substantial

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decline in commodity prices in the fourth quarter as well as declining drilling activity by its producer customers.

Capital Expenditures. Capital expenditures for the year ended December 31, 2009 were $0.1 million as compared to $1.1 million for the year ended December 31, 2008. During the year ended December 31, 2009, we spent $0.1 million on maintenance capital. The decrease in capital expenditures in 2009 compared to 2008 was the result of a reduction in drilling activity during 2009.

Discontinued Operations. On April 1, 2009, we sold our producer services line of business, and thus have retrospectively classified the revenues minus the cost of natural gas and natural gas liquids as discontinued operations. During the year ended December 31, 2009, this business generated revenues of $19.2 million and cost of natural gas and natural gas liquids of $18.9 million, as compared to revenues of $265.1 million and cost of natural gas and natural gas liquids of $263.3 million during the year ended December 31, 2008.

In February 2011, we classified the assets and liabilities of our Wildhorse Gathering System as held for sale and thus have retrospectively classified the operations as discontinued. During the year ended December 31, 2009, the Wildhorse Gathering System generated revenues of $21.8 million and operating income of $0.2 million. During the year ended December 31, 2008, the Wildhorse Gathering System generated revenues of $6.5 million and operating income of less than $0.1 million.

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Gulf of Mexico Segment



	Three Months Ending December 31,
	2009			2008 (b)
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Sales of natural gas, NGLs, oil and condensate	$	31,161		$	952
Gathering and treating services	864			703
Other	1,616			—
Total revenues	33,641			1,655
Cost of natural gas and natural gas liquids	26,372			1,376
Operating costs and expenses:
Operations and maintenance	1,907			605
Depreciation and amortization	6,576			1,521
Total operating costs and expenses	8,483			2,126
Operating loss	$	(1,214	)	$	(1,847	)

Capital Expenditures	358			—

Realized average prices:
Oil and condensate (per Bbl)	$	59.11		$	—
Natural gas (per Mcf)	$	4.64		$	6.64
NGLs (per Bbl)	$	35.52		$	20.58
Production volumes:
Gathering volumes (Mfc/d)(a)	116,492			12,014
NGLs and condensate (net equity gallons)	5,768,018			176,962

________________________


(a)	Gathering volumes (Mcf/d) are calculated by taking the total volume and then dividing by the number of days in the respective period.


(b)	Includes operations related to the Millennium Acquisition starting on October 1, 2008.

Revenues and Cost of Natural Gas and Natural Gas Liquids. The Gulf of Mexico Segment was a new segment and new area of operations for us in 2008. We entered into this segment as a result of the Millennium Acquisition, effective October 1, 2008. During the year ended December 31, 2009, the Gulf of Mexico Segment contributed $7.3 million in revenues minus cost of natural gas and natural gas liquids compared to $0.3 million in the year ended December 31, 2008. As a result of damage inflicted by Hurricanes Gustav and Ike in August 2008 and September 2008, respectively, the Yscloskey plant did not come back online until mid-January 2009 and the North Terrebonne plant did not come back online until mid-November 2008. We received a partial payment of approximately $1.6 million for business interruption caused by Hurricanes Gustav and Ike which we recognized as other revenue during the three months ended June 30, 2009.

Operating Expenses. Operating expenses for the year ended December 31, 2009 were $1.9 million compared to $0.6 million in the year ended December 31, 2008. We continued to incur operating expenses associated with the Yscloskey and North Terrebonne plants while the plants were undergoing repair for the hurricane damage. We also incurred costs for the repair of the two plants. Such costs were recovered from the escrow account established pursuant to the Millennium Acquisition purchase and sale agreement. As a result and pursuant to the agreement, any insurance proceeds received for repair costs will be deposited into the escrow account. During 2009, we received payment from the Millennium Acquisition escrow of the remaining $0.3 million in cash and continued canceling common units held in escrow to satisfy additional claims.

Depreciation and Amortization. Depreciation and amortization expenses for the year ended December 31, 2009 were $6.6 million compared to $1.5 million for the three months in 2008 that we owned the assets acquired in the Millennium Acquisition.

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Capital Expenditures. Capital expenditures for 2009 for the Gulf of Mexico Segment were $0.4 million. We did not incur any capital expenditures related to the Gulf of Mexico Segment in 2008.

Upstream Segment



	Twelve Months Ending December 31,
	2009			2008 (a)
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Oil and condensate	$	35,316		$	72,526
Sulfur	—			37,759
Natural gas (b)	12,021			32,513
NGLs	16,057			29,530
Other	239			701
Total revenues	63,633			173,029
Operating Costs and expenses:
Operations and maintenance (c)	28,536			37,481
Other operating expense	(3,552		)	—
Depletion, depreciation and amortization	34,009			44,997
Impairment	8,114			107,017
Goodwill impairment	—			30,994
Total operating costs and expenses	67,107			220,489
Operating (loss) income	$	(3,474	)	$	(47,460	)

Capital expenditures	$	8,437		$	20,655

Realized average prices (d):
Oil and condensate (per Bbl)	$	45.30		$	87.04
Natural gas (per Mcf)	$	3.69		$	8.09
NGLs (per Bbl)	$	31.90		$	61.39
Sulfur (per Long ton)	$	—		359,96
Production volumes (e):
Oil and condensate (Bbl)	811,075			823,316
Natural gas (Mcf)	3,659,431			4,117,247
NGLs (Bbl)	504,669			480,450
Total (Mcfe)	11,553,895			11,939,843
Sulfur (Long ton)	119,812			104,613

________________________


(a)	Includes operations from the Stanolind Acquisition effective May 1, 2008.


(b)	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.


(c)	Includes costs to dispose of sulfur in our Upstream segment of $2.2 million for the year ended December 31, 2009.


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


(e)	Volumes and realized prices for the year ended December 31, 2008 have been adjusted from prior reported amounts for a reallocation which was recorded in December 2009.

Revenue. For the year ended December 31, 2009, the Upstream Segment contributed $63.6 million of revenue as compared to $173.0 million for the year ended December 31, 2008. On April 30, 2008, we acquired all of Stanolind Oil and Gas Corp. (the "Stanolind Acquisition"). With this acquisition, we acquired crude oil and natural gas producing properties in the Permian Basin of West Texas, primarily in Ward, Crane and Pecos Counties. The decrease in revenue was due to substantially lower realized prices for oil, natural gas, NGLs and sulfur and the non-cash mark-to-market of product imbalances, partially offset by

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an additional four months of operations related to the assets acquired in the Stanolind Acquisition. During 2009, production averaged 10.3 MMcf/d of natural gas, 2.2 MBO/d of oil and condensate, 1.4 MB/d of NGL's and 328 LT/d of sulfur. The period included twelve months of production from the assets acquired in the Stanolind Acquisition which averaged 812 Boe/d. During 2009, the Big Escambia Creek (BEC) plant experienced reduced oil, residue gas and NGL sales due to unanticipated repairs and overhauls to the plant's residue gas compressors. Sales of oil, residue gas and NGLs from BEC, Flomaton and Fanny Church fields were curtailed for 60 days, during 2009 associated with the compressors' downtime. The reduced production during these periods negatively impacted Upstream revenues by approximately $2.6 million.

During 2009, the cost to dispose sulfur exceeded the sales price by $2.2 million compared to revenue of $37.8 million during 2008. Historically, sulfur was viewed as a low value by-product in the production of oil and natural gas. Due to an increase in demand in the global fertilizer market during the first nine months of 2008, the price per long ton (before effects of net-backs) peaked at over $600 at the Tampa, Florida market in September 2008. Deterioration in the sulfur market during 2009 has caused the price at the Tampa, Florida market to decline to a range of $0 to $30 per long ton. Currently in the first quarter 2010, the Tampa, Florida sulfur market has improved to $90 per long ton.

Operating Expenses. Operating expenses, including severance and ad valorem taxes, totaled $28.5 million for the Upstream Segment during the year ended December 31, 2009, as compared to $37.5 million for the year ended December 31, 2008. The operating expenses include twelve months of expenses related to the assets acquired in the Stanolind Acquisition during 2009 compared to only eight months for the same period in 2008. The decrease in operating expense can be attributed to lower well workover expense incurred during 2009 as compared to the same period in the prior year and additional expenses being incurred during 2008 due to the turnaround at the BEC treating facility in April 2008. The decrease during 2009 is also due to 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.

Depletion, Depreciation and Amortization. Depletion, depreciation and amortization expense for the year ended December 31, 2009 was $34.0 million, as compared to $45.0 million for the year ended December 31, 2008. The decrease for 2009 compared to the comparable period in 2008 is due to the decrease in our depletable base as a result of the impairment charges we incurred during the last three months of fiscal year 2008. This decrease was partially offset by the depletion expense related to the assets added through the Stanolind Acquisition for 2009 compared to only eight months during the same period in 2008 and the curtailed production during 2008 due to the turnaround at the BEC treating facility in April 2008.

Other Operating Income. Other operating income for the year ended December 31, 2009, includes income of $3.6 million due to the recovery of $2.2 million of assets previously written off and the release of $1.4 million of liabilities assumed as part of our purchase price allocation for our acquisitions of Escambia Asset Co. LLC and Redman Energy Holdings, L.P. During the period, we received additional information about collectability of these assets and determined that we no longer had any obligation under these liabilities.

Impairment. During the year ended December 31, 2009, we incurred impairment charges of $8.1 million in our Upstream Segment, of which, $7.9 million was a result of a decline in natural gas prices, production declines and lower natural gas liquids yields at our Flomaton field and $0.2 million in other fields due to lower natural gas prices. During the year ended December 31, 2008, we incurred impairment charges related to certain fields of $107.0 million due to the substantial decline in commodity prices during the fourth quarter of 2008. As a result of the impairment charge in the year ended December 31, 2008, we assessed our goodwill balance for impairment and recorded an impairment charge to goodwill of $31.0 million.

Capital Expenditures. The Upstream Segment's maintenance capital expenditures for the year ended December 31, 2009 totaled $8.4 million compared $20.7 million for the year ended December 31, 2008. We did not incur any growth capital expenditures during 2009 or 2008. The maintenance capital expenditures during 2009 were associated with compressor overhauls at the BEC and Flomaton treating facilities and well completions, recompletions, workovers, equipping and leasing activities. The higher maintenance capital expenditures in 2009 were related primarily to a planned turnaround at our Big Escambia Creek (“BEC”) facility.

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Corporate Segment



	Twelve Months Ending December 31,
	2009			2008
	($ in thousands)
Revenues:
Realized commodity derivatives gains (losses)	$	83,300		$	(46,059	)
Unrealized commodity derivatives gains (losses)	(189,590		)	207,824
Total revenues	(106,290		)	161,765
General and administrative	45,819			45,618
Depreciation and amortization	1,073			787
Other expense	—			10,699
Operating income (loss)	(153,182		)	104,661
Other income (expense):
Interest income	187			771
Other income	934			1,318
Interest expense	(21,591		)	(32,884		)
Unrealized interest rate derivative losses	12,529			(27,717		)
Realized interest rate derivative gains (losses)	(18,876		)	(5,214		)
Other expense	(1,070		)	(955		)
Total other income (expense)	(27,887		)	(64,681		)
Gain (loss) from continuing operations before taxes	(181,069		)	39,980
Income tax (benefit) provision	989			(1,459		)
Gain (loss) from continuing operations	(182,058		)	41,439
Discontinued operations, net of tax	9,074			35,377
Segment gain (loss)	$	(172,984	)	$	76,816

Revenue. As a master limited partnership, we distribute available cash (as defined in our partnership agreement) every quarter to our unitholders subject to reserves established by our Board of Directors. Our distribution policy, including a description of the right to make reserves against available cash, is discussed in greater detail in Part II, Item 5. Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities - Cash Distribution Policy.

The volatility inherent in commodity prices generates uncertainty in future levels of available cash. We enter into derivative transactions to reduce our exposure to commodity price risk and reduce the uncertainty of future cash flows.

Our Corporate Segment's revenue, which solely includes our commodity derivatives activity, decreased to a loss of $106.3 million for the year ended December 31, 2009, from a gain of $161.8 million for the year ended December 31, 2008. As a result of our commodity hedging activities, revenues include total realized gains of $83.3 million on risk management activity settled during the year ended December 31, 2009 and unrealized mark-to-market losses of $189.6 million for the year ended December 31, 2009, as compared to realized losses of $46.1 million and unrealized mark-to-market gains of $207.8 million for the year ended December 31, 2008. Included in unrealized commodity derivative (losses) gains is amortization related to put premiums and costs associated with the resetting of derivative contract prices of $48.4 million during the year ended December 31, 2009 as compared to $13.3 million for the year ended December 31, 2008.

As the forward price curves for our hedged commodities shift in relation to the caps, floors, and swap strike prices, the fair value of such instruments changes. We capture this change as unrealized, non-cash, mark-to-market changes during the period of the change. The unrealized mark-to-market changes for the year ended December 31, 2009 and 2008 had no impact on cash activities for those periods and, as such, are excluded from our calculation of Adjusted EBITDA. The realized commodity derivatives results during the year ended December 31, 2009 reflect the difference between the strike prices and settlement prices for derivative volumes settled during the year. As such, the realized amounts impact our cash flows and are included in our calculation of Adjusted EBITDA.

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marking our hedges to market will have on our income from operations in future periods. Conversely, negative commodity price movements affecting our revenues and costs are expected to be partially offset by our executed derivative instruments.

General and Administrative Expenses. General and administrative expenses increased by $0.2 million to $45.8 million for 2009 as compared to $45.6 million for 2008. This growth in general and administrative expenses was primarily driven by increased headcount in our corporate office as a result of our 2008 acquisitions but was also impacted by our recruiting efforts in accounting, back-office, engineering, land and operations-related corporate personnel associated with being a public partnership. Corporate-office payroll expenses increased by $2.8 million in 2009 as a result of the increased headcount. Included within the increased corporate-office payroll expenses was an decrease of $1.0 million related to equity-based compensation, of which 2009 includes $0.4 million related to the allocation of expense from Eagle Rock Holdings, L.P. due to its issuance of Tier I units to one of our executives, as compared to $1.6 million in 2008. Also included in 2009 was a one time charge of $0.1 million for severance payments due to a reduction in workforce. As a result of the increase in our expenses for corporate-office headcount, contract labor and other outside professional services decreased by $2.6 million in 2009 as compared to the same period in 2008. In addition, 2009 included legal and other professional advisory fees of $0.9 million incurred related to strategic discussions regarding our capital structure and proposals received regarding the sale of the Minerals Business.

At the present time, we do not allocate our general and administrative expenses cost to our operational segments. The Corporate Segment bears the entire amount.

Other Operating Expenses. In July 2008, SemGroup, L.P. and certain of its subsidiaries (“SemGroup”) filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. We historically sold portions of our condensate production from our Texas Panhandle and East Texas midstream systems to SemGroup. During July 2008, we sold pre-bankruptcy, and continued to sell post-bankruptcy, condensate to SemGroup. As of August 1, 2008, we ceased all deliveries/sales of condensate to SemGroup. As a result of the bankruptcy we recorded a $10.7 million bad debt charge during the year ended December 31, 2008 which is included in “Other Operating Expense” in the consolidated statement of operations. Although we sought payment of our $10.7 million receivable for condensate sales as a critical supplier to SemGroup under its Supplier Protection Program (“SPP”), we were not successful in being recognized as a critical provider by SemGroup and thus were not admitted to the SPP.

Total Other Expense. Total other expense, which includes both realized and unrealized gains and losses from our interest rate swaps, decreased to $27.9 million for the year ended December 31, 2009 as compared to $64.7 million for the year ended December 31, 2008. During 2009, we incurred realized losses from our interest rate swaps of $18.9 million as compared to realized losses of $5.2 million during the year ended December 31, 2008. We also incurred unrealized mark-to-market gains from our interest rate swaps of $12.5 million during the year ended December 31, 2009 as compared to unrealized mark-to-market losses of $27.7 million for the same period in 2008. These unrealized mark-to-market losses did not have any impact on cash activities for the period, and are excluded by definition from our calculation of Adjusted EBITDA.

Interest expense decreased to $21.6 million for the year ended December 31, 2009 as compared to $32.9 million during the same period in the prior year. Interest expense is shown before the impact of our interest rate derivatives, which convert a portion of our outstanding debt from variable-rate interest obligations to fixed-rate interest obligations. All of our outstanding debt consists of borrowings under our revolving credit facility, which bears interest primarily based on a LIBOR rate plus the applicable margin. The decrease in interest expense is due to lower LIBOR rates during 2009, as compared to the same period in 2008, partially offset by higher debt balances in the 2009 period as a result of our acquisitions made in 2008.

Income Tax (Benefit) Provision. Income tax provision for the 2009 and 2008 relates to (i) state taxes due by us and (ii) federal taxes due by Eagle Rock Energy Acquisition Co., Inc. (acquiring entity of certain entities acquired in the acquisition of Redman Energy Corporation “Redman Acquisition” in 2007) and Eagle Rock Energy Acquisition Co. II, Inc. (acquiring entity of certain entities acquired in the Stanolind Acquisition) and their wholly-owned corporations, Eagle Rock Upstream Development Company, Inc. (successor entity to certain entities acquired in the Redman acquisition) and Eagle Rock Upstream Development Company II, Inc. (successor entity to certain entities acquired in the Stanolind acquisition), which are subject to federal income taxes (the “C Corporations”). During 2009, our tax provision increased by $2.4 million as compared to the same periods in the prior year. These increases were the result of 2009 income projected for the C Corporations resulting from utilization of our remaining net operating loss carryforwards, adjustments to true-up of the results of 2008 tax return and our 2008 tax provision, as well as changes in estimates used in our tax provision calculation in prior periods. For further discussion of our income tax (benefit) provision, see Note 15 to our consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data staring on page F-1 of this Annual Report.

Discontinued Operations. On May 24, 2010, we completed the sale of our Minerals Business. For the year ended December 31, 2009, we generated revenues of $15.7 million and income from operations of $7.8 million. For the year ended

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December 31, 2008, we generated revenues of $43.0 million and income loss from operations of $31.7 million. During the years ended December 31, 2009 and 2008, the Partnership incurred state tax expense on discontinued operations of $0.2 million and $0.4 million, respectively. During the years ended December 31, 2009 and 2008, we recorded a gain (loss) to discontinued operations, excluding the gain recognized by us on the sale of the Minerals Business, of $9.1 million and $35.4 million, respectively.

Adjusted EBITDA.

Adjusted EBITDA, as defined under Part II, Item 6. Selected Financial Data - Non-GAAP Financial Measures, decreased by $33.8 million from $206.4 million for the year ended December 31, 2008 to $172.6 million for the year ended December 31, 2009.

As described above, revenues minus cost of natural gas and natural gas liquids for the Midstream Business (including the Texas Panhandle, East Texas/Louisiana, South Texas and Gulf of Mexico Segments) decreased by $62.5 million during the year ended December 31, 2009, as compared to the comparable period in 2008. The Upstream Segment decreased an additional $108.7 million to revenues during the year ended December 31, 2009, as compared to the comparable period in 2008. Our Corporate Segment's realized commodity derivatives gain increased by $129.4 million during the year ended December 31, 2009 as compared to the comparable period in 2008. This resulted in a negative $41.8 million of total incremental revenues minus cost of natural gas and natural gas liquids during the year ended December 31, 2009 as compared to the comparable period in 2008. The incremental revenue amounts are adjusted to exclude the impact of unrealized commodity derivatives not included in the calculation of Adjusted EBITDA.

Operating expenses (including taxes other than income) for our Midstream Business increased by $0.3 million for the year ended December 31, 2009, as compared to the same period in 2008, while Operating Expenses (including taxes other than income) for the Upstream Segment decreased $8.9 million for the year ended December 31, 2009, as compared to the comparable period in 2008.

General and administrative expense, excluding the impact of non-cash compensation charges related to our long-term incentive program, Holding's Tier I incentive units and other non-recurring items and captured within our Corporate Segment, increased during the year ended December 31, 2009 by $1.2 million, as compared to the respective period in 2008.

As a result, revenues (excluding the impact of unrealized commodity derivative activity) minus cost of natural gas and natural gas liquids for the year ended December 31, 2009, as compared to the same period in 2008 decreased by $41.8 million, operating expenses decreased by $9.2 million and general and administrative expenses increased by $1.2 million. The decreases in revenues minus the cost of natural gas and natural gas liquids, the decreases in operating costs offset by the increase in general and administrative expenses resulted in a decrease to Adjusted EBITDA during the year ended December 31, 2009, as compared to the year ended December 31, 2008. Adjusted EBITDA excludes amortization of commodity hedge costs (including costs of hedge reset transactions) for the years ended December 31, 2009 and 2008 of $48.4 million and $13.3 million, respectively. Including these amortization costs, our Adjusted EBITDA for the years ended December 31, 2009 and 2008 would have been $124.2 million and $193.1 million, respectively.

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LIQUIDITY AND CAPITAL RESOURCES

Historically, our sources of liquidity have included cash generated from operations, equity investments by our existing owners, equity investments by other institutional investors and borrowings under our revolving credit facility. We believe that the cash generated from these sources will continue to be sufficient to meet all of our expected liquidity needs, which include our requirements for short-term working capital, long-term capital expenditures for maintenance and organic growth and our expected quarterly cash distributions. In the event we acquire additional midstream assets or natural gas or oil properties at purchase prices that exceed our existing capital resources, we expect that we will finance those acquisitions with a combination of expanded or new debt facilities, and new equity and debt issuances through the capital markets.

Our distribution policy is to distribute to our unitholders, on a quarterly basis, all of our available cash in the manner described below and as further described in our partnership agreement. Available cash generally means, for any quarter ending prior to liquidation, all cash on hand at the end of that quarter less the amount of cash reserves that the general partner determines to establish to:


•	provide for the proper conduct of our business, including for future capital expenditures and credit and other needs;


•	comply with applicable law or any partnership debt instrument or other agreement; or


•	provide funds for distributions to unitholders and the general partner in respect of any one or more of the next four quarters.

The actual distributions we will declare will be subject to our operating performance, prevailing market conditions (including forward oil, natural gas and sulfur prices), the impact of unforeseen events and the approval of our Board of Directors and will be done pursuant to our distribution policy.

In response to, in part, a lack of liquidity due to our high leverage levels and restricted access to the capital markets during 2009, our Board of Directors determined to reduce the quarterly distribution with respect to the first quarter of 2009 (and sustain such reduced quarterly distribution through the distributions for the third quarter of 2010). This decision was made to establish cash reserves (as against available cash) for the proper conduct of our business and to enhance our ability to remain in compliance with financial covenants under our revolving credit facility in future periods. The cash not distributed was used to reduce our outstanding debt under our revolving credit facility, to continue to execute our hedge strategy to maintain future cash flows and/or to fund growth capital expenditures.

Our goal is to reduce our ratio of outstanding debt to Adjusted EBITDA, or “leverage ratio,” both on a total Partnership basis and with respect to the definition of Total Leverage Ratio under our revolving credit facility (which is based on the outstanding borrowings allocated to, and the Adjusted EBITDA generated by, our Midstream Business), to approximately 3.0 to 3.5 on a sustained basis. We believe this leverage ratio range to be appropriate for our business and more in-line with historical midstream industry standards. We plan to achieve this goal by, without limitation, reducing outstanding indebtedness and investing in attractive organic growth and acquisition opportunities. As of December 31, 2010, our Total Leverage Ratio was 4.3. During the year ended December 31, 2010, we reduced our outstanding debt under the revolving credit facility by $224.4 million to $530.0 million, and since March 31, 2009, we have reduced our outstanding indebtedness under the revolving credit facility by $307.4 million. We do not expect to be able to maintain this level of debt reduction during 2011. We expect our efforts to reduce our leverage ratio to our desired range during 2011 will be primarily through investing in attractive growth opportunities which will increase our Adjusted EBITDA. We also expect our leverage ratio to benefit from any exercise of our approximately 20.7 million warrants outstanding as of December 31, 2010, which carry an exercise price of $6.00 per common unit and expire on May 15, 2012. Total proceeds to the Partnership from the warrants, if exercised in full, would total approximately $124 million. It is our intention to use future proceeds from warrants being exercised, if any, to pay for general partnership purposes, including to pay down borrowings outstanding under our revolving credit facility, absent any organic growth or acquisition opportunities.

Given the improvement in our liquidity during 2010, we announced an increase in the quarterly distribution to an annualized rate of $0.60 per unit with respect to the fourth quarter of 2010 (paid on February 14, 2011). Given our current outlook, we intend to recommend to the Board further quarterly increases in the distribution throughout 2011, with the expectation and objective of reaching an annualized distribution rate of $0.75 per unit beginning with respect to the fourth quarter of 2011 (payable in February 2012). Actual future increases in the distribution level, if any, will be driven by market conditions, future commodity prices, our leverage levels, the performance of our underlying assets and our ability to consummate accretive growth projects or acquisitions. Management's distribution recommendation is subject to change should factors affecting the general business climate or our specific operations differ from current expectations. All actual distributions

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paid will be determined and declared at the discretion of the Board, regardless of our recommendation.

For a detailed description of our revolving credit facility, see Note 7 to our consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data and below under “Revolving Credit Facility and Debt Covenants.”

Cash Flows

From January 1, 2009 through December 31, 2010, the key events that have had major impacts on our cash flows are:


•	the sale of our Minerals Business to Black Stone Minerals Company for approximately $171.6 million;


•	a rights offering for which we received gross proceeds of $53.9 million and issued 21,557,164 common units and 21,557,164 warrants to purchase common units;


•	the completion of the refurbishment of our Phoenix Plant and its installation in our Texas Panhandle region for a cost of $24.3 million;


•	the acquisition of certain additional interest in the Big Escambia Creek Field (and the nearby Flomaton and Fanny Church fields) from Indigo Minerals, LLC for approximately $3.9 million in cash on hand; and


•	the acquisition of certain natural gas gathering systems and related facilities from Centerpoint Energy Field Services, Inc. for $27.0 million in cash drawn from our revolver and cash on hand.

Cash Distributions.

On February 4, 2009, we declared a $0.41 per unit distribution on all outstanding units (including common units, general partner units, and subordinated units) for the fourth quarter of 2008, payable on February 13, 2009 to the unitholders of record on February 10, 2009. The distribution to the common units, general partner units and subordinated units was paid on February 13, 2009.

With respect to the first quarter 2009 through the third quarter 2010, we declared a quarterly cash distribution of $0.025 to our general partner (as to its general partner units through our first quarter 2010) and our common unitholders (except for the restricted units granted on October 27, 2010) as of each record date. The total combined distribution amount was $9.3 million.

On January 27, 2011, we declared our fourth quarter 2010 cash distribution of $0.15 per unit to our common unitholders of record as of February 7, 2011. The distribution was paid on February 14, 2011.

Working Capital.

Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. As of December 31, 2010, working capital was a negative $61.1 million as compared to negative $60.3 million as of December 31, 2009, excluding assets and liabilities held for sale.

The net decrease in working capital of $0.8 million from December 31, 2009 to December 31, 2010, resulted primarily from the following factors:


•	cash balances and marketable securities, net of due to/from affiliates, increased overall by $1.3 million;


•	trade accounts receivable decreased by $10.1 million primarily from the impact of slightly lower revenues, increased collection efforts and realized settlement losses on our commodity derivatives;


•	risk management net working capital balance increased by a net $9.8 million as a result of changes in current portion of mark-to-market unrealized positions, the adjustment of the strike price of certain derivative instrument (see Hedging Strategy) and the amortization of put premiums and other derivative costs;


•	accounts payable increased by $2.5 million from December 31, 2009 primarily as a result of activities and timing of payments, including capital expenditures activities; and

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•	accrued liabilities increased by $0.2 million primarily reflecting payment of employee benefit accruals, lower interest payments and the timing of payment of unbilled expenditures related primarily to capital expenditures.

Cash Flows Year Ended 2010 Compared to Year Ended 2009

Cash Flow from Operating Activities. Cash flows from operating activities increased $16.9 million during 2010 as compared to 2009 as a result of higher commodity prices across our two businesses. These higher commodity prices resulted in higher cash flows from the sale of our equity crude oil, natural gas and NGLs volumes and higher cash flows from the sale of sulfur. Higher commodity prices also resulted in us realizing net settlement losses on our commodity derivatives during 2010, of which $1.1 million of cash received was reclassified to cash from financing activities, compared to $8.9 million of cash received being reclassified during 2009. In addition, our cash flows from operations for the year ended December 31, 2010 includes a payment of $5.9 million to adjust the strike price on an existing derivative contract and net payments of $2.2 million to unwind certain derivative contracts, as discussed within "Hedging Strategy" below, compared to a payment of $19.6 million to reset certain derivative contracts and payments of $5.6 million to unwind certain derivative contracts included within cash flows from operating activities during 2009.

Cash Flows from Investing Activities. Cash flows provided by investing activities for 2010 were $73.5 million, as compared to cash flows used in investing activities of $37.3 million for 2009, primarily due to the sale of our Minerals Business. The cash inflow from the sale of our Minerals Business was offset by our acquisition of the additional working interests from Indigo Minerals, LLC and certain natural gas gathering systems from CEFS, In 2009 we did not make any acquisitions. In addition, we increased our cash outlays for capital expenditures, in particular spending related to our Phoenix Plant, as compared to our spending on capital expenditures in 2009.

Cash Flows from Financing Activities. Cash flows used in financing activities during 2010 as compared to 2009, increased by $102.2 million. Key differences between periods include net repayments to our revolving credit facility of $224.4 million during 2010 as compared to net repayments of $45.0 million from our revolving credit facility during 2009. We used the proceeds received from the sale of our Minerals Business and the proceeds received from our rights offering, in which we raised gross proceeds of $53.9 million, to pay down borrowings outstanding under our revolving credit facility. Cash outflows related to our distributions decreased to $7.2 million during 2010 as compared to $35.7 million during 2009 as a result of reducing our quarterly distribution to $0.025 for the payments made in 2010 (for the fourth quarter of 2009 and first three quarters of 2010) from $0.41 paid in the first quarter of 2009 (for the fourth quarter of 2008), coupled with $0.025 paid in the last three quarters of 2009 (for the first three quarters of 2009).

Cash Flows Year Ended 2009 Compared to Year Ended 2008

Cash Flow from Operating Activities. Cash flows from operating activities decreased $61.6 million during 2009 as compared to 2008 as a result of lower commodity prices across our three businesses and reduced NGL equity volumes in the Midstream Business. These lower commodity prices resulted in lower cash flows from the sale of our equity crude oil, natural gas and natural gas liquids volumes. In addition, during 2009, we incurred expenses of $2.2 million as the cost to dispose sulfur exceeded the sales price, compared to 2008 in which we recorded revenue related to the sale of sulfur of $37.8 million. The lower commodity prices also had a direct result in the decrease in our working capital. Specifically contributing to the decrease in cash flows from operating activities was the $36.9 million decrease in accounts payable, as discussed above. Lower commodity prices also resulted in us realizing settlement gains during the year ended December 31, 2009, of which $8.9 million of cash received was reclassified to cash from financing activities, compared to $11.1 million of payments being reclassified during 2008. In addition, our cash flows from operating activities for 2009 includes payments of $19.6 million to reset certain derivative contracts and $5.6 million to unwind certain derivative contracts.

Cash Flows from Investing Activities. Cash flows used for investing activities for 2009, as compared to 2008, decreased by $368.0 million due to acquisitions completed in 2008. During 2008, we paid $262.2 million, net of cash acquired, for our acquisitions. During the 2009, we did not make any acquisitions. The investing activities for the current period reflect additions to property, plant and equipment expenditures of $36.1 million versus $66.7 million for the prior year period. This decrease is attributable to lower well-connect activity in our Midstream Business resulting from the reduced drilling activity of our producer customers, as well as lower capital spending associated with the maintenance of our Big Escambia Creek (“BEC”) facility, for which we performed a scheduled turnaround during 2008.

Cash Flows from Financing Activities. Cash flows used for financing activities during 2009 were $73.3 million versus cash flows provided by financing activities of $102.8 million during 2008. Key differences between periods include net payments to our revolving credit facility of $45.0 million during 2009, as compared to net proceeds of $232.3 million from our

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revolving credit facility during 2008. The net proceeds received during 2008, were used for our acquisitions of Stanolind and MMP. Distributions to members decreased to $35.7 million during 2009, as compared to $117.6 million during 2008 as a result of reducing our quarterly distribution to $0.025 from $0.41, as discussed above.

Capital Requirements

We anticipate that we will have sufficient liquidity and access to capital to continue to maintain and commercially exploit our Midstream Business (all four segments) and Upstream Segment assets consistent with our current operations. Additionally, as an operator of midstream and upstream assets, our capital requirements have increased to maintain those assets, hold production and throughput constant and to replace reserves. We anticipate that we will meet these requirements through cash generated from operations. We believe, however, that substantial growth would require access to external capital sources.

The energy business can be capital intensive, requiring significant investment for the acquisition or development of new facilities. We categorize our capital expenditures as either:


•	growth capital expenditures, which are made to acquire or construct additional assets to expand or upgrade our business, or to grow our production in our Upstream Business; or


•	maintenance capital expenditures, which are 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 maintain production in our Upstream Business.

Our 2010 capital budget anticipated that we would spend approximately $40 million in total in 2010 on maintenance and growth capital, excluding acquisitions. We actually spent approximately $73.7 million in total in 2010 due primarily to the installation of the Phoenix Plant in our Texas Panhandle segment and to additional drilling and workover activity in our Upstream Business, particularly in Southern Alabama. In addition, we spent $31.0 million on the acquisition of certain assets from CEFS and Indigo Minerals, LLC.

Our 2011 capital budget anticipates that we will spend approximately $78 million in total for the year. This budget includes capital expenditures for growth, maintenance and well connect projects in both our Midstream and Upstream Segments. We intend to finance our capital expenditures with internally generated cash flow and draws from our revolving credit facility.

Since our inception in 2002, we have made substantial growth capital expenditures. We historically have financed our maintenance capital expenditures (including well-connect costs) with internally generated cash flow and our growth capital expenditures ultimately with draws from our revolving credit facility (although such expenditures were often funded out of internally generated cash flow as an interim step). We anticipate funding our growth capital expenditures, for the foreseeable future, out of cash flow generated from operations, with draws from our revolving credit facility, and, to the extent necessary, issuances of additional equity and debt securities.

Hedging Strategy

We use a variety of hedging instruments to accomplish our risk management objectives. At times our hedging strategy may involve entering into hedges with strike prices above current futures prices or resetting existing hedges to higher price levels in order to meet our cash flow requirements, stay in compliance with our revolving credit facility covenants and continue to execute on our distribution objectives. In addition, we may also terminate or unwind hedges or portions of hedges when the expected future volumes do not support the level of hedges. Hedge transactions such as these impact our liquidity in that we are required to pay the present value of the difference between the hedged price and the current futures price. These transactions also increase our exposure to the counterparties through which we execute the hedges. As part of this strategy, we executed the following hedging transactions during the year ended December 31, 2010;


•	On July 23, 2010, we enhanced our commodity derivative portfolio by adjusting the strike price of certain hedges to the forward market prices as of the date the hedges were executed. Specifically, we paid $5.9 million to adjust the strike price from $53.55 to $79.80 per barrel on existing NYMEX WTI crude oil swaps of 45,000 barrels per month for the five months ending December 31, 2010.


•	On November 23, 2010, we entered into a series of hedging transactions to unwind existing contracts. We unwound; (i) 20,000 barrels a month of an "out-of-the-money" WTI crude oil swap with a price of $80.05, (ii) 15,000 barrels a

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month of a 20,000 barrels a month "out-of-the-money" WTI crude oil swap with a price of $75.00 and (iii)23,000 barrels a month of a "in-the-money" WTI crude oil swap covering 29,000 barrels per month for the first half of the 2011 calendar year and 23,000 barrels a month covering the second half of the 2011 calendar year with a price a $86.20. For these transactions, we paid $2.2 million. We were using these WTI crude oil derivatives to hedge against changes in NGL prices. To continue hedging these NGL volumes, we then entered into the following derivative transactions for the 2011 calendar year on November 23, 2010: a 996,000 gallon per month OPIS normal butane swap at $1.50 per gallon, a 462,000 gallon per month OPIS iso butane swap at $1.5425 per gallon, a 378,000 gallon per month OPIS natural gasoline swap at $1.8525 per gallon, a 1,680,000 gallon per month OPIS propane swap for $1.1165 per gallon and a 252,000 gallon per month OPIS propane swap for $1.11 per gallon.

•

On December 20, 2010, we entered into a 34,000 MMbtu per month Henry Hub natural gas swap at $4.45 per MMbtu. For this swap, we will be paying the fixed price, where normally, for the swaps we enter into, we pay the floating price. We were using a portion of our Henry Hub natural gas swaps to hedge against changes in ethane prices and this transaction effectively unwinds a portions of these swaps. To continue hedging these ethane volumes, we then entered into a 1,428,000 gallon per month OPIS ethane swap at a price of $0.545 per gallon.

For a further discussion of our hedging strategy, see Note 11 to our consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data starting on page F-1 of this Annual Report. For a detail of our open derivative positions as of December 31, 2010, see Part II, Item 7A. Qualitative and Quantitative Disclosure About Market Risk.

Revolving Credit Facility

As of December 31, 2010, our revolving credit facility was comprised of 19 banks with aggregate commitments of $880 million. unused capacity available to us under our credit agreement, based on outstanding debt and total commitments as of that date, was approximately $341 million (before taking into account covenant-based capacity limitations and the approximately $9.1 million of unfunded commitments from Lehman Brothers that is no longer available after Lehman Brothers' bankruptcy filing), on which we pay a commitment fee of 0.3% annually. Historically, our available capacity has been further limited by compliance with the financial covenants in the credit agreement. The credit agreement is scheduled to mature on December 13, 2012.

Given the current state of the banking industry worldwide, we are pleased with the degree of diversification within our lender group. As of today, all of our banks’ commitments, with the exception of Lehman Brothers’ commitment, remain in place and have funded in response to our borrowing notices. A Lehman Brothers subsidiary has an approximately 2.6% participation in our revolving credit facility.

We announced in October 2010 that our existing borrowing base was increased to $140 million from $130 million as part of our regularly scheduled semi-annual borrowing base redetermination. The reaffirmation was effective as of October 1, 2010, with no additional fees or increases in interest rate spread incurred.

Debt Covenants

Our revolving credit facility accommodates, through the use of a borrowing base for our Upstream Business and traditional cash-flow based covenants for our Midstream Business, the allocation of indebtedness to either our Upstream Business (to be measured against the borrowing base) or to our Midstream Business (to be measured against the cash-flow based covenant). At December 31, 2010, we were in compliance with our covenants under the revolving credit facility. Our interest coverage ratio, as defined in the credit agreement (i.e., Consolidated EBITDA divided by Consolidated Interest Expense), was 3.8 as compared to a minimum interest coverage covenant of 2.5, and our leverage ratio, as defined in the credit agreement (i.e., Total Funded Indebtedness divided by Adjusted Consolidated EBITDA), was 4.3 as compared to a maximum leverage ratio of 5.0. We believe that we will remain in compliance with our financial covenants through 2011.

Off-Balance Sheet Obligations.

We have no off-balance sheet transactions or obligations.

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Total Contractual Cash Obligations.

The following table summarizes our total contractual cash obligations as of December 31, 2010.



	Payments Due by Period
Contractual Obligations	Total		2011		2012		2013		2014-2015		Thereafter
	($ in millions)
Long-term debt (including interest)(a)	$	592.4	$	31.5	$	560.9	$	—	$	—	$	—
Operating leases	18.3		4.2		4.0		2.4		3.4		4.3
Purchase obligations(b)	—		—		—		—		—		—
Total contractual obligations	$	610.7	$	35.7	$	564.9	$	2.4	$	3.4	$	4.3

__________________________

(a) Assumes our fixed swapped average interest rate of 3.76% plus the applicable margin under our amended and restated credit agreement, which remains constant in all periods.

(b) Excludes physical and financial purchases of natural gas, NGLs, and other energy commodities due to the nature of both the price and volume components of such purchases, which vary on a daily or monthly basis. Additionally, we do not have contractual commitments for fixed price and/or fixed quantities of any material amount.

Recent Accounting Pronouncements

The Financial Accounting Standards Board (the “FASB”) has codified a single source of U.S. Generally Accepted Accounting Principles (U.S. GAAP), the Accounting Standards Codification. Unless needed to clarify a point to readers, the Partnership will refrain from citing specific section references when discussing application of accounting principles or addressing new or pending accounting rule changes.

In January 2010, the FASB issued updated authoritative guidance which aligns the current oil and natural gas reserve estimation and disclosure requirements of the Extractive Industries - Oil and Gas guidance, as discussed above. This guidance expands the disclosures required for equity method investments, revises the definition of oil- and natural gas-producing activities to include nontraditional resources in reserves unless not intended to be upgraded into synthetic oil or natural gas, amends the definition of proved oil and natural gas reserves to require 12-month average pricing in estimating reserves, amends and adds definitions in the Master Glossary that is used in estimating proved oil and natural gas quantities and provides guidance on geographic areas with respect to disclosure of information about significant reserves. This guidance must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009. We adopted this guidance effective December 31, 2009 (See Note 21).

In June 2009, the FASB issued authoritative guidance which reflects the FASB’s response to issues entities have encountered when applying previous guidance. In addition, this guidance addresses concerns expressed by the SEC, members of the United States Congress, and financial statement users about the accounting and disclosures required in the wake of the subprime mortgage crisis and the deterioration in the global credit markets. In addition, because this guidance eliminates the exemption from consolidation for qualified special-purpose entities (“QSPEs”) a transferor will need to evaluate all existing QSPEs to determine whether they must be consolidated. This guidance was effective for us on January 1, 2010 and did not have a material impact on our consolidated financial statements

In June 2009, the FASB issued authoritative guidance, which amends the consolidation guidance applicable to variable interest entities ("VIEs"). The amendments will significantly affect the overall consolidation analysis. While the FASB’s discussions leading up to the issuance of this guidance focused extensively on structured finance entities, the amendments to the consolidation guidance affect all entities and enterprises, as well as qualifying special-purpose entities (QSPEs) that were excluded from previous guidance. Accordingly, an enterprise will need to carefully reconsider its previous conclusions, including (1) whether an entity is a VIE, (2) whether the enterprise is the VIE’s primary beneficiary, and (3) what type of financial statement disclosures are required. This guidance was effective for us on January 1, 2010 and did not have a material impact on our consolidated financial statements.

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evaluate each deliverable to determine the unit of accounting and whether it should be treated separately or in combination. The consensus removes certain thresholds for separation, provides criteria for allocation of revenue amongst deliverables and expands disclosure requirements. This standard was effective for us on January 1, 2011 and will not have a material impact on our consolidated financial statements.

In January 2010, the FASB issued additional guidance on fair value disclosures. The new guidance clarifies two existing disclosure requirements and requires new disclosures such as: (1) a “gross” presentation of activities (purchases, sales, and settlements) within the Level 3 rollforward reconciliation, which will replace the “net” presentation format; and (2) detailed disclosures about the transfers in and out of Level 1 and 2 measurements. This guidance is effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 rollforward information, which is required for annual reporting periods beginning after December 15, 2010, and for interim reporting periods within those years. We adopted the fair value disclosures guidance on January 1, 2010, except for the gross presentation of the Level 3 rollforward information which was not required to be adopted by us until January 1, 2011.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Eagle Rock Energy G&P, LLC and Unitholders of Eagle Rock Energy Partners, L.P.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Eagle Rock Energy Partners, L.P. and subsidiaries (the Partnership) as of December 31, 2010 and 2009, and the related consolidated statements of operations, members' equity, and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 3 to the consolidated financial statements, on December 31, 2009, the Partnership changed its method of accounting for oil and gas reserves. As discussed in Note 21 to the consolidated financial statements, the accompanying consolidated financial statements have been retrospectively adjusted for discontinued operations.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership's internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 11, 2011 (not presented herein) expressed an unqualified opinion on the Partnership's internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 11, 2011, except for the retrospective adjustment for discontinued operations discussed in Note 21, as to which the date is May 17, 2011

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EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2010 AND 2009

($ in thousands)



	December 31, 2010		December 31, 2009
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	4,049	$	2,732
Accounts receivable(a)	75,695		85,784
Risk management assets	—		2,479
Due from affiliates	—		490
Prepayments and other current assets	2,498		2,790
Assets held for sale	8,615		172,176
Total current assets	90,857		266,451
PROPERTY, PLANT AND EQUIPMENT — Net	1,137,239		1,124,695
INTANGIBLE ASSETS — Net	113,634		128,767
DEFERRED TAX ASSET	1,969		1,562
RISK MANAGEMENT ASSETS	1,075		3,410
OTHER ASSETS	4,623		9,933
TOTAL	$	1,349,397	$	1,534,818

LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	91,886	$	89,342
Due to affiliate	56		60
Accrued liabilities	10,940		11,110
Taxes payable	1,102		2,416
Risk management liabilities	39,350		51,650
Liabilities held for sale	1,705		2,094
Total current liabilities	145,039		156,672
LONG-TERM DEBT	530,000		754,383
ASSET RETIREMENT OBLIGATIONS	24,711		19,829
DEFERRED TAX LIABILITY	38,662		40,246
RISK MANAGEMENT LIABILITIES	31,005		32,715
OTHER LONG TERM LIABILITIES	867		575
COMMITMENTS AND CONTINGENCIES (Note 12)
MEMBERS' EQUITY:
Common Unitholders(b)	579,113		484,282
Subordinated Unitholders(c)	—		52,058
General Partner(c)	—		(5,942		)
Total members' equity	579,113		530,398
TOTAL	$	1,349,397	$	1,534,818

________________________


(a)	Net of allowance for bad debt of $4,496 as of December 31, 2010 and $4,818 as of December 31, 2009.


(b)	83,425,378 and 54,203,471 units were issued and outstanding as of December 31, 2010 and 2009, respectively. These amounts do not include unvested restricted common units granted under the Partnership's long-term incentive plan of 1,744,454 and 1,371,019 as of December 31, 2010 and 2009, respectively.


(c)	20,691,495 subordinated units and 844,551 general partner units were issued and outstanding as of December 31, 2009. On May 24, 2010 and July 30, 2010, all of the subordinated and general partner units, respectively, were contributed to the Partnership and subsequently cancelled.

See notes to consolidated financial statements.

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EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

($ in thousands)



	Years Ended December 31,
	2010			2009			2008
REVENUE:
Natural gas, natural gas liquids, oil, condensate and sulfur sales	$	688,052		$	633,357		$	1,227,779
Gathering, compression, processing and treating fees	50,608			44,005			38,497
Commodity risk management (losses) gains	(8,786		)	(106,290		)	161,765
Other revenue	2,435			1,858			716
Total revenue	732,309			572,930			1,428,757
COSTS AND EXPENSES:
Cost of natural gas and natural gas liquids	468,304			470,099			886,019
Operations and maintenance	76,415			71,496			73,203
Taxes other than income	12,226			10,709			18,210
General and administrative	45,775			45,819			45,618
Other operating (income) expense	—			(3,552		)	10,699
Impairment expense	6,666			21,788			142,116
Goodwill impairment	—			—			30,994
Depreciation, depletion and amortization	106,398			108,530			108,356
Total costs and expenses	715,784			724,889			1,315,215
OPERATING (LOSS) INCOME	16,525			(151,959		)	113,542
OTHER INCOME (EXPENSE):
Interest income	111			187			771
Other income	501			934			1,318
Interest expense	(15,147		)	(21,591		)	(32,884		)
Interest rate risk management losses	(27,135		)	(6,347		)	(32,931		)
Other expense	(51		)	(1,070		)	(955		)
Total other (expense) income	(41,721		)	(27,887		)	(64,681		)
(LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(25,196		)	(179,846		)	48,861
INCOME TAX PROVISION (BENEFIT)	(2,585		)	989			(1,459		)
(LOSS) INCOME FROM CONTINUING OPERATIONS	(22,611		)	(180,835		)	50,320
DISCONTINUED OPERATIONS, NET OF TAX	17,262			9,577			37,200
NET (LOSS) INCOME	$	(5,349	)	$	(171,258	)	$	87,520

See notes to consolidated financial statements.

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EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS (continued)

FOR THE YEARS ENDED December 31, 2010, 2009 AND 2008

(in thousands, except per unit amounts)



	Years Ended December 31,
	2010			2009			2008
NET (LOSS) INCOME PER COMMON UNIT—BASIC AND DILUTED:
Basic:
(Loss) Income from Continuing Operations
Common units	$	(0.26	)	$	(2.38	)	$	0.67
Subordinated units	$	(0.48	)	$	(2.48	)	$	0.67
General partner units	$	(0.39	)	$	(2.38	)	$	0.67
Discontinued Operations
Common units	$	0.22		$	0.13		$	0.51
Subordinated units	$	0.22		$	0.13		$	0.51
General partner units	$	0.22		$	0.13		$	0.51
Net Income (Loss)
Common units	$	(0.04	)	$	(2.26	)	$	1.18
Subordinated units	$	(0.26	)	$	(2.36	)	$	1.18
General partner units	$	(0.17	)	$	(2.26	)	$	1.18
Weighted Average Units Outstanding (in thousands)
Common units	68,625			53,496			51,534
Subordinated units	8,163			20,691			20,691
General partner units	488			845			845

Diluted:
(Loss) Income from Continuing Operations
Common units	$	(0.26	)	$	(2.38	)	$	0.67
Subordinated units	$	(0.48	)	$	(2.48	)	$	0.67
General partner units	$	(0.39	)	$	(2.38	)	$	0.67
Discontinued Operations
Common units	$	0.22		$	0.13		$	0.51
Subordinated units	$	0.22		$	0.13		$	0.51
General partner units	$	0.22		$	0.13		$	0.51
Net (Loss) Income
Common units	$	(0.04	)	$	(2.26	)	$	1.18
Subordinated units	$	(0.26	)	$	(2.36	)	$	1.18
General partner units	$	(0.17	)	$	(2.26	)	$	1.18
Weighted Average Units Outstanding (in thousands)
Common units	68,625			53,496			51,699
Subordinated units	8,163			20,691			20,691
General partner units	488			845			845

See notes to consolidated financial statements.

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EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

($ in thousands)



	Years Ended December 31,
	2010			2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income	$	(5,349	)	$	(171,258	)	$	87,520
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Discontinued Operations	(17,262		)	(9,577		)	(37,200		)
Depreciation, depletion and amortization	106,398			108,530			108,356
Impairment	6,666			21,788			173,110
Amortization of debt issuance costs	1,305			1,068			958
Equity in earnings of unconsolidated affiliates	20			(153		)	—
Distribution from unconsolidated affiliates—return on investment	67			164			—
Reclassing financing derivative settlements	(1,131		)	(8,939		)	11,063
Equity-based compensation	5,407			6,685			7,694
Gain of sale of assets	(371		)	(476		)	(1,265		)
Other operating income	—			(3,552		)	—
Other	196			210			(1,618		)
Changes in assets and liabilities—net of acquisitions:
Accounts receivable	10,208			18,982			44,747
Prepayments and other current assets	292			(172		)	941
Risk management activities	(9,195		)	147,751			(199,339		)
Accounts payable	(3,787		)	(36,929		)	(43,292		)
Due to affiliates	328			8,437			(12,491		)
Accrued liabilities	41			(6,411		)	(1,258		)
Other assets	1,058			1,487			23
Other current liabilities	(763		)	(407		)	836
Net cash provided by operating activities	94,128			77,228			138,785
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(64,497		)	(36,134		)	(66,741		)
Acquisitions, net of cash acquired	(30,984		)	—			(262,245		)
Proceeds from sale of asset	171,686			476			1,294
Purchase of intangible assets	(2,660		)	(1,626		)	(2,975		)
Net cash provided by (used in) investing activities	73,545			(37,284		)	(330,667		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	90,617			131,000			432,128
Repayment of long-term debt	(315,000		)	(176,000		)	(199,814		)
Payment of debt issuance costs	—			—			(789		)
Proceeds from derivative contracts	1,131			8,939			(11,063		)
Proceeds from Rights Offering	53,893			—			—
Transaction fees	(3,066		)	(1,480		)	—
Exercise of warrants	5,351			—			—
Repurchase of common units	(1,177		)	(64		)	—
Distributions to members and affiliates	(7,195		)	(35,655		)	(117,646		)
Net cash (used in) provided by financing activities	(175,446		)	(73,260		)	102,816
CASH FLOWS FROM DISCONTINUED OPERATIONS:
Operating activities	9,194			19,713			42,366
Investing activities	(104		)	(1,581		)	(3,936		)
Net cash provided by discontinued operations	9,090			18,132			38,430
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	1,317			(15,184		)	(50,636		)
CASH AND CASH EQUIVALENTS—Beginning of period	2,732			17,916			68,552
CASH AND CASH EQUIVALENTS—End of period	$	4,049		$	2,732		$	17,916

Interest paid—net of amounts capitalized	$	14,272		$	26,311		$	29,822
Units issued in acquisitions and from escrow for acquisitions	$	2,089		$	3,000		$	24,236
Cash paid for taxes	$	1,923		$	1,517		$	705
Issuance of common units for transaction fee	$	29,000		$	—		$	—
Investments in property, plant and equipment, not paid	$	10,922		$	3,761		$	5,534
Deferred tranasaction fees, not paid	$	—		$	1,155		$	—

See notes to consolidated financial statements.

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EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

($ in thousands)



	General Partner			Number of Common Units		Common Units			Number of Subordinated Units		Subordinated Units			Total
BALANCE — January 1, 2008	$	(3,155	)	50,699,647		$	617,563		20,691,495		$	112,360		$	726,768
Net income	1,009			—		61,794			—		24,717			87,520
Equity issued in acquisitions	—			2,181,818		24,236			—		—			24,236
Distribution to affiliates	—			—		(857		)	—		—			(857		)
Distributions	(1,643		)	—		(82,588		)	—		(33,415		)	(117,646		)
Vesting of restricted units	—			162,302		—			—		—			—
Equity-based compensation	75			—		5,442			—		2,177			7,694
BALANCE — December 31, 2008	(3,714		)	53,043,767		625,590			20,691,495		105,839			727,715
Net loss	(1,921		)	—		(122,270		)	—		(47,067		)	(171,258		)
Distributions	(379		)	—		(26,738		)	—		(8,538		)	(35,655		)
Vesting of restricted units	—			334,403		—			—		—			—
Repurchase of common units	—			(17,492	)	(64		)	—		—			(64		)
Equity-based compensation	72			—		4,789			—		1,824			6,685
Units returned from escrow	—			(7,065	)	(25		)	—		—			(25		)
Units issued from escrow	—			849,858		3,000			—		—			3,000
BALANCE — December 31, 2009	(5,942		)	54,203,471		484,282			20,691,495		52,058			530,398
Net income (loss)	734			—		(24,225		)	—		18,142			(5,349		)
Distributions	(483		)	—		(35,869		)	—		—			(36,352		)
Vesting of restricted units	—			798,301		—			—		—			—
Rights offering	—			21,557,164		53,893			—		—			53,893
Transaction costs for rights offering	—			—		(4,147		)	—		—			(4,147		)
Exercise of warrants	—			891,919		5,351			—		—			5,351
Units released from escrow	—			330,604		2,089			—		—			2,089
Repurchase of common units	—			(181,292	)	(1,177		)	—		—			(1,177		)
Equity based compensation	43			—		4,570			—		794			5,407
Payment of tranaction fee to Eagle Rock Holdings, L.P.	—			4,825,211		29,000			—		—			29,000
Cancellation of subordinated units	—			—		70,994			(20,691,495	)	(70,994		)	—
Acquisition of General Partner	5,648			1,000,000		(5,648		)	—		—			—
BALANCE — December 31, 2010	$	—		83,425,378		$	579,113		—		$	—		$	579,113

See notes to consolidated financial statements.

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

NOTE 1. ORGANIZATION AND DESCRIPTION OF BUSINESS

Basis of Presentation and Principles of Consolidation—The accompanying financial statements include consolidated

assets, liabilities and the results of operations of Eagle Rock Energy Partners, L.P. (“Eagle Rock Energy” or the “Partnership”).

The general partner of Eagle Rock Energy is Eagle Rock Energy GP, L.P, and the general partner of Eagle Rock Energy GP,

L.P. is Eagle Rock Energy G&P, LLC, both of which became wholly-owned subsidiaries of the Partnership on July 30, 2010, as

further discussed in Notes 8 and 9. The transaction with Eagle Rock Energy GP, L.P. was accounted for by the Partnership as

a recapitalization. The acquisition of Eagle Rock Energy G&P, LLC was accounted for as an acquisition of entities under

common control, which requires the Partnership to present its financial statements as if the two entities had always been

combined, similar to the pooling of interests method. The balance sheet as of December 31, 2009 and the cash flow statements

for the year ended December 31, 2009 have been retrospectively adjusted to reflect the amounts due to Eagle Rock Energy G&P, LLC as accounts payable rather than due to affiliates. No retrospective adjustments were made to the statements of operations for the twelve months ended December 30, 2010, 2009 and 2008, as Eagle Rock Energy G&P, LLC did not have any operations outside of the services provided to and reimbursed by the Partnership through an omnibus agreement.

In February 2011, the Partnership classified the assets and liabilities of its Wildhorse gathering system as held for sale and the operations as discontinued. Financial information for the years ended December 31, 2010, 2009 and 2008 have been retrospectively adjusted as assets and liabilities held for sale and discontinued operations (see Notes 13 and 21).

Recent Developments— On May 21, 2010, a majority of the Partnership's unaffiliated unitholders approved the Recapitalization and Related Transactions, as defined and further discussed in Note 9. As a result of this approval, the Partnership's subordinated units and incentive distribution rights were contributed and subsequently cancelled (see Note 8), and the Partnership consummated the sale of all of its fee mineral and royalty interests as well as its equity investment in Ivory Working Interests, L.P. (collectively, the "Minerals Business"). Operations related to the Minerals Business for the year ended December 31, 2010, have been recorded as part of discontinued operations. Financial information related to the Minerals Business for the years ended December 31, 2009 and 2008 have been retrospectively adjusted to be reflected as assets and liabilities held-for-sale and discontinued operations (see Notes 13 and 19). In addition, the Partnership launched a rights offering to the holders of its common units and general partner units on June 1, 2010, in which it distributed transferable subscription rights (“Rights”) to subscribe for common units and warrants to purchase additional common units. This rights offering expired on June 30, 2010, and the Partnership issued 21,557,164 common units and 21,557,164 warrants on or about July 8, 2010. See Note 8 for a further discussion of the rights offering.

Description of Business—Eagle Rock Energy is a growth-oriented limited partnership engaged in the business of gathering, compressing, treating, processing, transporting and selling natural gas, fractionating and transporting natural gas liquids, or NGLs (the “Midstream Business”) and the business of acquiring, developing and producing interests in oil and natural gas properties (the “Upstream Business”). The Partnership's natural gas pipelines gather natural gas from designated points near producing wells and transport these volumes to third-party pipelines, the Partnership's gas processing plants, utilities and industrial consumers. Natural gas transported to the Partnership's gas processing plants, either on the Partnership's pipelines or third party pipelines, is treated to remove contaminants and conditioned or processed into marketable natural gas and natural gas liquids. The Partnership conducts its midstream operations within Louisiana and three geographic areas of Texas and accordingly reports its Midstream Business results through four segments: the Texas Panhandle Segment, the South Texas Segment, the East Texas/Louisiana Segment and the Gulf of Mexico Segment. On October 1, 2008, the Partnership completed the acquisition of 100% of the outstanding units of Millennium Midstream Partners, L.P. (“MMP”) (see Note 4). The MMP assets include natural gas gathering and related compression and processing facilities in West Texas, Central Texas, East Texas, Southern Louisiana and the Gulf of Mexico that are now a part of the Partnership's East Texas/Louisiana Segment, South Texas Segment and which created the Partnership's Gulf of Mexico Segment.

On April 30, 2008, the Partnership completed the acquisition of all of the outstanding capital stock of Stanolind Oil and Gas Corp. (“Stanolind”). The Stanolind assets include operated oil and natural gas producing properties in the Permian Basin, primarily in Ward, Crane and Pecos Counties, Texas.

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. Eagle Rock Energy is the owner of a non-operating undivided interest in the Indian Springs gas processing plant and the Camp Ruby gas gathering system. Eagle Rock Energy owns these interests as

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tenants-in-common with the majority owner-operator of the facilities. Accordingly, Eagle Rock Energy includes its pro-rata share of assets, liabilities, revenues and expenses related to these assets in its financial statements. All intercompany accounts and transactions are eliminated in the consolidated financial statements.

Oil and Natural Gas Accounting Policies

The Partnership utilizes the successful efforts method of accounting for its oil and natural gas properties. Leasehold costs are capitalized when incurred. Costs incurred to drill and complete development wells are capitalized. Unproved properties are assessed periodically within specific geographic areas and, if necessary, impairments are charged to expense. Geological and geophysical expenses and delay rentals are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if the well is determined to be unsuccessful. The Partnership carries the costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well as long as the Partnership is making sufficient progress towards assessing the reserves and the economic and operating viability of the project.

Depletion of producing oil and natural gas properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for acquisition costs using all proved reserves. Authoritative guidance requires that acquisition costs of proved properties be amortized on the basis of all proved reserves, (developed and undeveloped) and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves.

Upon sale or retirement of complete fields of depreciable or depleted property, the book value thereof, less proceeds or salvage value, is charged or credited to income.

Impairment of Oil and Natural Gas Properties

The Partnership reviews its proved properties at the field level when management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future oil and natural gas reserves that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels. If the carrying amount of an asset exceeds the sum of the undiscounted estimated future net cash flows, the Partnership recognizes impairment expense equal to the difference between the carrying value and the fair value of the asset, which is estimated to be the expected present value of discounted future net cash flows from proved reserves utilizing the Partnership's weighted average cost of capital. During the year ended December 31, 2010, the Partnership incurred impairment charges of $0.1 million in its Upstream Segment due to adjustments to reserves. During the year ended December 31, 2009, the Partnership incurred impairment charges of $8.1 million in its Upstream Segment, of which $7.9 million was a result of a decline in natural gas prices, production declines and lower natural gas liquids yields at its Flomaton field and $0.2 million in other fields due to lower natural gas prices. During the year ended December 31, 2008, the Partnership recorded impairment charges of $107.0 million in its Upstream Business as a result of substantial declines in commodity prices in the fourth quarter. The Partnership cannot predict the amount of additional impairment charges that may be recorded in the future.

Unproved leasehold costs are reviewed periodically and a loss is recognized to the extent, if any, that the cost of the property has been impaired. Unproved properties that are individually insignificant are amortized. Unproved properties that are individually significant are assessed for impairment on a property-by-property basis. If considered impaired, costs are charged to expense when such impairment is deemed to have occurred. During the year ended December 31, 2010, the Partnership recorded impairment charges of $3.4 million to certain fields in its unproved properties as the Partnership determined it would not be technologically feasible to develop these unproved locations.

Asset Retirement Obligations

The Partnership is required to make estimates of the future costs of the retirement obligations of its producing oil and natural gas properties. This requirement necessitates that the Partnership make estimates of property abandonment costs that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to significant revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors that may be difficult to predict.

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Other Significant Accounting Policies

Use of Estimates—The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Significant estimates are required for proved oil and natural gas reserves, which can affect the carrying value of oil and natural gas properties. The Partnership evaluates its estimates and assumptions on a regular basis. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates and such differences could be material.

Cash and Cash Equivalents—Cash and cash equivalents include certificates of deposit and other highly liquid investments with maturities of three months or less at the time of purchase.

Concentration and Credit Risk—Concentration and credit risk for the Partnership principally consists of cash and cash equivalents and accounts receivable.

The Partnership places its cash and cash equivalents with high-quality institutions and in money market funds. The Partnership derives its revenue from customers primarily in the natural gas industry. Industry concentrations have the potential to impact the Partnership's overall exposure to credit risk, either positively or negatively, in that the Partnership's customers could be affected by similar changes in economic, industry or other conditions. However, the Partnership believes the risk posed by this industry concentration is offset by the creditworthiness of the Partnership's customer base. The Partnership's portfolio of accounts receivable is comprised primarily of mid-size to large domestic corporate entities. The following is the activity within the Partnership's allowance for doubtful accounts during the years ended December 31, 2010, 2009 and 2008.



	2010			2009			2008
($ in thousands)
Balance at beginning of period	$	4,818		$	12,080		$	1,046
Charged to bad debt expense	(122		)	535			11,136
Write-offs/adjustments charged to allowance	(200		)	(7,797		)	(102		)
Balance at end of period	$	4,496		$	4,818		$	12,080

Of the $11.1 million charged to bad debt expense during the year ended December 31, 2008, $10.7 relates to outstanding receivables from SemGroup, L.P., which filed for bankruptcy in July 2008. During the year ended December 31, 2009, the Partnership wrote off $7.3 million related to SemGroup, L.P. This amount relates to the non-503(b)(9) claims and the portion of the receivables sold in August 2009 (see Note 18 for further discussion).

Certain Other Concentrations—The Partnership relies on natural gas producers for its Midstream Business's natural gas and natural gas liquid supply, with the top two producers (by segment) accounting for 24% of its natural gas supply in the Texas Panhandle Segment, 20% of its natural gas supply in the East Texas/Louisiana Segment and 62% of its natural gas supply in the South Texas Segment, and in the Gulf of Mexico Segment, three customers accounted for 84% of its natural gas supply for the year ended December 31, 2010. While there are numerous natural gas and natural gas liquid producers, and some of these producers are subject to long-term contracts, the Partnership may be unable to negotiate extensions or replacements of these contracts on favorable terms, if at all. If the Partnership were to lose all or even a portion of the natural gas volumes supplied by these producers and was unable to acquire comparable volumes, the Partnership's results of operations and financial position could be materially adversely affected. These percentages are calculated based on MMBtus gathered during the year ended December 31, 2010. For the year ended December 31, 2010, ONEOK Hydrocarbon, the Partnership's largest customer, represented 29% of its total sales revenue (including realized and unrealized gains on commodity derivatives).

Inventory—Inventory is stated at the lower of cost or market, with cost being determined using the standard cost method, which approximates actual costs on a first-in-first-out or average basis. At December 31, 2010, the Partnership had $0.5 million of crude oil finished goods inventory which is recorded as part of Other Current Assets within the Consolidated Balance Sheet.

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Property, Plant, and Equipment—Property, plant, and equipment consists primarily of gas gathering systems, gas processing plants, NGL pipelines, conditioning and treating facilities and other related facilities, and oil and gas properties, which are carried at cost less accumulated depreciation, depletion and amortization. The Partnership charges repairs and maintenance against income when incurred and capitalizes renewals and betterments, which extend the useful life or expand the capacity of the assets. The Partnership calculates depreciation on the straight-line method over estimated useful lives of the Partnership's newly developed or acquired assets. The weighted average useful lives are as follows:



Plant Assets	20 years
Pipelines and equipment	20 years
Gas processing and equipment	20 years
Office furniture and equipment	5 years

The Partnership capitalizes interest costs on major projects during extended construction time periods. Such interest costs are allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. During the years ended December 31, 2010, 2009 and 2008, the Partnership capitalized interest costs of approximately $0.4 million, $0.1 million, and $0.4 million, respectively.

Impairment of Long-Lived Assets—Management evaluates whether the carrying value of non-oil and natural gas long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the assets. Management considers various factors when determining if these assets should be evaluated for impairment, including, but not limited to:


•	significant adverse change in legal factors or in the business climate;


•	a current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast which demonstrates continuing losses associated with the use of a long-lived asset;


•	an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;


•	significant adverse changes in the extent or manner in which an asset is used or in its physical condition;


•	a significant change in the market value of an asset; or


•	a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.

If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset's carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management's intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets. During the year ended December 31, 2010, the Partnership recorded impairment charges of $29.3 million related to its Midstream Business due to (i) $3.1 million due to the notification during the second quarter 2010 that a significant gathering contract on its Raymondville system in its South Texas Segment would be terminated during the third quarter of 2010 and (ii) $26.2 million, recorded within discontinued operations in our South Texas Segment, due to an anticipated decline in volumes on its Wildhorse gathering system. During the year ended December 31, 2009, the Partnership recorded impairment charges related to certain processing plants, pipelines and contracts in its Midstream business of $13.7 million due to reduced throughput volumes. During the year ended December 31, 2008, the Partnership recorded an impairment charge related to certain processing plants, pipelines and contracts in its Midstream business of $35.1 million due to the substantial decline in commodity prices in the fourth quarter as well as declining drilling activity by its producer customers. Due to the percent-of-proceeds, fixed recovery and keep-whole contract arrangements the Partnership operates under with some of its producer customers, cash flows are dependent up the selling price of the natural gas and natural gas liquids processed by its plants. Under these arrangements, lower commodity prices result in lower margins. In addition, lower commodity prices influence the drilling activity of the Partnership's producer customers. Lower drilling activity reduces the future volumes of natural gas projected to flow through the Partnership's gathering systems, thus reducing

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both the equity volumes attributable to the Partnership and the fees generated under the fee-based arrangements the Partnership operates under as part of its Midstream Business.

Goodwill—Goodwill acquired in connection with business combinations represent the excess of consideration over the fair value of tangible net assets and identifiable intangible assets acquired. Certain assumptions and estimates are employed in determining the fair value of assets acquired and liabilities assumed, as well as in determining the allocation of goodwill to the appropriate reporting unit.

During the year ended December 31, 2008, the Partnership performed its annual impairment test in May 2008 and determined that no impairment appeared evident. The Partnership's goodwill impairment test involves a comparison of the fair value of each of its reporting units with their carrying value. The fair value is determined using discounted cash flows and other market-related valuation models. Certain estimates and judgments are required in the application of the fair value models. As a result of the impairment charge incurred within the Partnership's Upstream Segment during the fourth quarter of 2008 which resulted from the substantial decline in commodity prices during the fourth quarter of 2008, the Partnership performed an assessment of its goodwill and recorded an impairment charge of $31.0 million, which reduced its goodwill amount to zero. No such impairment was recorded in the years ended December 31, 2010 or 2009. At December 31, 2010, 2009 and 2008, the Partnership had gross goodwill of $31.0 million, $31.0 million and $31.0 million, respectively, and accumulated impairment losses of $31.0 million, $31.0 million and $31.0 million, respectively.

Other Assets— As of December 31, 2010, other assets primarily consist of costs associated with: debt issuance costs, net of amortization ($1.9 million); business deposits to various providers and state or regulatory agencies ($1.6 million); and investment in unconsolidated affiliates ($1.1 million). As of December 31, 2009, other assets primarily consist of costs associated with: debt issuance costs, net of amortization ($3.2 million); business deposits to various providers and state or regulatory agencies ($1.1 million); and investment in unconsolidated affiliates ($13.3 million).

Within the Partnership's investments of unconsolidated affiliates, the Partnership owns 5.0% of the common units of each of Buckeye Pipeline, L.P. and Trinity River, LLC. The Partnership also owns a 50% joint venture in Valley Pipeline, LLC. and Sweeny Gathering, L.P. These investments are accounted for under the equity method and as of December 31, 2010 are not considered material to the Partnership's financial position or results of operations.

Transportation and Exchange Imbalances—In the course of transporting natural gas and natural gas liquids for others, the Partnership may receive for redelivery different quantities of natural gas or natural gas liquids than the quantities actually delivered. These transactions result in transportation and exchange imbalance receivables or payables which are recovered or repaid through the receipt or delivery of natural gas or natural gas liquids in future periods, if not subject to cash out provisions. Imbalance receivables are included in accounts receivable and imbalance payables are included in accounts payable on the consolidated balance sheets and marked-to-market using current market prices in effect for the reporting period of the outstanding imbalances. For the Midstream Business, as of December 31, 2010, the Partnership had imbalance receivables totaling $0.8 million and imbalance payables totaling $1.2 million, respectively. For the Midstream business, as of December 31, 2009, the Partnership had imbalance receivables totaling $0.3 million and imbalance payables totaling $2.9 million, respectively. Changes in market value and the settlement of any such imbalance at a price greater than or less than the recorded imbalance results in either an upward or downward adjustment, as appropriate, to the cost of natural gas sold.

Revenue Recognition—Eagle Rock Energy's primary types of sales and service activities reported as operating revenue include:


•	sales of natural gas, NGLs, crude oil and condensate;


•	natural gas gathering, processing and transportation, from which Eagle Rock Energy generates revenues primarily through the compression, gathering, treating, processing and transportation of natural gas; and


•	NGL transportation from which the Partnership generates revenues from transportation fees.

Revenues associated with sales of natural gas, NGLs, crude oil and condensate are recognized when title passes to the customer, which is when the risk of ownership passes to the customer and physical delivery occurs. Revenues associated with transportation and processing fees are recognized when the service is provided.

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For gathering and processing services, Eagle Rock Energy either receives fees or commodities from natural gas producers depending on the type of contract. Under the percentage-of-proceeds contract type, Eagle Rock Energy is paid for its services by keeping a percentage of the NGLs produced and a percentage of the residue gas resulting from processing the natural gas. Commodities received are in turn sold and recognized as revenue in accordance with the criteria outlined above. Under the keep-whole contract type, Eagle Rock Energy purchases wellhead natural gas to return to the producer and sells processed natural gas and NGLs to third parties.

Transportation, compression and processing-related revenues are recognized in the period when the service is provided and include the Partnership's fee-based service revenue for services such as transportation, compression and processing.

The Partnership's Upstream Segment has elected the entitlements method to account for production imbalances. Imbalances occur when the Partnership sells more or less than its entitled ownership percentage of total production. In accordance with the entitlements method, any amount received in excess of the partnership's share is treated as a liability. If the Partnership receives less than its entitled share, the underproduction is recorded as a receivable. As of December 31, 2010, the Partnership's Upstream Segment had an imbalance receivable balance of $0.5 million. As of December 31, 2009, the Partnership's Upstream Segment had an imbalance receivable balance of $1.9 million and an imbalance payable balance of $0.5 million.

A significant portion of the Partnership's sale and purchase arrangements are accounted for on a gross basis in the consolidated statements of operations as natural gas sales and costs of natural gas, respectively. These transactions are contractual arrangements which establish the terms of the purchase of natural gas at a specified location and the sale of natural gas at a different location at the same or at another specified date. These arrangements are detailed either jointly, in a single contract, or separately in individual contracts which are entered into concurrently or in contemplation of one another with a single or multiple counterparties. Both transactions require physical delivery of the natural gas and the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk and counterparty nonperformance risk. Under authoritative guidance, purchase and sale agreements with the same counterparty are required to be recorded on a net basis. For the years ended December 31, 2010, 2009 and 2008, the Partnership did not enter into any purchase and sale agreements with the same counterparty.

Environmental Expenditures—Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures which relate to an existing condition caused by past operations and do not generate current or future revenue are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated.

Income Taxes—Provision for income taxes is primarily applicable to the Partnership's state tax obligations under the Revised Texas Franchise Tax (the “Revised Texas Franchise Tax”) and certain federal and state tax obligations of Eagle Rock Energy Acquisition Co., Inc. and Eagle Rock Upstream Development Company, Inc., both of which are consolidated subsidiaries. Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of the tax paying entities for financial reporting and tax purposes.

In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax. In May 2006, the State of Texas expanded its pre-existing franchise tax to include limited partnerships, limited liability companies, corporations and limited liability partnerships. As a result of the change in tax law, the Partnership's tax status in the State of Texas changed from non-taxable to taxable effective with the 2007 tax year.

Since the Partnership is structured as a pass-through entity, it is not subject to federal income taxes. As a result, its partners are individually responsible for paying federal and certain income taxes on their share of the Partnership's taxable income. Since the Partnership does not have access to information regarding each partner's tax basis, it cannot readily determine the total difference in the basis of the Partnership's net assets for financial and tax reporting purposes.

In accordance with authoritative guidance, the Partnership must recognize the tax effects of any uncertain tax positions it may adopt, if the position taken by it is more likely than not sustainable. If a tax position meets such criteria, the tax effect to be recognized by the Partnership would be the largest amount of benefit with more than a 50% chance of being realized upon settlement. This guidance was effective January 1, 2007, and the Partnership's adoption of this guidance had no material impact on its financial position, results of operations or cash flows. See Note 15 for additional information regarding the Partnership's income taxes.

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Derivatives—Authoritative guidance establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires an entity to recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The guidance provides that normal purchase and normal sale contracts, when appropriately designated, are not subject to the guidance. Normal purchases and normal sales are contracts which provide for the purchase or sale of something, other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business. The Partnership's forward natural gas and crude oil purchase and sales contracts are designated as normal purchases and sales. Substantially all forward contracts fall within a one-month to four-year term; however, the Partnership does have certain contracts which extend through the life of the dedicated production. The terms of these contracts generally preclude unplanned netting. The Partnership uses financial instruments such as puts, swaps and other derivatives to mitigate the risks to cash flows resulting from changes in commodity prices and interest rates. The Partnership recognizes these financial instruments on its consolidated balance sheet at the instrument's fair value with changes in fair value reflected in the consolidated statement of operations, as the Partnership has not designated any of these derivative instruments as hedges. The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as a financing activity in the statement of cash flows. See Note 11 for a description of the Partnership's risk management activities.

Fair Value Measurement—Authoritative guidance establishes accounting and reporting standards for assets and liabilities carried at fair value. The guidance provides definitions of fair value and expands the disclosure requirements with respect to fair value a specifies a hierarchy of valuation techniques based on the inputs used to measure fair value. See Note 10 for additional information regarding the Partnership's assets and liabilities carried at fair value.

NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS

In January 2010, the FASB issued updated authoritative guidance which aligns the current oil and natural gas reserve estimation and disclosure requirements of the Extractive Industries - Oil and Gas guidance, as discussed above. This guidance expands the disclosures required for equity method investments, revises the definition of oil- and natural gas-producing activities to include nontraditional resources in reserves unless not intended to be upgraded into synthetic oil or natural gas, amends the definition of proved oil and natural gas reserves to require 12-month average pricing in estimating reserves, amends and adds definitions in the Master Glossary that is used in estimating proved oil and natural gas quantities and provides guidance on geographic areas with respect to disclosure of information about significant reserves. This guidance must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009. The Partnership adopted this guidance effective December 31, 2009. (See Note 21).

In June 2009, the FASB issued authoritative guidance which reflects the FASB’s response to issues entities have encountered when applying previous guidance. In addition, this guidance addresses concerns expressed by the SEC, members of the United States Congress, and financial statement users about the accounting and disclosures required in the wake of the subprime mortgage crisis and the deterioration in the global credit markets. In addition, because this guidance eliminates the exemption from consolidation for qualified special-purpose entities (“QSPEs”) a transferor will need to evaluate all existing QSPEs to determine whether they must be consolidated. This guidance was effective for the Partnership on January 1, 2010 and did not have a material impact on its consolidated financial statements

In June 2009, the FASB issued authoritative guidance, which amends the consolidation guidance applicable to variable interest entities ("VIEs"). The amendments will significantly affect the overall consolidation analysis. While the FASB’s discussions leading up to the issuance of this guidance focused extensively on structured finance entities, the amendments to the consolidation guidance affect all entities and enterprises, as well as qualifying special-purpose entities (QSPEs) that were excluded from previous guidance. Accordingly, an enterprise will need to carefully reconsider its previous conclusions, including (1) whether an entity is a VIE, (2) whether the enterprise is the VIE’s primary beneficiary, and (3) what type of financial statement disclosures are required. This guidance was effective for the Partnership on January 1, 2010 and did not have a material impact on its consolidated financial statements.

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In September 2009, the FASB issued a consensus which revises the standards for recognizing revenue on arrangements with multiple deliverables. Before evaluating how to recognize revenue for transactions with multiple revenue generating activities, an entity should identify all the deliverables in the arrangement and, if there are multiple deliverables, evaluate each deliverable to determine the unit of accounting and whether it should be treated separately or in combination. The consensus removes certain thresholds for separation, provides criteria for allocation of revenue amongst deliverables and expands disclosure requirements. This standard was effective for the Partnership on January 1, 2011 and will not have a material impact on the Partnership's consolidated financial statements.

In January 2010, the FASB issued additional guidance on fair value disclosures. The new guidance clarifies two existing disclosure requirements and requires new disclosures such as: (1) a “gross” presentation of activities (purchases, sales, and settlements) within the Level 3 rollforward reconciliation, which will replace the “net” presentation format; and (2) detailed disclosures about the transfers in and out of Level 1 and 2 measurements. This guidance is effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 rollforward information, which is required for annual reporting periods beginning after December 15, 2010, and for interim reporting periods within those years. The Partnership adopted the fair value disclosures guidance on January 1, 2010, except for the gross presentation of the Level 3 rollforward information which was not required to be adopted by the Partnership until January 1, 2011. The presentation of the table disclosing the assets and liabilities by hierarchy level as of December 31, 2009 has been changed to conform to the presentation as of December 31, 2010 (see Note 10).

NOTE 4. ACQUISITIONS

2010 Acquisitions

On September 30, 2010, the Partnership acquired certain additional interests in the Big Escambia Creek Field (and the

nearby Flomaton and Fanny Church Fields) from Indigo Minerals, LLC for $3.9 million in cash on hand. These interests are in wells in which the Partnership currently owns significant interests and are nearly 100% operated by the Partnership. The entire purchase price was allocated to proved properties.

On October 19, 2010, the Partnership acquired certain natural gas gathering systems and related facilities located primarily in Wheeler and Hemphill Counties in the Texas Panhandle from Centerpoint Energy Field Services, Inc. ("CEFS"). The closing purchase price for the assets was $27.0 million, subject to customary post-closing adjustments. The assets acquired include over 200 miles of gathering pipeline and related compression and dehydration facilities, together with gas gathering contracts, rights of way and other intangible assets. The assets are located in the core of the highly active and prolific Granite Wash play and are highly complementary to the Partnership's existing East Panhandle system.

The preliminary purchase price was allocated based on their respective fair value as determined by management with the assistance of K.E. Andrews & Company, a third-party valuation specialist. The purchase price allocation is set forth below (in thousands):



Property, plant and equipment	$	22,917
Intangibles, rights-of-way	4,583
Other current assets	147
Other current liabilities	(344		)
Asset retirement obligations	(260		)
	$	27,043

The Partnership commenced recording results of operations related to these assets acquired from CEFS on October 19, 2010.

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2008 Acquisitions

Update on Millennium Acquisition. On October 1, 2008, the Partnership completed the acquisition of 100% of the outstanding units of Millennium Midstream Partners, L.P. (“MMP”). MMP is in the natural gas gathering and processing business, with assets located in East, Central and West Texas and South Louisiana. With respect to the South Louisiana assets acquired in the acquisition, the Yscloskey and North Terrebonne facilities were flooded with three to four feet of water as a result of the storm surges caused by Hurricanes Ike and/or Gustav. The North Terrebonne facility came back on-line in November 2008 and the Yscloskey facility came back on-line in January 2009. The former owners of MMP provided the Partnership indemnity coverage for Hurricanes Gustav and Ike to the extent losses are not covered by insurance and established an escrow account of 1,818,182 common units and $0.6 million in cash available for the Partnership to recover against for this purpose. As of December 31, 2009, the escrow account held 391,304 common units. During the year ended December 31, 2010, the Partnership released 330,604 units out of escrow to the former owners of MMP and recovered the remaining 60,700 units held in escrow. As of December 31, 2010, the Partnership had an additional claim for $0.2 million cash out of escrow.

As a result of releasing the 330,604 units out of escrow to the former owners of MMP, the Partnership adjusted its purchase price allocation with respect to the Millennium Acquisition. As of December 31, 2010, the total purchase price was $212.9 million. With respect to the Millennium Acquisition, the Partnership increased the amount allocated to pipelines, plants

and intangibles by $1.2 million, $0.8 million and $0.3 million, respectively.

NOTE 5. PROPERTY PLANT AND EQUIPMENT AND ASSET RETIREMENT OBLIGATIONS

Fixed assets consisted of the following:



	December 31, 2010			December 31, 2009
	($ in thousands)
Land	$	2,629		$	1,559
Plant	251,436			242,010
Gathering and pipeline	666,163			642,778
Equipment and machinery	26,408			22,279
Vehicles and transportation equipment	4,251			4,232
Office equipment, furniture, and fixtures	1,120			1,248
Computer equipment	8,486			6,912
Corporate	126			126
Linefill	4,269			4,269
Proved properties	471,781			435,789
Unproved properties	1,304			7,264
Construction in progress	42,416			15,513
	1,480,389			1,383,979
Less: accumulated depreciation, depletion and amortization	(343,150		)	(259,284		)
Net property plant and equipment	$	1,137,239		$	1,124,695

Depreciation expense for the years ended December 31, 2010, 2009 and 2008 was approximately $54.2 million, $51.5 million and $43.6 million, respectively. Depletion expense for the year ended December 31, 2010, 2009 and 2008 was approximately $30.0 million, $33.7 million and $45.0 million, respectively. During the year ended December 31, 2010, the Partnership recorded impairment charges of $2.6 million related to its pipeline and plant assets due to the notification during the second quarter 2010 that a significant gathering contract in its South Texas Segment would be terminated during the third quarter of 2010, $0.1 million of proved properties in its Upstream segment due to adjustments to reserves and $3.4 million of impairment charges related to unproved properties in the Upstream Segment due to the fact that the Partnership determined it would not be technologically feasible to develop these unproved locations. During the year ended December 31, 2009, the Partnership recorded impairment charges related to its pipeline assets and proved properties of $12.6 million and $8.1 million, respectively. During the year ended December 31, 2008, the Partnership recorded impairment charges related to its plants, gathering and pipeline assets and proved properties of $4.3 million, $19.5 million and $107.0 million, respectively.

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Asset Retirement Obligations—The Partnership recognizes asset retirement obligations for its oil and gas working interests associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. The Partnership records the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The Partnership recognizes asset retirement obligations for its midstream assets in accordance with the term “conditional asset retirement obligation,” which refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional upon a future event that may or may not be within the Partnership's control. Although uncertainty about the timing and/or method of settlement may exist and may be conditional upon a future event, the obligation to perform the asset retirement activity is unconditional. Accordingly, the Partnership is required to recognize a liability for the fair value of a conditional asset retirement obligation upon initial recognition if the fair value of the liability can be reasonably estimated. As of December 31, 2009, the Partnership had $1.0 million restricted in an escrow account for purposes of settling associated asset retirement obligations in the State of Alabama, which was released out of escrow during the year ended December 31, 2010.

A reconciliation of the Partnership's liability for asset retirement obligations is as follows:



	2010			2009			2008
	($ in thousands)
Asset retirement obligations—January 1	$	19,829		$	19,872		$	11,337
Additional liability	1,019			—			204
Liabilities settled	(1,175		)	(1,324		)	—
Revision to liabilities	2,582			—			—
Additional liability related to acquisitions	663			—			7,260
Accretion expense	1,793			1,281			1,071
Asset retirement obligations—December 31	$	24,711		$	19,829		$	19,872

During the year ended December 31, 2010, the Partnership made revisions of $2.6 million to increase certain asset retirement obligations due to changes in the estimate of the costs to remediate, as well as changes in the estimates of the timing of settlement.

NOTE 6. INTANGIBLE ASSETS

Intangible assets consist of right-of-ways and easements and acquired customer contracts, which the Partnership amortizes over the term of the agreement or estimated useful life. Amortization expense was approximately $22.2 million, $23.2 million and $19.7 million for the years ended December 31, 2010, 2009 and 2008, respectively. Estimated aggregate amortization expense for each of the five succeeding years is as follows: 2011—$12.1 million; 2012—$11.7 million; 2013—$10.5 million; 2014—$7.0 million; and 2015 —$7.0 million. Intangible assets consisted of the following (as of December 31, 2010 and 2009):



	December 31, 2010			December 31, 2009
	($ in thousands)
Rights-of-way and easements—at cost	$	91,490		$	84,746
Less: accumulated amortization	(20,552		)	(15,504		)
Contracts	122,601			121,150
Less: accumulated amortization	(79,905		)	(61,625		)
Net intangible assets	$	113,634		$	128,767

The amortization period for the Partnership's rights-of-way and easements is 20 years. The amortization period for contracts range from 5 to 20 years, and are approximately 8 years on average as of December 31, 2010. During the year ended December 31, 2010, the Partnership recorded impairment charges of $0.5 million related to rights-of-way. During the year ended December 31, 2009, the Partnership recorded impairment charges related to its Rights-of-way and easements of $1.1 million. During the year ended December 31, 2008, the Partnership recorded impairment charges related to its rights-of-way and easements and contracts of $3.7 million and $7.6 million, respectively.

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NOTE 7. LONG-TERM DEBT

Long-term debt consisted of:



	December 31, 2010		December 31, 2009
	($ in thousands)
Revolving credit facility	$	530,000	$	754,383
Total debt	530,000		754,383
Less: current portion	—		—
Total long-term debt	$	530,000	$	754,383

On December 13, 2007, the Partnership entered into a senior secured revolving credit facility (the “Revolving Credit Facility”) with aggregate commitments of $800 million. During the year ended December 31, 2008, the Partnership exercised $180 million of its $200 million accordion feature of the Revolving Credit Facility, which increased the total commitment to $980 million. The Revolving Credit Facility was entered into with a syndicate of commercial and investment banks, led by Wachovia Capital Markets, LLC and Bank of America Securities LLC as joint lead arrangement agents and joint book runners. The Revolving Credit Facility provided for $980 million aggregate principal amount of revolving commitments and had a maturity date of December 13, 2012. The Revolving Credit Facility provided the Partnership with the ability to potentially increase the total amount of revolving commitments by an additional $20 million to a total of $1 billion. Subsequently, as a result of Lehman Brothers’ bankruptcy filing, the amount of available commitments was reduced by the unfunded portion of Lehman Brother's commitment in an amount of approximately $9.1 million to a total of $970.9 million and the potential increase in commitments was reduced by approximately $0.5 million to a total of approximately $19.5 million.

On March 8, 2010, the Partnership entered into the Second Amendment (the “Credit Facility Amendment”) to its Revolving Credit Facility. In connection with its unitholders' approval of the Global Transaction Agreement and related matters (see Note 9), the Credit Facility Amendment became effective.

The Credit Facility Amendment modified the definition of “Change in Control” in such a way that the exercising of the GP Acquisition Option, as defined in Note 9, did not trigger a “Change in Control” event and potential default. In addition to modifying the definition of “Change in Control,” the Credit Facility Amendment also:

•

reduced the maximum permitted Senior Secured Leverage Ratio (as such term is defined in the credit agreement) from 4.25 to 1.0 under the current credit agreement to 3.75 to 1.0 (and from 4.75 to 1.0 to 4.25 to 1.0 for specified periods following certain permitted acquisitions). The Senior Secured Leverage Ratio covenant is only relevant if the Partnership has unsecured senior or subordinated notes outstanding;


•	obligated the Partnership to use $100 million of the proceeds from the sale of the Minerals Business (described in Note 19) to make a mandatory prepayment towards its outstanding borrowings under the revolving credit facility, which mandatory prepayment was made on May 25, 2010; and


•	reduced, upon such mandatory prepayment, its borrowing capacity under the revolving credit facility by the $100 million amount of such mandatory prepayment to $880 million; however, this did not impact its availability under the Partnership's revolving credit facility because it is limited by compliance with financial covenants.

The Credit Facility Amendment further clarifies that the proceeds from the sale of the Minerals Business in excess of$100 million may be used to immediately reduce debt, but will not result in a mandatory prepayment unless such proceeds are not reinvested in Property (as defined in the credit agreement) within the 270-day post-closing period (i.e. by February 18, 2011) provided in the credit agreement. On May 28, 2010, the Partnership repaid an additional $72 million towards its outstanding borrowings under the revolving credit facility from proceeds from the sale of the Minerals Business. The Partnership does not anticipate any further reductions in commitments under the Credit Facility resulting from the sale of the Minerals Business.

At the Partnership's election, its outstanding indebtedness bears interest on the unpaid principal amount either at a base rate plus the applicable margin (currently 0.75% per annum based on the Partnership's total leverage ratio and utilization of its borrowing base as part of its total indebtedness); or at the Adjusted Eurodollar Rate plus the applicable margin (currently 1.875% per annum based on the Partnership's total leverage ratio and utilization of its borrowing base as part of its total

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indebtedness). At December 31, 2010, the weighted average interest rate on the Partnership's outstanding debt balance was 5.94%.

Base rate interest loans are paid the last day of each March, June, September and December. Eurodollar Rate Loans are paid the last day of each interest period, representing one-, two-, three-, six-, nine- or twelve months, as selected by the Partnership. The Partnership pays a commitment fee equal to (1) the average of the daily differences between (a) the revolver commitments and (b) the sum of the aggregate principal amount of all outstanding loans times (2) 0.30% per annum, based on its current leverage ratio and borrowing base utilization. The Partnership also pays a letter of credit fee equal to (1) the applicable margin for revolving loans which are Eurodollar Rate loans times (2) the average aggregate daily maximum amount available to be drawn under all such Letters of Credit (regardless of where any conditions for drawing could then be met and determined as of the close of business on any date of determination). Additionally, the Partnership pays a fronting fee equal to 0.125% per annum times the average aggregate daily maximum amount available to be drawn under all letters of credit.

The obligation under the Revolving Credit Facility are secured by first priority liens on substantially all for the Partnership's assets, including a pledge of all of the capital stock of each of its subsidiaries.

The Revolving Credit Facility contains various covenants which limit the Partnership's ability to grant liens, make certain loans and investments; make certain capital expenditures outside the Partnership's current lines of business or certain related lines of business; make distributions other than from available cash; merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of the Partnership's assets. Additionally, the Revolving Credit Facility limits the Partnership's ability to incur additional indebtedness with certain exceptions and purchase money indebtedness and indebtedness related to capital or synthetic leases not to exceed 2.5% of tangible net worth.

The Revolving Credit Facility also contains covenants, which, amount other things, require the Partnership, on a consolidated basis, to maintain specified ratios or conditions as follows:


•	Consolidated EBITDA (as defined) to Consolidated Interest Expense (as defined) of not less than 2.5 to 1.0;


•	Total Funded Indebtedness (as defined) to Adjusted Consolidated EBITDA (as defined) of not more than 5.0 to 1.0 (5.25 to 1.0 for the three quarters following a material acquisition); and


•	Borrowing Base Indebtedness (as defined) not to exceed the Borrowing Base (as defined) as re-determined from time to time.

As of December 31, 2010, the Partnership was in compliance with the financial covenants under its revolving credit facility and has not been subject to mandatory repayments and/or a commitment reduction for asset and property sales, reductions in borrowing base and for insurance/condemnation proceeds.

The Partnership's credit facility accommodates, through the use of a borrowing base for its Upstream Business and traditional cash-flow based covenants for its Midstream Business, the allocation of indebtedness to either its Upstream Business (to be measured against the borrowing base) or to its Midstream Business (to be measured against the cash-flow based covenant.

On October 19, 2010, the Partnership announced that the borrowing base under its revolving credit facility, which relates to our Upstream Business, was set at $140 million by its commercial lenders as part of its regularly scheduled semi-annual borrowing base redetermination. This was an increase from the $130 million our borrowing base was set at during the April 2010 redetermination. The redetermined borrowing base was effective October 1, 2010, with no additional fees or increase in interest rate spread incurred.

Based upon total commitments as of December 31, 2010, the Partnership had approximately $341 million of unused capacity under the Revolving Credit Facility at December 31, 2010 on which the Partnership pays a 0.35% commitment fee per year.

The Revolving Credit Facility includes a sub-limit for the issuance of standby letters of credit for a total of $200 million. At December 31, 2010, the Partnership had $0.8 million of outstanding letters of credit.

In certain instances defined in the Revolving Credit Facility, the Partnership's outstanding debt is subject to mandatory repayments and/or is subject to a commitment reduction for asset and property sales, reductions in borrowing base and for insurance/condemnation proceeds.

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During the year ended December 31, 2008, the Partnership incurred an additional $0.8 million of debt issuance costs in connection with exercising the accordion feature of the Revolving Credit Facility. During the years ended December 31, 2010, 2009 and 2008, the Partnership recorded approximately $1.3 million, $1.1 million and $1.0 million of debt issuance amortization expense, respectively. As of December 31, 2010 the unamortized amount of debt issuance cost was $1.9 million.

Scheduled maturities of long-term debt as of December 31, 2010, were as follows:



	Principal Amount
	($ in thousands)
2011	—
2012	530,000
	$	530,000

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NOTE 8. MEMBERS’ EQUITY

At December 31, 2010, there were 83,425,378 common units outstanding. In addition, there were 1,744,454 restricted unvested common units outstanding.

As a result of the approval of certain of the Recapitalization and Related Transactions, as further discussed in Note 9, on May 24, 2010, the Partnership's general partner and Eagle Rock Holdings, L.P. ("Holdings") contributed to the Partnership all 20,691,495 of the outstanding subordinated units and all of the outstanding incentive distribution rights in the Partnership. In connection with the contribution of the subordinated units and incentive distribution rights, the Partnership (i) issued 4,825,211 common units to Holdings as payment of the transaction fee contemplated by the Global Transaction Agreement (as defined in Note 9) and (ii) adopted and entered into a Second Amended and Restated Agreement of Limited Partnership.

Pursuant to the Partnership's Second Amended and Restated Agreement of Limited Partnership, among other things: (i) the subordinated units and incentive distribution rights were cancelled; (ii) the concepts of a subordination period and a minimum quarterly distribution (and, as a result, the concept of arrearages on the common units) were eliminated; and (iii) provisions were included that provide the Partnership an option to acquire its general partner and its general partner entities, which were acquired on July 30, 2010, as further discussed below.

On June 1, 2010, the Partnership launched its rights offering and distributed 21,557,164 Rights to the holders of its common and general partner units as of close of business on May 27, 2010, the record date. Each common and general partner unitholder received 0.35 Rights for each unit held as of the record date. Each Right entitled the holder (including holders of Rights acquired during the subscription period) to purchase for $2.50 in cash (i) one common unit and (ii) one warrant to purchase one additional common unit at $6.00 on certain specified days beginning on August 15, 2010 and ending on May 15,

2012. The warrants are exercisable only on each March 15, May 15, August 15 and November 15 during the period in which

the warrants remain outstanding. The rights offering expired on June 30, 2010, and the Partnership issued 21,557,164 common

units and 21,557,164 warrants on or about July 8, 2010 for gross proceeds of $53.9 million. During the three months ended

September 30, 2010, the Partnership used the proceeds received from the rights offering to repay $50.0 million of outstanding

borrowings under the revolving credit facility. On August 15, 2010, 284,722 warrants were exercised for 284,722 newly issued

common units, for which the Partnership received proceeds of $1.7 million. On November 15, 2010, 607,197 warrants were exercised for 607,197 newly issued common units, for which the Partnership received proceeds of $3.6 million. As of December 31, 2010, 20,665,245 warrants were still outstanding.

On July 27, 2010, the Partnership gave notice to Holdings of its intention to exercise the GP Acquisition Option (as

defined in Note 9). The transaction closed on July 30, 2010, and the Partnership issued 1,000,000 common units to Holdings to

acquire the Partnership's general partner entities. As a result, the Partnership's 844,551 outstanding general partner units were

cancelled. In connection with the completion of the GP Acquisition Option, the Partnership's board of directors (the "Board")

was expanded to include two additional independent directors who were appointed by the Conflicts Committee on July 30,

2010.

During the year ended December 31, 2010, the Partnership released 330,604 common units that were previously held in an escrow account related to its acquisition of MMP to the former owners of MMP.

During the year ended December 31, 2009, the Partnership recovered and cancelled 7,065 common units that were being held in an escrow account related to its acquisition of MacLondon Energy, L.P. and released 849,858 common units that were previously held in an escrow account related to its Millennium Acquisition to the former owners of MMP.

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The Partnership has declared a cash distribution for each quarter since its initial public offering. The table below summarizes these distributions for the last three years.



Quarter Ended	Distribution per Unit		Record Date	Payment Date
March 31, 2008	$	0.4000	May 9, 2008	May 15, 2008
June 30, 2008	$	0.4100	August 8, 2008	August 14, 2008
September 30, 2008	$	0.4100	November 7, 2008	November 14, 2008
December 31, 2008	$	0.4100	February 10, 2009	February 13, 2009
March 31, 2009*	$	0.0250	May 11, 2009	May 15, 2009
June 30, 2009*	$	0.0250	August 10, 2009	August 14, 2009
September 30, 2009*	$	0.0250	November 9, 2009	November 13, 2009
December 31, 2009*	$	0.0250	February 8, 2010	February 12, 2010
March 31, 2010*	$	0.0250	May 7, 2010	May 14, 2010
June 30, 2010*	$	0.0250	August 9, 2010	August 13, 2010
September 30, 2010+	$	0.0250	November 8, 2010	November 12, 2010
December 31, 2010+	$	0.1500	February 7, 2011	February 14, 2011

______________________________

+ The distribution per unit represents distributions made only on common units.

* The distribution per unit represents distributions made only on common units and general partner units.

NOTE 9. RELATED PARTY TRANSACTIONS

During the year ended December 31, 2010, 2009 and 2008 the Partnership incurred $6.8 million, $8.8 million and $0.6 million, respectively, in expenses with related parties, of which there was an outstanding accounts payable balance of $0.5 million and $0.7 million as of December 31, 2010 and 2009, respectively.

Related to its investments in unconsolidated subsidiaries, during the year ended December 31, 2010 and 2009, the Partnership recorded income of less than $0.1 million for each of the periods. There were no outstanding accounts receivable balances as of December 31, 2010 and 2009.

The Partnership receives services from Stanolind Field Services ("SFS"), which was an entity controlled by Natural Gas Partners ("NGP"). On August 2, 2010, SFS ceased being a related party of the Partnership as NGP sold all of its interests in SFS. During the periods from January 1, 2010 through August 2, 2010 and during the years ended December 31, 2009 and 2008, the Partnership incurred approximately $0.6 million, $2.2 million and 2.1 million, respectively, for services performed by SFS. As of December 31, 2010 and 2009, there were no outstanding accounts payable balances.

As of December 31, 2010 and 2009, the Partnership had zero and $0.5 million, respectively, due from Holdings relating to payments made by the Partnership on Holdings' behalf.

As of December 31, 2010 and 2009, the Partnership had $0.1 million due to Sweeny Gathering, L.P. (the Partnership owns a 50% joint venture in this entity), for money the Partnership has collected on their behalf.

During 2009 and 2008, the Partnership leased office space from Montierra Minerals & Production, L.P. (“Montierra”), which is owned by NGP and certain members of the Partnership's senior management, including the Chief Executive Officer. During the years ended December 31, 2009 and 2008, the Partnership made rental payments of $0.1 million for each year. In addition, the Partnership was reimbursed by Montierra for services performed by its employees on behalf of Montierra of less than $0.1 million, $0.1 million and $0.2 million for the years ended December 31, 2010, 2009 and 2008, respectively. As of December 31, 2010 and 2009, no amounts were due to or from Montierra.

As of December 31, 2010 and 2009, the Partnership had an outstanding receivable balance of zero and $0.7 million, respectively, due from an affiliate of NGP.

In connection with the closing of the Partnership's initial public offering, on October 24, 2006, it entered into a registration rights agreement with Eagle Rock Holdings, L.P. in connection with its contribution to the Partnership of all of Eagle Rock Holdings, L.P.'s limited and general partner interests in Eagle Rock's predecessor. In the registration rights agreement, the Partnership agreed, for the benefit of Eagle Rock Holdings, L.P., to register the common units it holds, the

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common units issuable upon conversion of the subordinated units that it holds and any common units or other equity securities issuable in exchange for the common units and subordinated units it holds. The registration rights agreement is still in effect and the Partnership is in compliance with all obligations of the agreement.

In connection with the closing of the acquisition of certain fee minerals, royalties, overriding royalties and non-operated working interest properties from Montierra and NGP-VII Co-Investment Opportunities, L.P. ("Co-Invest"), the Partnership entered into a registration rights agreements with Montierra and Co-Invest. In the registration rights agreements, the Partnership agreed, for the benefit of Montierra and Co-Invest, to register the common units it holds, the common units issuable upon conversion of the subordinated units that it holds and any common units or other equity securities issuable in exchange for the common units and subordinated units it holds. The registration rights agreement is still in effect and the Partnership is in compliance with all obligations of the agreement.

On April 30, 2008, the Partnership completed the acquisition of all of the outstanding capital stock of Stanolind, for an aggregate purchase price of $81.8 million. Because of the potential conflict of interest between the interests of the Company and the public unitholders of Eagle Rock, the Board of Directors authorized the Company's Conflicts Committee to review, evaluate, and, if determined appropriate, approve the Stanolind Acquisition. The Conflicts Committee, consisting of independent Directors of the Company, determined that the Stanolind Acquisition was fair and reasonable to Eagle Rock and its public unitholders and recommended to the Board of Directors of the Company that the transaction be approved and authorized. In determining the purchase consideration for the Stanolind Acquisition, the Conflicts Committee considered the valuation of the properties involved in the transaction, the valuation of the units to be offered as consideration in the transaction, and the cash flow of Stanolind. Based on the recommendation of the Conflicts Committee, the Board of Directors approved the transaction.

Recapitalization and Related Transactions

On December 21, 2009, the Partnership announced that it, through certain of its affiliates, had entered into definitive agreements with affiliates of NGP and Black Stone Minerals Company, L.P. (“Black Stone”) to improve its liquidity and simplify its capital structure. The definitive agreements included: (i) a Securities Purchase and Global Transaction Agreement, entered into between Eagle Rock Energy and NGP, including Eagle Rock Energy's general partner entities controlled by NGP, and (ii) a Purchase and Sale Agreement (the “Minerals Business Sale Agreement”), entered into between Eagle Rock Energy and Black Stone for the sale of Eagle Rock Energy'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 Holdings, which is controlled by NGP (the Partnership refers to the amended Securities Purchase and Global Transaction Agreement as the “Global Transaction Agreement”). The Partnership refers to the transactions contemplated by the Global Transaction Agreement and Minerals Business Sale Agreement collectively as the “Recapitalization and Related Transactions.”

On May 21, 2010, at a reconvened special meeting of the Partnership's common unitholders, a majority of the Partnership's unaffiliated unitholders approved, among other things, the Recapitalization and Related Transactions.

The Recapitalization and Related Transactions included the following key provisions,

•

An option in favor of the Partnership, to issue 1,000,000 common units to capture the value of its controlling interest through (i) acquiring the Partnership's general partner, and such general partner's general partner, and thereafter canceling the 844,551 general partner units outstanding, and (ii) reconstituting its board of directors to allow its common unitholders to elect the majority of its directors (the “GP Acquisition Option”);


•	The sale of the Partnership's Minerals Business to Black Stone for which we received net proceeds of $171.6 million. The Partnership retained approximately $2.9 million of cash received from net revenues received from the Minerals Business after the effective date of the sale, making its total proceeds from the sale of the Minerals Business $174.5 since January 1, 2010;


•	The simplification of the Partnership's capital structure through the contribution, and resulting cancellation, of the incentive distribution rights and the approximate 20.7 million subordinated units held by Holdings;


•	A rights offering for which Holdings and NGP agreed to fully participate with respect to 9.5 million common and general partner units owned or controlled by NGP as well as with respect to common units it received (see below) as payment of the transaction fee; and


•	For a period of up to four months following unitholder approval of the amended Global Transaction

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Agreement, NGP's commitment to back-stop (primarily through Holdings) up to $41.6 million, at a price of $3.10 per unit, an Eagle Rock Energy equity offering to be undertaken at the sole option of the Partnership's Conflicts Committee.

In exchange for NGP's and Holdings' contributions and commitments under the Global Transaction Agreement, Eagle Rock paid Holdings a transaction fee of $29 million in newly-issued common units. The units were valued at $6.0101 per unit, based on 90% of the volume-adjusted trailing 10-day average of the trading price of Eagle Rock's common units as of April 24, 2010, resulting in a total of approximately 4.8 million common units paid to Holdings upon completion of the Minerals Business sale on May 24, 2010.

The sale of the Minerals Business closed on May 24, 2010, and the Partnership received $171.6 million in net proceeds (after consideration of approximately $2.9 million of net revenues received from the Minerals Business after the effective date) (see Note 17).

The subordinated units and incentive distribution rights were contributed and subsequently cancelled on May 24, 2010

(see Note 8).

The rights offering was launched on June 1, 2010 and expired on June 30, 2010 (see Note 8).

On July 27, 2010, the Partnership gave notice to Holding of its intention to exercise the GP Acquisition Option. On July 30, 2010, the Partnership closed the acquisition and cancelled the general partner units (see Note 8).

NGP's commitment to back-stop an Eagle Rock Energy equity offering expired on September 21, 2010.

See Note 7 for a discussion of an amendment to the Partnership's revolving credit facility related to the Recapitalization and Related Transactions.

See Note 12 for a discussion of a settled lawsuit that alleged certain claims related to the Recapitalization and Related

Transactions.

In connection with the Recapitalization and Related Transactions, the Partnership incurred legal (not including related litigation costs), accounting, advisory and similar costs, beginning in May 2009 through December 31, 2010, totaling

$6.6 million. Of these costs, the Partnership expensed $2.5 million, of which $0.4 million was recorded as part of discontinued operations, and capitalized $4.1 million as transactions costs within Members' Equity.

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NOTE 10. FAIR VALUE OF FINANCIAL MEASUREMENTS

Effective January 1, 2008, the Partnership adopted authoritative guidance which, among other things, requires enhanced disclosures about assets and liabilities carried at fair value.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Partnership utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk inherent in the inputs to the valuation technique. The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).

The three levels of the fair value hierarchy are as follows:

Level 1 – Quoted prices are available in active markets for identical assets and liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the market place throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value.

As of December 31, 2010, the Partnership has recorded its interest rate swaps and commodity derivative instruments (see Note 11), which includes crude oil, natural gas and natural gas liquids (“NGLs”), at fair value. The Partnership has classified the inputs to measure the fair value of its interest rate swap, crude oil derivatives and natural gas derivatives as Level 2. Because the NGL market is thinly traded and considered to be less liquid, the Partnership has classified the inputs related to its NGL derivatives as Level 3. The following table discloses the fair value of the Partnership's derivative instruments as of December 31, 2010 and 2009:



	As of December 31, 2010
	Level 1		Level 2			Level 3			Netting(a)			Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	—		$	—		$	(1,292	)	$	(1,292	)
Natural gas derivatives	—		16,731			—			(14,364		)	2,367
NGL derivatives	—		—			168			(168		)	—
Total	$	—	$	16,731		$	168		$	(15,824	)	$	1,075

Liabilities:
Crude oil derivatives	$	—	$	(45,664	)	$	—		$	1,292		$	(44,372	)
Natural gas derivatives	—		(35		)	—			14,364			14,329
NGL derivatives	—		—			(5,901		)	168			(5,733		)
Interest rate swaps	—		(34,579		)	—			—			(34,579		)
Total	$	—	$	(80,278	)	$	(5,901	)	$	15,824		$	(70,355	)

__________________________


(a)	Represents counterparty netting under agreements governing such derivative contracts.

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	As of December 31, 2009
	Level 1		Level 2			Level 3			Netting(a)			Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	9,089		$	—		(9,086		)	$	3
Natural gas derivatives	—		8,761			—			(3,475		)	5,286
Interest rate swaps	—		600			—			—			600
Total	$	—	$	18,450		$	—		$	(12,561	)	$	5,889

Liabilities:
Crude oil derivatives	$	—	$	(54,125	)	$	—		9,086			$	(45,039	)
Natural gas derivatives	—		—			—			3,475			3,475
NGL derivatives	—		—			(14,784		)	—			(14,784		)
Interest rate swaps	—		(28,017		)	—			—			(28,017		)
Total	$	—	$	(82,142	)	$	(14,784	)	$	12,561		$	(84,365	)

__________________________


(a)	Represents counterparty netting under agreements governing such derivative contracts.

The fair value hierarchy of derivative assets and liabilities presented as of December 31, 2009 has been changed from the previously presented 2009 disclosures to reflect gross assets and liabilities reconciled to the net presentation in the consolidated balance sheet due to counterparty netting under agreements governing such derivative contracts.

As of December 31, 2010 and 2009, risk management current assets in the Consolidated Balance Sheet include put premiums and other derivative costs, net of amortization, of zero and $4.0 million, respectively.

The following table sets forth a reconciliation of changes in the fair value of the Level 3 NGL derivatives during the years ended December 31, 2010, 2009 and 2008 (in thousands):



	Year Ended December 31,
	2010			2009			2008
Net asset (liability) balance as of January 1	$	(14,784	)	$	14,016		$	(52,793	)
Settlements	12,358			66			16,098
Total gains or losses (realized and unrealized)	(3,307		)	(28,866		)	50,711
Net (liability) asset balance as of December 31	$	(5,733	)	$	(14,784	)	$	14,016

The Partnership values its Level 3 NGL derivatives using forward curves, volatility curves, volatility skew parameters, interest rate curves and model parameters. In addition, the impact of counterparty credit risk is factored into the value of derivative assets and the Partnership's credit risk is factored into the value of derivative liabilities.

The Partnership recognized (losses) gains of $(5.7) million, $(15.2) million, and $50.0 million in the years ended December 31, 2010, 2009 and 2008, respectively, that are attributable to the change in unrealized gains or losses related to those assets and liabilities still held at December 31, 2010, 2009 and 2008, which are included in the commodity risk management (losses) gains.

Realized and unrealized losses related to the interest rate derivatives are recorded as part of interest rate risk management gains and losses in the Consolidated Statements of Operations. Realized and unrealized gains and losses and premium amortization related to the Partnership's commodity derivatives are recorded as a component of revenue in the Consolidated Statements of Operations.

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The following table discloses the fair value of the Partnership's assets measured at fair value on a nonrecurring basis for the year ended December 31, 2010 (in thousands):



	December 31, 2010		Level 1		Level 2		Level 3		Total Losses
Plant assets	$	131	$	—	$	—	$	131	$	725
Pipeline assets	$	6,498	$	—	$	—	$	6,498	$	25,410
Rights-of-way	$	85	$	—	$	—	$	85	$	1,609
Contracts	$	—	$	—	$	—	$	—	$	1,595
Unproved properties	$	—	$	—	$	—	$	—	$	3,432
Proved properties	$	132	$	—	$	—	$	132	$	104

In connection with the preparation of these financial statements for the year ended December 31, 2010, the Partnership wrote down plant assets with a carrying value of $0.9 million to their fair value of $0.1 million, pipeline assets with a carrying value of $31.9 million to their fair value of $6.5 million, rights-of-way with a carrying value of $1.7 million to their fair value of $0.1 million, contracts with a carrying value of $1.6 million to their fair value of zero, proved properties with a carrying value of $0.2 million to their fair value of $0.1 million and unproved properties with a carrying value of $3.4 million to their fair value of zero, resulting in an impairment charge of $32.9 million being included in earnings for the year ended December 31, 2010, of which $26.2 million was recorded within discontinued operations. The impairment charges related to plant assets, pipeline assets, rights-of-way and contracts related specifically to the Midstream Business due to the loss during the second quarter 2010 of a significant contract on the Partnership's Raymondville system within its South Texas Segment and due to an anticipated decline in volumes on the Partnership's Wildhorse gathering system within its South Texas Segment, while the impairment of the Upstream Segment's unproved properties was due to the Partnership determining that it was not technologically feasible to develop these unproved locations and the Upstream Segment's proved properties was due to adjustments to its reserves. The Partnership calculated the fair value of the impaired assets on its Raymondville system and its proved properties using discounted cash flow analysis to determine the excess of the asset's carrying value over its fair value. The Partnership calculated the fair value of the impaired assets on its Wildhorse gathering system based on an unsolicited value of the system provided by a market participant.

The carrying amount of cash equivalents is believed to approximate their fair values because of the short maturities of these instruments. The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments.

The Partnership believes that the fair value of its Revolving Credit Facility does not approximate its carrying value as of December 31, 2010 because the applicable floating rate margin on the Revolving Credit Facility was a below-market rate. The fair value of the Revolving Credit Facility has been estimated based on similar transactions that occurred during the twelve months ended December 31, 2010 and the first two months of 2011. The Partnership's estimate of the fair value of the borrowings under its Revolving Credit Facility as of December 31, 2010 was $518.0 million versus a carrying value of $530.0 million. The Partnership's estimate of the fair value of the borrowings under its Revolving Credit Facility as of December 31, 2009 was $713.2 million versus a carrying value of $754.4 million.

NOTE 11. RISK MANAGEMENT ACTIVITIES

To mitigate its interest rate risk, the Partnership entered into various interest rate swaps. These swaps convert the variable-rate term loan into a fixed-rate obligation. The purpose of entering into these swaps is to eliminate interest rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense.

On March 30, 2009, the Partnership amended all of its existing interest rate swaps to change the interest rate the Partnership received from three month LIBOR to one month LIBOR through January 9, 2011. During this time period, the fixed rate to be paid by the Partnership was reduced, on average, by 20 basis points. After January 9, 2011, the interest rate to be received by the Partnership changed back to three month LIBOR, and the fixed rate the Partnership pays reverted back to the original rate through the end of swap maturities in 2012.

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The table below summarizes the terms, amounts received or paid and the fair values of the various interest rate swaps:



Effective Date	Expiration Date	Notional Amount		Fixed Rate (a)
12/31/2008	12/31/2012	$	150,000,000	2.360% / 2.560%
9/30/2008	12/31/2012	150,000,000		4.105% / 4.295%
10/3/2008	12/31/2012	300,000,000		3.895% / 4.095%

_________________________________


(a)	First amount is the rate the Partnership pays through January 9, 2011 and the second amount is the interest rate the Partnership pays from January 10, 2011 through December 31, 2012.

The Partnership's interest rate derivative counterparties include Wells Fargo Bank N.A. and The Royal Bank of Scotland plc.

Commodity Derivative Instruments

The prices of crude oil, natural gas and NGLs are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors which are beyond the Partnership's control. These risks can cause significant changes in the Partnership's cash flows and affect its ability to achieve its distribution objective and comply with the covenants of its revolving credit facility. In order to manage the risks associated with the future prices of crude oil, natural gas and NGLs, the Partnership engages in non-speculative risk management activities that take the form of commodity derivative instruments. The Partnership has determined that it is necessary to hedge a substantial portion of its expected production in order to meaningfully reduce its future cash flow volatility. The Partnership generally limits its hedging levels to 80% of expected future production. While hedging at this level of production does not eliminate all of the volatility in the Partnership's cash flows, it allows the Partnership to mitigate the risk of situations where a modest loss of production would put it in an over-hedged position. The Partnership may hedge for periods of time above the 80% of expected future production levels where it deems it prudent to reduce extreme future price volatility. However, hedging to that level requires approval of the Board of Directors, which the Partnership obtained for its 2009 and 2010 hedging activity. At times, the Partnership's strategy may involve entering into hedges with strike prices above current future prices or resetting existing hedges to higher price levels in order to meet its cash flow objectives or to stay in compliance with its revolving credit facility. In addition, the Partnership may also terminate or unwind hedges or portions of hedges when the expected future volumes do not support the level of hedges. Expected future production for its Upstream Business is derived from the proved reserves, adjusted for price-dependent expenses and revenue deductions. For the Midstream Business, expected future production is based on the expected production from wells currently flowing to the Partnership's processing plants, plus additional volumes the Partnership expects to receive from future drilling activity by its producer customer base. The Partnership's expectations for its Midstream Business volumes associated with future drilling are based on information it receives from its producer customer base and historical observations. The Partnership applies the appropriate contract terms to these projections to determine its expected future equity share of the commodities.

The Partnership uses put options, costless collars and fixed-price swaps to achieve its hedging objectives, and often hedges its expected future volumes of one commodity with derivatives of the same commodity. In some cases, however, the Partnership believes it is better to hedge future changes in the price of one commodity with a derivative of another commodity, which it refers to as “cross-commodity” hedging. The Partnership will often hedge the changes in future NGL prices (propane and heavier) using crude oil hedges because NGL prices have been highly correlated to crude oil prices and hedging NGLs directly is usually less attractive due to the relative illiquidity in the NGL forward market. The Partnership will also use natural gas hedges to hedge a portion of its expected future ethane production because forward prices for ethane are often heavily discounted from its current prices. Also, natural gas prices provide support for ethane prices because in many processing plants ethane can be recombined with the residue gas stream and sold as natural gas. When the Partnership uses cross-commodity hedging, it will convert the expected volumes of the underlying commodity to equivalent volumes of the hedged commodity. In the case of NGLs hedged with crude oil derivatives, these conversions are based on the linear regression of the prices of the two commodities observed during the previous 36 months and management's judgment regarding future price relationships of the commodities. In the case where ethane is hedged with natural gas derivatives, the conversion is based on the thermal content of ethane.

The Partnership has a risk management policy which allows management to execute crude oil, natural gas and NGL hedging instruments in order to reduce exposure to substantial adverse changes in the prices of these commodities. The Partnership continually monitors and ensures compliance with this risk management policy through senior level executives in its operations, finance and legal departments.

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The Partnership has not designated any of its commodity derivative instruments as hedges and therefore is marking these derivative contracts to fair value. Changes in fair values of the commodity derivative instruments are recorded as an adjustment to the mark-to-market gains (losses) on risk management transactions within revenue.

By using derivative instruments to economically hedge exposure to changes in commodity prices, the Partnership exposes itself to credit risk, which is the failure of the counterparty to perform under the terms of the derivative contract. The Partnership's counterparties are all participants or affiliates of participants within its Revolving Credit Facility (see Note 7), which is secured by substantially all of the assets of the Partnership. Therefore, the Partnership is not required to post any collateral, nor does it require collateral from its counterparties. The Partnership minimizes the credit risk in derivative instruments by limiting its exposure to any single counterparty and monitoring the creditworthiness of its counterparties on an ongoing basis. In addition, the Partnership's derivative contracts, for certain counterparties, are subject to counterparty netting agreements governing such derivatives and therefore the risk of loss is somewhat mitigated.

The Partnership's commodity derivative counterparties include BNP Paribas, Wells Fargo Bank, N.A, Comerica Bank, Barclays Bank PLC, Bank of Nova Scotia, The Royal Bank of Scotland plc, Bank of America N.A., J Aron and Company (an affiliate of Goldman Sachs), BBVA Compass Bank and Credit Suisse Energy LLC (an affiliate of Credit Suisse Group AG).

On November 23, 2010, the Partnership entered into a series of hedging transactions to unwind existing contracts. The Partnership unwound; (i) 20,000 barrels a month of an "out-of-the-money" WTI crude oil swap with a price of $80.05, (ii) 15,000 barrels a month of a 20,000 barrels a month "out-of-the-money" WTI crude oil swap with a price of $75.00 and (iii)23,000 barrels a month of a "in-the-money" WTI crude oil swap covering 29,000 barrels per month for the first half of the 2011 calendar year and 23,000 barrels a month covering the second half of the 2011 calendar year with a price a $86.20. For these transactions, the Partnership paid $2.2 million. The Partnership was using these WTI crude oil derivatives to hedge against changes in NGL prices. To continue hedging these NGL volumes, the Partnership then entered into the following derivative transactions for the 2011 calendar year on November 23, 2010: a 996,000 gallon per month OPIS normal butane swap at $1.50 per gallon, a 462,000 gallon per month OPIS iso butane swap at $1.5425 per gallon, a 378,000 gallon per month OPIS natural gasoline swap at $1.8525 per gallon, a 1,680,000 gallon per month OPIS propane swap for $1.1165 per gallon and a 252,000 gallon per month OPIS propane swap for $1.11 per gallon.

On December 20, 2010, the Partnership entered into a 34,000 MMbtu per month Henry Hub natural gas swap at $4.45 per MMbtu. For this swap, the Partnership will be paying the fixed price, where normally, for the swaps it enters into, it pays the floating price. The Partnership was using a portion of its Henry Hub natural gas swaps to hedge against changes in ethane prices and this transaction effectively unwinds a portions of these swaps. To continue hedging these ethane volumes, the Partnership then entered into a 1,428,000 gallon per month OPIS ethane swap at a price of $0.545 per gallon.

In addition, during the year ended December 31, 2010, the Partnership entered into the following derivative transactions for its 2011 calendar year: a 12,000 barrel per month NYMEX WTI costless collar with a floor strike price at $75.00 per barrel and a cap strike price of $89.85 per barrel on February 16, 2010, a 17,000 barrel per month NYMEX WTI swap at $83.30 on June 18, 2010 and a NYMEX WTI swap covering 29,000 barrels per month for the first half of the calendar year and 23,000 barrels per month for the second half of the calendar year with a strike price of $86.20 per barrel on August 23, 2010.

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The following table, as of December 31, 2010, sets forth certain information regarding the Partnership's commodity derivatives that will mature during the year ended December 31, 2011:

Underlying

Period

Notional

Volumes

(units)

Type

Floor

Strike

Price

($/unit)

Cap

Strike

Price

($/unit)

Natural Gas:

NYMEX Henry Hub

Jan-Dec 2011

1,200,000 mmbtu

Costless Collar

7.50

8.85

NYMEX Henry Hub

Jan-Dec 2011

720,000 mmbtu

Swap

7.085

NYMEX Henry Hub

Jan-Dec 2011

2,280,000 mmbtu

Swap

6.57

NYMEX Henry Hub

Jan-Dec 2011

(408,000) mmbtu

Swap

4.45

Crude Oil:

NYMEX WTI

Jan-Dec 2011

139,152 bbls

Costless Collar

75.00

85.70

NYMEX WTI

Jan-Dec 2011

360,000 bbls

Costless Collar

80.00

92.40

NYMEX WTI

Jan-Dec 2011

144,000 bbls

Costless Collar

75.00

89.85

NYMEX WTI

Jan-Dec 2011

125,256 bbls

Swap

80.00

NYMEX WTI

Jan-Dec 2011

120,000 bbls

Swap

65.10

NYMEX WTI

Jan-Dec 2011

60,000 bbls

Swap

75.00

NYMEX WTI

Jan-Dec 2011

360,000 bbls

Swap

65.60

NYMEX WTI

Jan-Dec 2011

204,000 bbls

Swap

83.30

NYMEX WTI

Jan-Jun 2011

36,000 bbls

Swap

86.20

Natural Gas Liquids:

OPIS NButane Mt. Belv non TET

Jan-Dec 2011

11,592,000 gallons

Swap

1.50

OPIS IsoButane Mt. Belv non TET

Jan-Dec 2011

5,544,000 gallons

Swap

1.5425

OPIS Natural Gasoline Mt. Belv non TET

Jan-Dec 2011

4,536,000 gallons

Swap

1.8525

OPIS Propane Mt. Belv non TET

Jan-Dec 2011

20,160,000 gallons

Swap

1.1165

OPIS Propane Mt. Belv non TET

Jan-Dec 2011

3,024,000 gallons

Swap

1.11

OPIS Ethane Mt. Belv non TET

Jan-Dec 2011

17,136,000 gallons

Swap

0.545

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The following table, as of December 31, 2010, sets forth certain information regarding the Partnership's commodity derivatives that will mature during the year ended December 31, 2012:

Underlying

Period

Notional

Volumes

(units)

Type

Floor

Strike

Price

($/unit)

Cap

Strike

Price

($/unit)

Natural Gas:

NYMEX Henry Hub

Jan-Dec 2012

1,080,000 mmbtu

Costless Collar

7.35

8.65

NYMEX Henry Hub

Jan-Dec 2012

3,120,000 mmbtu

Swap

6.77

Crude Oil:

NYMEX WTI

Jan-Dec 2012

135,576 bbls

Costless Collar

75.30

86.30

NYMEX WTI

Jan-Dec 2012

360,000 bbls

Costless Collar

80.00

98.50

NYMEX WTI

Jan-Dec 2012

192,000 bbls

Costless Collar

75.00

94.75

NYMEX WTI

Jan-Dec 2012

108,468 bbls

Swap

80.30

NYMEX WTI

Jan-Dec 2012

240,000 bbls

Swap

68.30

NYMEX WTI

Jan-Dec 2012

240,000 bbls

Swap

76.50

NYMEX WTI

Jan-Dec 2012

240,000 bbls

Swap

82.02

NYMEX WTI

Jan-Dec 2012

420,000 bbls

Swap

90.65

On February 16, 2010, the Partnership entered into a 12,000 barrels per month WTI costless collar with a floor strike price at $75.00 per barrel and a cap strike price of $89.85 per barrel for its 2011 calendar year. On February 17, 2010, the Partnership entered into a 16,000 barrels per month NYMEX WTI costless collar with a floor strike price at $75.00 per barrel and a cap strike price of $94.75 per barrel for its 2012 calendar year.

The following table, as of December 31, 2010, sets forth certain information regarding the Partnership's commodity derivatives that will mature during the year ended December 31, 2013:

Underlying

Period

Notional

Volumes

(units)

Type

Floor

Strike

Price

($/unit)

Cap

Strike

Price

($/unit)

Natural Gas:

NYMEX Henry Hub

Jan-Dec 2013

600,000 mmbtu

Swap

5.65

NYMEX Henry Hub

Jan-Dec 2013

600,000 mmbtu

Swap

5.30

NYMEX Henry Hub

Jan-Dec 2013

600,000 mmbtu

Swap

5.305

Crude Oil:

NYMEX WTI

Jan-Dec 2013

240,000 bbls

Swap

90.20

NYMEX WTI

Jan-Dec 2013

720,000 bbls

Swap

89.85

NYMEX WTI

Jan-Dec 2013

384,000 bbls

Swap

90.75

NYMEX WTI

Jan-Dec 2013

120,000 bbls

Swap

88.20

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Fair Value of Interest Rate and Commodity Derivatives

Fair values of interest rate and commodity derivative instruments not designated as hedging instruments in the consolidated balance sheet as of December 31, 2010 and 2009:



	As of December 31, 2010
	Derivative Assets				Derivative Liabilities
	Balance Sheet Classification	Fair Value			Balance Sheet Classification	Fair Value
	($ in thousands)
Interest rate derivatives - liabilities		$	—		Current liabilities	$	(19,822	)
Interest rate derivatives - liabilities		—			Long-term liabilities	(14,757		)
Commodity derivatives - assets	Current assets	—			Current liabilities	9,150
Commodity derivatives - assets	Long-term assets	2,402			Long-term liabilites	5,347
Commodity derivatives - liabilities	Current assets	—			Current liabilities	(28,678		)
Commodity derivatives - liabilities	Long-term assets	(1,327		)	Long-term liabilities	(21,595		)
Total derivatives		$	1,075			$	(70,355	)

	As of December 31, 2009
	Derivative Assets				Derivative Liabilities
	Balance Sheet Classification	Fair Value			Balance Sheet Classification	Fair Value
	($ in thousands)
Interest rate derivatives - assets	Long-term assets	$	600			$	—
Interest rate derivatives - liabilities		—			Current liabilities	(16,988		)
Interest rate derivatives - liabilities		—			Long-term liabilities	(11,029		)
Commodity derivatives - assets	Current assets	3,494			Current liabilities	9,842
Commodity derivatives - assets	Long-term assets	2,830			Long-term liabilities	1,684
Commodity derivatives - liabilities	Current assets	(1,015		)	Current liabilities	(44,504		)
Commodity derivatives - liabilities	Long-term assets	(20		)	Long-term liabilities	(23,370		)
Total derivatives		$	5,889			$	(84,365	)

The following table sets forth the location of gains and losses for derivatives not designated as hedging instruments within the Partnership's Consolidated Statement of Operations (in thousands):



		Amount of Gain (Loss) recognized in Income on Derivatives
		2010			2009			2008
Interest rate derivatives	Interest rate risk management losses	$	(27,135	)	$	(6,347	)	$	(32,931	)
Commodity derivatives	Commodity risk management (losses) gains	(8,786		)	(106,290		)	161,765
Total		$	(35,921	)	$	(112,637	)	$	128,834

The Partnership's hedge counterparties are participants in its credit agreement, and the collateral for the outstanding borrowings under its credit agreement is used as collateral for the Partnership's hedges. The Partnership does not have rights to collateral from its counterparties, nor does it have rights of offset against borrowings under its credit agreement.

NOTE 12. COMMITMENTS AND CONTINGENT LIABILITIES

Litigation—The Partnership is subject to several lawsuits which arise from time to time in the ordinary course of business, such as the interpretation and application of contractual terms related to the calculation of payment for liquids and natural gas proceeds. The Partnership has accruals of approximately zero and $0.1 million as of December 31, 2010 and 2009, respectively, related to these matters. The Partnership has been indemnified up to a certain dollar amount for two of these lawsuits. For the indemnified lawsuits, the Partnership has not established any accruals as the likelihood of these suits being successful against them is considered remote. If there ultimately is a finding against the Partnership in the indemnified cases,

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the Partnership would expect to make a claim against the indemnification up to limits of the indemnification. These matters are not expected to have a material adverse effect on our financial position, results of operations or cash flows.

On February 9, 2010, a lawsuit, alleging certain claims related to the Recapitalization and Related Transactions (see

Note 9), was filed on behalf of one of the Partnership's public unitholders in the Court of Chancery of the State of Delaware

naming the Partnership, its general partner, certain affiliates of its general partner, including the general partner of its general

partner, and each member of the Partnership's Board of Directors as defendants. The complaint alleged a breach by the defendants of their fiduciary duties to the Partnership and the public unitholders and sought to enjoin the Recapitalization and

Related Transactions. The Partnership believed the allegations made in the complaint were without merit. On March 11, 2010, in an effort to minimize the further cost, expense, burden and distraction of any litigation relating to the lawsuit, the parties to the lawsuit entered into a Memorandum of Understanding regarding the terms of a potential settlement of the lawsuit. On August 16, 2010, the parties to the lawsuit filed a Stipulation and Agreement of Compromise, Settlement and Release with the Court of Chancery of the State of Delaware. The settlement resolved the allegations by the plaintiff against the defendants in connection with the Recapitalization and Related Transactions and provides a release and settlement by a proposed class of the Partnership common unitholders during the period from September 17, 2009 through and including the date of the closing of the transactions of all claims against the defendants as they relate to the Recapitalization and Related Transactions. At a hearing on October 28, 2010, the Court of Chancery of the State of Delaware approved the settlement and entered a final Order and Judgment. The order approving the settlement became final on November 29, 2010. During the year ended December 31, 2010, the Partnership incurred $1.2 million of costs, and as of December 31, 2010, the Partnership no longer had an accrual relating to this matter. In addition, the Partnership had recorded a receivable related to this matter of approximately $0.6 million for amounts it expects to recover under its Directors and Officers insurance, of which approximately $0.3 million remains outstanding as of December 31, 2010.

Insurance—The Partnership covers its operations and assets with insurance which management believes is consistent with that in force for other companies engaged in similar commercial operations with similar type properties. This insurance includes: (1) commercial general liability insurance covering liabilities to third parties for bodily injury, property damage and pollution arising out of Eagle Rock Energy operations; (2) workers’ compensation liability coverage for employees to required statutory limits; (3) automobile liability insurance covering liability to third parties for bodily injury and property damage arising out of the operation of all owned, hired and non-owned vehicles by its employees on company business; (4) property insurance covering the replacement cost of all owned real and personal property, including coverage for losses due to boiler and machinery breakdown, earthquake, flood and consequent business interruption/extra expense; (5) control of well/operator's extra expense insurance for operated and non operated wells in the Upstream Segment; and (6) corporate liability insurance including coverage for Directors and Officers and Employment Practices liabilities. In addition, the Partnership maintains excess liability insurance providing limits in excess of the established primary limits for commercial general liability and automobile liability insurance.

All coverages are subject to industry accepted policy terms, conditions, limits and deductibles comparable to that obtained by other energy companies with similar operations. The cost of insurance for the energy industry continued to fluctuate over the past year, reflecting the changing conditions in the insurance markets.

Regulatory Compliance—In the ordinary course of business, the Partnership is subject to various laws and regulations. In the opinion of management, the Partnership is in material compliance with existing laws and regulations.

Environmental—The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, the Partnership must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership's combined results of operations, financial position or cash flows. At December 31, 2010 and 2009, the Partnership had accrued approximately $4.0 million and $4.4 million, respectively, for environmental matters.

During 2009, the Partnership completed voluntary self-audits of its compliance with air quality standards, which included permitting in the Texas Panhandle Segment as well as a majority of its other Midstream Business locations and some of its Upstream Business locations in Texas. These audits were performed pursuant to the Texas Environmental, Health and

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Safety Audit Privilege Act, as amended. The Partnership completed the disclosures to the Texas Commission on Environmental Quality (“TCEQ”), and the Partnership has substantially addressed the deficiencies that it disclosed therein. The Partnership does not foresee at this time any impediment in timely addressing the remaining deficiencies identified as a result of these audits.

Since January 1, 2010, the Partnership has received additional Notices of Enforcement (“NOEs”) and Notices of Violation (“NOVs”) from the TCEQ related to air compliance matters and expects to receive additional NOEs or NOVs from the TCEQ from time to time throughout 2011. Though the TCEQ has the discretion to adjust penalties and settlements upwards based on a compliance history containing multiple, successive NOEs, the Partnership does not expect that the resolution of any existing NOE or any future similar NOE will vary significantly from the administrative penalties and agreed settlements experienced by it to date.

Retained Revenue Interest—Certain assets of the Partnership's Upstream Segment are subject to retained revenue interests. These interests were established under purchase and sale agreements that were executed by the Partnership's predecessors in title. The terms of these agreements entitle the owners of the retained revenue interests to a portion of the revenues received from the sale of the hydrocarbons above specified base oil and natural gas prices. These retained revenue interests do not represent a real property interest in the hydrocarbons. The Partnership's reported revenues are reduced to account for the retained revenue interests on a monthly basis.

The retained revenue interests affect the Partnership's interest at the Big Escambia Creek, Flomaton and Fanny Church fields in Escambia County, Alabama. With respect to the Partnership's Flomaton and Fanny Church fields, these retained revenue interests are in effect for any calendar year in which the Partnership surpasses certain average net production rates, while for the Partnership's Big Escambia field, the retained revenue interest commenced in 2010 and is expected to continue through the end of 2019.

Other Commitments—The Partnership utilizes assets under operating leases for its corporate office, certain rights-of way and facilities locations, vehicles and in several areas of its operation. Rental expense, including leases with no continuing commitment, amounted to approximately $7.8 million, $8.9 million, and $5.8 million for the years ended December 31, 2010, 2009 and 2008, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term. At December 31, 2010, commitments under long-term non-cancelable operating leases for the next five years are as follows: 2011—$4.2 million; 2012—$4.0 million; 2013—$2.4 million; 2014—$1.7 million and 2015—$1.7 million.

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NOTE 13. SEGMENTS

On May 24, 2010, the Partnership completed the sale of its fee mineral and royalty interests as well as its equity investment in Ivory Working Interests, L.P. (collectively, the “Minerals Business”). In February 2011, the Partnership classified the assets and liabilities of its Wildhorse gathering system as held for sale. As authoritative guidance requires the operations for components of entities that are classified as held for sale or have been disposed of be recorded as part of discontinued operations, operating results for the Minerals Business and the Wildhorse gathering system for the years ended December 31, 2010, 2009 and 2008 have been excluded from the Partnership’s segment presentation below. See Note 19 for a further discussion of the sale of the Partnership’s Minerals Business and Note 21 for a further discussion of the Wildhorse gathering system.

Based on the Partnership’s approach to managing its assets, the Partnership believes its operations consist of four geographic segments in its Midstream Business, one upstream segment that is its Upstream Business and one functional (Corporate and Other) segment:


(i)	Midstream—Texas Panhandle Segment:

gathering, compressing, processing and treating natural gas and marketing of natural gas, NGLs and condensate in the Texas Panhandle;


(ii)	Midstream—South Texas Segment:

gathering, compressing, processing and treating natural gas and marketing of natural gas, NGLs and condensate in South Texas;


(iii)	Midstream—East Texas/Louisiana Segment:

gathering, compressing, processing, treating and transporting natural gas and marketing of natural gas, NGLs and condensate and related NGL transportation in East Texas and Louisiana;


(iv)	Midstream—Gulf of Mexico Segment:

gathering and processing of natural gas and fractionating, transporting and marketing of NGLs in South Louisiana, Gulf of Mexico and inland waters of Texas;


(v)	Upstream Segment:

crude oil, natural gas and sulfur production from operated and non-operated wells; and


(vi)	Corporate and Other Segment:

risk management, intersegment eliminations and other corporate activities such as general and administrative expenses.

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The Partnership's chief operating decision-maker (“CODM”) currently reviews its operations using these segments. The CODM evaluates segment performance based on segment operating income or loss from continuing operations. Summarized financial information concerning the Partnership's reportable segments is shown in the following table:



Midstream Business Year Ended December 31, 2010	Texas Panhandle Segment		South Texas Segment			East Texas / Louisiana Segment		Gulf of Mexico Segment			Total Midstream Business
($ in thousands)
Sales to external customers	$	358,235	$	56,885		$	204,349	$	32,954		$	652,423
Cost of natural gas, natural gas liquids and condensate	237,467		51,573			151,236		28,028			468,304
Intersegment cost of oil and condensate	5,587		—			—		—			5,587
Operating costs and other expenses	35,032		1,839			17,275		1,771			55,917
Depreciation, depletion, amortization and impairment	45,876		6,388			18,452		6,838			77,554
Operating income (loss) from continuing operations	$	34,273	$	(2,915	)	$	17,386	$	(3,683	)	$	45,061
Capital Expenditures	$	29,282	$	90		$	15,756	$	180		$	45,308
Segment Assets	$	566,641	$	56,961		$	269,640	$	82,475		$	975,717



Total Segments Year Ended December 31, 2010	Total Midstream Business		Upstream Segment			Corporate and Other Segment				Total Segments
($ in thousands)
Sales to external customers	$	652,423	$	88,672	(c)	$	(8,786	)	(a)	$	732,309
Intersegment sales	—		6,063			(6,063		)		—
Cost of natural gas, natural gas liquids and condensate	468,304		—			—				468,304
Intersegment cost of oil and condensate	5,587		—			(5,587		)		—
Operating costs and other (income) expenses	55,917		32,724		(b)	45,775				134,416
Intersegment operations and maintenance	—		47			(47		)		—
Depreciation, depletion, amortization and impairment	77,554		33,960			1,550				113,064
Operating income (loss) from continuing operations	$	45,061	$	28,004		$	(56,540	)		$	16,525
Capital Expenditures	$	45,308	$	26,772		$	1,609			$	73,689
Segment Assets	$	975,717	$	359,474		$	14,206		(d)	$	1,349,397

_________________________________


(a)	Represents results of the Partnership's derivatives activity.


(b)	Includes costs to dispose of sulfur in the Upstream segment of $0.7 million for the year ended December 31, 2010.


(c)	Sales to external customers for the year ended December 31, 2010 includes $3.0 million of business interruption insurance recovery related to the shutdown of the Eustace plant in 2010 in the Upstream Segment, which is recognized in Other revenue on the Consolidated Statement of Operations.


(d)	Includes elimination of intersegment transactions.

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Midstream Business Year Ended December 31, 2009	Texas Panhandle Segment		South Texas Segment			East Texas / Louisiana Segment		Gulf of Mexico Segment				Total Midstream Business
($ in thousands)
Sales to external customers	$	293,952	$	78,476		$	209,518	$	33,641		(c)	$	615,587
Cost of natural gas, natural gas liquids and condensate	206,985		73,785			162,957		26,372				470,099
Operating costs and other expenses	31,873		1,904			17,985		1,907				53,669
Depreciation, depletion, amortization and impairment	46,085		11,332			23,129		6,576				87,122
Operating income (loss) from continuing operations	$	9,009	$	(8,545	)	$	5,447	$	(1,214	)		$	4,697
Capital Expenditures	$	7,293	$	69		$	18,188	$	358			$	25,908
Segment Assets	$	539,899	$	93,837		$	285,327	$	87,780			$	1,006,843



Total Segments Year Ended December 31, 2009	Total Midstream Business		Upstream Segment				Corporate and Other Segment				Total Segments
($ in thousands)
Sales to external customers	$	615,587	$	63,633			$	(106,290	)	(a)	$	572,930
Cost of natural gas, natural gas liquids and condensate	470,099		—				—				470,099
Operating costs and other expenses	53,669		24,984			(b)	45,819				124,472
Depreciation, depletion, amortization and impairment	87,122		42,123				1,073				130,318
Operating income (loss) from continuing operations operations	$	4,697	$	(3,474	)		$	(153,182	)		$	(151,959	)
Capital Expenditures	$	25,908	$	8,437			$	2,022			$	36,367
Segment Assets	$	1,006,843	$	363,667			$	164,308			$	1,534,818



Midstream Business Year Ended December 31, 2008	Texas Panhandle Segment		South Texas Segment			East Texas / Louisiana Segment			Gulf of Mexico Segment			Total Midstream Business
($ in thousands)
Sales to external customers	$	603,066	$	167,202		$	322,040		$	1,655		$	1,093,963
Cost of natural gas, natural gas liquids and condensate	459,064		156,549			269,030			1,376			886,019
Operating costs and other expenses	34,269		2,489			16,569			605			53,932
Depreciation, depletion, amortization and impairment	43,688		11,909			40,553			1,521			97,671
Operating income (loss) from continuing operations	66,045		$	(3,745	)	$	(4,112	)	$	(1,847	)	$	56,341
Capital Expenditures	$	30,738	$	1,145		$	17,391		$	—		$	49,274
Segment Assets	$	563,556	$	107,655		$	313,383		$	80,106		$	1,064,700



Total Segments Year Ended December 31, 2008	Total Midstream Business		Upstream Segment			Corporate and Other Segment			Total Segments
($ in thousands)
Sales to external customers	$	1,093,963	$	173,029		$	161,765	(a)	$	1,428,757
Cost of natural gas, natural gas liquids and condensate	886,019		—			—			886,019
Operating costs and other expenses	53,932		37,481			56,317			147,730
Depreciation, depletion, amortization and impairment	97,671		183,008			787			281,466
Operating income (loss) from continuing operations operations	$	56,341	$	(47,460	)	$	104,661		$	113,542
Capital Expenditures	$	49,274	$	20,655		$	751		$	70,680
Segment Assets	$	1,064,700	$	397,785		$	310,576		$	1,773,061

_________________________________


(a)	Represents results of the Partnership's derivatives activity.


(b)	Includes costs to dispose of sulfur in the Upstream segment of $2.2 million for the year ended December 31, 2009.


(c)	Sales to external customers for the year ended December 31, 2009 includes $1.6 million of business interruption insurance recovery related to the damage incurred from Hurricane Ike and Gustav in the Gulf of Mexico Segment, which is recognized in Other revenue on the Consolidated Statement of Operations.

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NOTE 14. EMPLOYEE BENEFIT PLAN

The Partnership offers a defined contribution benefit plan to its employees. The plan, which was amended in December 2007 to eliminate, in part, a requirement that an employee have been with the Partnership longer than six months, provides for a dollar for dollar matching contribution by the Partnership of up to 3% of an employee's contribution and 50% of additional contributions up to an additional 2%. Additionally, the Partnership may, at its sole discretion and election, contribute up to 6% of a participating employee's base salary annually, subject to vesting requirements. Expenses under the plan for the years ended December 31, 2010, 2009 and 2008 were approximately $1.0 million, $0.7 million and $1.4 million, respectively.

NOTE 15. INCOME TAXES

The Partnership's provision for income taxes relates to (i) state taxes for the Partnership and (ii) federal taxes for Eagle Rock Energy Acquisition Co., Inc, (acquiring entity of Redman Energy Holdings, L.P. and Redman Energy Holdings II, L.P. and certain assets owned by NGP Income Co-Investment Opportunities Fund II, L.P. (collectively the "Redman Acquisition") in 2007) and Eagle Rock Energy Acquisition Co. II, Inc. (acquiring entity of certain entities acquired in the Stanolind Acquisition in 2008) and their wholly owned corporations, Eagle Rock Upstream Development Company, Inc., (successor entity of certain entities acquired in the Redman acquisition) and Eagle Rock Upstream Development Company II, Inc. (successor entity of certain entities acquired in the Stanolind acquisition), which are subject to federal income taxes (the “C Corporations”). In addition, with the amendment of the Texas Franchise Tax in 2006, the Partnership has become a taxable entity in the state of Texas. The Partnership's federal and state income tax provision is summarized below (in thousands):



	For the Year Ended December 31,
	2010			2009			2008
Current:
Federal	$	236		$	680		$	140
State	(240		)	1,464			831
Total current provision	(4		)	2,144			971
Deferred:
Federal	(2,204		)	1,862			(6,766		)
State	513			235			2,217
Total deferred	(1,691		)	2,097			(4,549		)
Total (benefit) provision for income taxes	(1,695		)	4,241			(3,578		)
Add Back: Valuation allowance for Federal tax attributes	—			(3,154		)	2,444
Total (benefit) provision for income taxes less valuation allowance	(1,695		)	1,087			(1,134		)
Income taxes from discontinued operations	(890		)	(98		)	(325		)
Total (benefit) provision for income taxes on continuing operations	$	(2,585	)	$	989		$	(1,459	)

The effective rate for the years ended December 31, 2010, 2009 and 2008 are shown in the table below. For 2010 and 2008, the effective tax rates are attributable to the state and federal taxes being applied to their respective book incomes. In 2009, the federal and state based income taxes were applied against book losses which resulted in a 100% effective tax rate. A reconciliation of the provision for income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows (in thousands):

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	For the Year Ended December 31,
	2010			2009			2008
Pre-tax net book income (loss) from continuing operations	$	(25,196	)	$	(179,846	)	$	48,861
Texas Margin Tax current and deferred	(617		)	1,601			2,723
Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities	(1,498		)	(963		)	(4,182		)
Tax attributes used	(470		)	(2,803		)	(2,444		)
Valuation allowance	—			3,154			2,444
(Benefit) provision for income taxes from continuing operations	$	(2,585	)	$	989		$	(1,459	)
Effective income tax rate on continuing operations	10.3		%	100.0		%	(3.0		)%

Significant components of deferred tax liabilities and deferred tax assets as of December 31, 2010 and 2009 are as follows (in thousands):



	December 31, 2010			December 31, 2009
Deferred Tax Assets:
Statutory depletion carryover	$	1,765		$	1,562
AMT credit carryforward	204			—
Total deferred tax	1,969			1,562
Less: valuation allowance	—			—
Net Deferred Tax Assets	1,969			1,562

Deferred Tax Liabilities:
Property, plant, equipment & amortizable assets	(3,295		)	(3,012		)
Unrealized hedging transactions	(540		)	(609		)
Book/tax differences from partnership investment	(34,827		)	(36,625		)
Total Deferred Tax Liabilities	(38,662		)	(40,246		)
Total Net Deferred Tax Liabilities	(36,693		)	(38,684		)
Current potion of total net deferred tax liabilities	—			—
Long-term portion of total net deferred tax liabilities	$	(36,693	)	$	(38,684	)

The Partnership had depletion deduction carryforwards and AMT credit carryforwards of $2.0 million and $1.6 million at December 31, 2010 and 2009, respectively.

The largest single component of Partnership's deferred tax liabilities is related to federal income taxes of the C Corporations described above. Book/tax differences were created by the Redman and Stanolind Acquisitions. These book/tax temporary differences result in a net deferred tax liability of $32.9 million at December 31, 2010, which will be reduced as allocation of built-in gain in proportion to the assets contributed brings the book and tax basis closer together over time. This deferred tax liability was recognized in conjunction with the purchase accounting adjustments for long term assets. The additional $3.8 million in deferred tax liabilities are related to book/tax differences in property, plant, and equipment and unrealized hedging transactions.

On May 18, 2006, the State of Texas enacted House Bill 3 which revised the pre-existing state franchise tax. In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits.

Although the bill states that the Revised Texas Franchise Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. Due to the enactment of the Revised Texas Franchise Tax, the Partnership recorded a net deferred tax liability of $3.8 million, $3.6 million

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and $3.4 million as of December 31, 2010, 2009 and 2008, respectively. The offsetting net changes of $0.2 million, $0.2 million and $1.5 million are shown in the Consolidated Statements of Operations for the years ended December 31, 2010, 2009 and 2008, respectively, as a component of provision for income taxes.

The Partnership adopted authoritative guidance related to accounting for uncertainty in income taxes on January 1, 2007. The Partnership has taken a position which is deemed to be “more likely than not” to be upheld upon review, if any, with respect to the deductibility of certain costs for the purpose of its franchise tax liability on a state franchise return. The Partnership has recorded a provision for the portion of this tax liability equal to the probability of recognition. In addition, the Partnership has accrued interest and penalties associated with these liabilities and has recorded these amounts within its state deferred income tax expense. The amount stated below relates to the tax returns filed for 2010 and 2009, which are still open under current statute. A reconciliation of the beginning and ending amount of the unrecognized tax benefits (liabilities) is as follows (in thousands):



Balance as of December 31, 2009	$	(267	)
Increases related to prior year tax positions	—
Increases related to current year tax positions	(302		)
Balance as of December 31, 2010	$	(569	)

NOTE 16. EQUITY-BASED COMPENSATION

Eagle Rock Energy G&P, LLC, the general partner of the general partner for the Partnership, has a long-term incentive plan as amended (“LTIP”) for its employees, directors and consultants who provide services to the Partnership and its subsidiaries and affiliates. On September 17, 2010, at a special meeting of the unitholders of the Partnership, the Partnership's unitholders approved an amendment and restatement of the Partnership's Long Term Incentive Plan (the "Amended Plan") to (i) increase the number of Partnership common units reserved for issuance under the Amended Plan by 5,000,000 units, (ii) provide for the grant of unit appreciation rights and other unit based awards, and (iii) make certain other non-material changes to the Amended Plan. The Amended Plan became effective following its approval by the Partnership's unitholders. Subsequent to approval, the LTIP provides for the issuance of an aggregate of 7,000,000 common units, to be granted either as options, restricted units or phantom units. Distributions declared and paid on outstanding restricted units are paid directly to the holders of the restricted units. The Partnership has historically only issued restricted units under the LTIP. No options or phantom units have been issued to date.

The weighted average fair value of the units granted during the years ended December 31, 2010, 2009 and 2008 were $6.60, $5.58 and $14.89, respectively. The awards generally vest on the basis of one third of the award each year. During the restriction period, distributions associated with the granted awards will be distributed to the awardees. No options or phantom units have been issued to date.

A summary of the restricted common units’ activity for the year ended December 31, 2010, is provided below:



	Number of Restricted Units		Weighted Average Fair Value
Outstanding at December 31, 2009	1,371,019		$	9.35
Granted	1,293,845		$	6.60
Vested	(798,301	)	$	11.80
Forfeitures	(122,109	)	$	8.19
Outstanding at December 31, 2010	1,744,454		$	6.27

For the years ended December 31, 2010, 2009, and 2008, non-cash compensation expense of approximately $5.4 million, $6.3 million, and $6.0 million, respectively, was recorded related to the granted restricted units. The GP Acquisition, as discussed in Note 8, triggered a change of control under certain award agreements for outstanding restricted common units awarded under the Partnership's LTIP and the accelerated vesting of the 315,607 affected outstanding restricted units, of which 84,086 were cancelled by the Partnership in satisfaction of $0.5 million in related employee tax liability paid by the Partnership, which are included in amounts discussed below. As a result of the accelerated vesting, the Partnership recognized an additional $2.8 million in equity-based compensation in the third quarter of 2010. In addition, during the three months ended September 30, 2010, the Partnership recorded a reduction to compensation expense of $2.2 million as a result of adjusting its forfeiture rate.

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As of December 31, 2010, unrecognized compensation costs related to the outstanding restricted units under the Partnership's LTIP totaled approximately $8.9 million. The remaining expense is to be recognized over a weighted average of 2.56 years.

Due to the vesting of certain restricted units during the years ended December 31, 2010 and 2009, 181,292 and 17,492, respectively, were repurchased by the Partnership for $1.2 million and $0.1 million, respectively, as consideration for the related employee tax liability paid by the Partnership. No units were repurchased in during the year ended December 31, 2008. Pursuant to the terms of the LTIP, these repurchased units are available for future grants under the LTIP.

In addition to equity awards under the LTIP, Eagle Rock Holdings, L.P. (“Holdings”), which is controlled by NGP, has

from time to time granted equity in Holdings to certain employees working on behalf of the Partnership, some of which are

named executive officers. During years ended December 31, 2010, 2009 and 2008, Holdings granted 40,000, 160,000 and 417,000, respectively, “Tier I” incentive interests to certain Eagle Rock Energy employee. The Partnership recorded a portion of the value of the incentive units as compensation expense in the Partnership's Consolidated Statements of Operations. This allocation is based on management's estimation of the total value of the incentive unit grant and of the grantees' portion of time dedicated to the Partnership. The Partnership recorded non-cash compensation expense of $0.1 million, $0.4 million and $1.7 million based on management's estimates related to the Tier I incentive unit grants made by Holdings during years ended December 31, 2010, 2009 and 2008, respectively.

NOTE 17. EARNINGS PER UNIT

Basic earnings per unit are computed by dividing the net income (loss) by the weighted average number of units outstanding during a period. To determine net income (loss) allocated to each class of ownership (common, subordinated and general partner), the Partnership first allocates net income (loss) in accordance with the amount of distributions made for the quarter by each class, if any. The remaining net income (loss) is allocated to each class in proportion to the class weighted average number of units outstanding for a period, as compared to the weighted average number of units for all classes for the period.

The Partnership has unvested restricted common units outstanding, which are considered dilutive securities . These units will be considered in the diluted weighted average common unit outstanding number in periods of net income. In periods of net losses, these units are excluded from the diluted weighted average common unit outstanding number.

As part of its rights offering, the Partnership granted warrants, as discussed in Note 8. Any warrants outstanding during the period are consider to be dilutive securities. These outstanding warrants will be considered in the diluted weighted average common unit outstanding number in periods of net income, except if the exercise price of the outstanding warrants is greater than the average market price of the common units for such periods. In periods of net losses, the outstanding warrants are excluded from the diluted weighted average common unit outstanding number.

For the years ended December 31, 2010, 2009 and 2008, the Partnership determined that it is more dilutive to apply the two-class method versus the treasury stock method in calculating dilutive earnings per unit. Thus, the unvested restricted common units are included in the computation of the diluted weighted average common unit outstanding calculation, but the denominator in the computation of diluted earnings per unit only includes the basic weighted average common units outstanding.

Under the Partnership's original partnership agreement, which was amended and restated on May 24, 2010, in connection with approval of the Recapitalization and Related Transactions, for any quarterly period, incentive distribution rights (“IDRs”) participated in net income only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed earnings or losses. Accordingly, undistributed net income is assumed to be allocated to the other ownership interests on a pro-rata basis. During the years ended December 31,2010 and 2009, the Partnership did not declare a quarterly distribution for the IDRs. On May 24, 2010, the Partnership's general partner contributed all of the outstanding IDRs to the Partnership (see Notes 8 and 9), and they were eliminated.

In addition, all of the subordinated units and general partner units, as discussed in Notes 8 and 9, were contributed to the Partnership and cancelled on May 24, 2010 and July, 30, 2010, respectively. As a result, the number of subordinated units and general partner units used in the calculation of earnings per unit for the three and nine months ended September 30, 2010 is based on the weighted average amount of time they were outstanding during those periods.

The restricted common units granted under the LTIP, as discussed in Note 15, contain non-forfeitable rights to the distributions declared by the Partnership and therefore meet the definition of participating securities. Participating securities are

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required to be included in the computation of earnings per unit pursuant to the two-class method.

The following table presents the Partnership's calculation of basic and diluted units outstanding for the periods indicated:



	For the Year Ended December 31,
	2010	2009	2008
	(Unit amounts in thousands)
Basic weighted average unit outstanding during period:
Common units	68,625	53,496	51,534
Subordinated units	8,163	20,691	20,691
General partner units	488	845	845

Diluted weighted average unit outstanding during period:
Common units	68,625	53,496	51,699
Subordinated units	8,163	20,691	20,691
General partner units	488	845	845

The following table presents the Partnership's basic and diluted loss per unit for the year ended December 31, 2010:



	Total			Common Units			Restricted Common Units			Subordinated Units			General Partner Units
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(22,611	)
Distributions declared	14,943			$	14,658		$	243		$	—		$	42
Assumed loss from continuing operations after distribution to be allocated	(37,554		)	(32,788		)	(633		)	(3,901		)	(232		)
Assumed allocation of loss from continuing operations	(22,611		)	(18,130		)	(390		)	(3,901		)	(190		)
Discontinued operations	17,262			15,071			291			1,793			107
Assumed net loss to be allocated	$	(5,349	)	$	(3,059	)	$	(99	)	$	(2,108	)	$	(83	)

Basic and diluted loss from continuing operations per unit				$	(0.26	)				$	(0.48	)	$	(0.39	)
Basic and diluted discontinued operations per unit				$	0.22					$	0.22		$	0.22
Basic and diluted loss per unit				$	(0.04	)				$	(0.26	)	$	(0.17	)

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The following table presents the Partnership's basic and diluted loss per unit for the year ended December 31, 2009:



	Total			Common Units			Restricted Common Units		Subordinated Units			General Partner Units
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(180,835	)
Distributions declared	5,498			$	5,350		$	64	$	—		$	84
Assumed loss from continuing operations after distribution to be allocated	(186,333		)	(132,851		)	—		(51,385		)	(2,097		)
Assumed allocation of loss from continuing operations	(180,835		)	(127,501		)	64		(51,385		)	(2,013		)
Discontinued operations	9,577			6,828			—		2,641			108
Assumed net loss to be allocated	$	(171,258	)	$	(120,673	)	$	64	$	(48,744	)	$	(1,905	)

Basic and diluted loss from continuing operations per unit				$	(2.38	)			$	(2.48	)	$	(2.38	)
Basic and diluted discontinued operations per unit				$	0.13				$	0.13		$	0.13
Basic and diluted loss per unit				$	(2.26	)			$	(2.36	)	$	(2.26	)

The following table presents the Partnership's basic and diluted income per unit for the year ended December 31, 2008:



	Total			Common Units			Restricted Common Units		Subordinated Units			General Partner Units
	($ in thousands, except for per unit amounts)
Income from continuing operations	$	50,320
Distributions declared	120,256			$	84,000		$	1,152	$	33,727		$	1,377
Assumed loss from continuing operations after distribution to be allocated	(69,936		)	(49,324		)	—		(19,804		)	(808		)
Assumed allocation of income from continuing operations	50,320			34,676			1,152		13,923			569
Discontinued operations	37,200			26,236			—		10,534			430
Assumed net income to be allocated	$	87,520		$	60,912		$	1,152	$	24,457		$	999

Basic and diluted income from continuing operations per unit				$	0.67				$	0.67		$	0.67
Basic and diluted discontinued operations per unit				$	0.51				$	0.51		$	0.51
Basic and diluted income per unit				$	1.18				$	1.18		$	1.18

NOTE 18. OTHER OPERATING EXPENSE

Other operating (income) expense for the year ended December 31, 2009, includes income of $3.6 million due to the recovery of $2.2 million of assets previously written off and the release of $1.4 million of liabilities assumed as part of the Partnership's purchase price allocation for its acquisitions of Escambia Asset Co., LLC and Redman Energy Holdings, L.P. During the period, the Partnership received additional information about collectability of these assets and determined that it no longer had any obligation under these liabilities.

In July 2008, SemGroup, L.P. and certain of its subsidiaries (“SemGroup”) filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. The Partnership historically sold portions of its condensate production from its Texas

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Panhandle and East Texas midstream systems to SemGroup. As a result of the bankruptcy, the Partnership took a $10.7 million bad debt charge during the year ended December 31, 2008, which is included in “Other Operating Expense” in the consolidated statement of operations. In August 2009, the Partnership sold $3.9 million of its outstanding receivables from SemGroup, which represented its 20-day administrative claims under 503(b)(9) of the United States Bankruptcy Code, for which it received a payment of $3.0 million. Due to certain repurchase obligations under the assignment agreement, the Partnership recorded the payment as a current liability within accounts payable as of December 31, 2010 and anticipates maintaining the balance as a liability until it is clear that the repurchase obligations can no longer be triggered.

NOTE 19. DISCONTINUED OPERATIONS

On April 1, 2009, the Partnership sold its producer services business (which was accounted for in its South Texas Segment) by assigning and novating the contracts under this business to a third-party purchaser. The Partnership sold the producer services business to a third-party purchaser as it was a low-margin business that was not core to the Partnership's operations. The Partnership received an initial payment of $0.1 million for the sale of the business. In addition the Partnership received a contingency payment of $0.1 million in October 2009. The Partnership will also continue to receive a monthly payment equivalent to $0.01 per MMbtu on the volume of gas that flows pursuant to the assigned contracts through March 31, 2011. Producer services was a business in which the Partnership would negotiate new well connections on behalf of small producers to pipelines other than its own. During the year ended December 31, 2010, this business generated revenues of $0.1 million and no cost of natural gas and NGLs. During the year ended December 31, 2009, this business generated revenues of $19.2 million and cost of natural gas and NGLs of $18.9 million. During the year ended December 31, 2008, this business generated revenues of $265.1 million and cost of natural gas and NGLs of $263.3 million. For the year ended December 31, 2010, 2009 and 2008, $0.1 million. $0.3 million and $1.8 million, respectively, of revenues minus the cost of natural gas and NGLs have been reported as discontinued operations.

On May 24, 2010, the Partnership completed the sale of its Minerals Business, for which it received net proceeds of approximately $171.6 million in cash after purchase price adjustments made to reflect an effective date of January 1, 2010 for the sale, as established in the agreement governing the sale. The Partnership retained approximately $2.9 million of cash from net revenues received from the Minerals Business after the effective date. The Partnership recorded a gain of $37.7 million on the sale, which is recorded as part of discontinued operations for the year ended December 31, 2010. Further upward or downward adjustments to the purchase price may occur post-closing to reflect customary true-ups. During the six months ended December 31, 2010, the Partnership received payments of $0.3 million related to pre-effective date operations and have recorded this amount as part of discontinued operations for the period. For the year ended December 31, 2010, the Minerals Business generated revenues of $8.9 million and income from operations of $5.5 million. For the year ended December 31, 2009, the Minerals Business generated revenues of $15.7 million and income from operations of $7.8 million. For the year ended December 31, 2008, the Minerals Business generated revenues of $43.0 million and income from operations of $31.7 million. During the years ended December 31, 2010, 2009 and 2008, the Minerals Business incurred state tax expense on discontinued operations of $0.4 million, $0.2 million and $0.4 million, respectively. During the years ended December 31, 2010, 2009 and 2008, the Minerals Business recorded a gain to discontinued operations of $5.5 million, $9.1 million and $35.4 million, respectively, excluding the gain recognized by the Partnership on the sale of the Minerals Business.

Assets and liabilities held for sale represent the assets and liabilities of the Partnership's Minerals Business. As of December 31, 2009, assets held for sale consists of the following: (i) accounts receivable of $3.0 million, (ii) net proved reserves of $55.2 million, (iii) unproved reserves of $64.9 million and (iv) the Partnership's equity investment in Ivory Working Interests, L.P. of $12.0 million. As of December 31, 2009, liabilities held for sale was made up of accounts payable.

NOTE 20. SUBSIDIARY GUARANTORS

In the future, the Partnership may issue registered debt securities guaranteed by its subsidiaries. The Partnership expects that all guarantors would be wholly-owned or available to be pledged and that such guarantees would be joint and several and full and unconditional. In accordance with practices accepted by the SEC, the Partnership has prepared Condensed Consolidating Financial Statements as supplemental information. The following Condensed Consolidating Balance Sheets at December 31, 2010 and 2009, and Condensed Consolidating Statements of Operations and Condensed Consolidating Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008, present financial information for Eagle Rock Energy Partners, L.P. as the Parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors, which are all 100% owned by the Parent, on a stand-alone basis, and the consolidation and elimination entries necessary to arrive at the information for the Partnership on a consolidated basis. The subsidiary guarantors are not restricted from making distributions to the Partnership.

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Condensed Consolidating Balance Sheet
December 31, 2010
(in thousands)	Parent Issuer		Subsidiary Guarantors		Non-guarantor investments		Consolidating Entries			Total
ASSETS:
Accounts receivable – related parties	$	42,667	$	—	$	—	$	(42,667	)	$	—
Assets held for sale	—		8,615		—		—			8,615
Other current assets	5,694		76,548		—		—			82,242
Total property, plant and equipment, net	1,200		1,136,039		—		—			1,137,239
Investment in subsidiaries	1,113,603		—		1,116		(1,114,719		)	—
Total other long-term assets	3,622		117,679		—		—			121,301
Total assets	$	1,166,786	$	1,338,881	$	1,116	$	(1,157,386	)	$	1,349,397
LIABILITIES AND EQUITY:
Accounts payable – related parties	$	—	$	42,667	$	—	$	(42,667	)	$	—
Liabilities held for sale	—		1,705		—		—			1,705
Other current liabilities	31,208		112,126		—		—			143,334
Other long-term liabilities	26,465		68,780		—		—			95,245
Long-term debt	530,000		—		—		—			530,000
Equity	579,113		1,113,603		1,116		(1,114,719		)	579,113
Total liabilities and equity	$	1,166,786	$	1,338,881	$	1,116	$	(1,157,386	)	$	1,349,397



Condensed Consolidating Balance Sheet
December 31, 2009
(in thousands)	Parent Issuer		Subsidiary Guarantors		Non-guarantor investments		Consolidating Entries			Total
ASSETS:
Accounts receivable – related parties	$	87,433	$	—	$	—	$	(87,433	)	$	—
Assets held for sale	—		172,176		—		—			172,176
Other current assets	5,171		89,104		—		—			94,275
Total property, plant and equipment, net	212		1,124,483		—		—			1,124,695
Investment in subsidiaries	1,244,384		—		1,205		(1,245,589		)	—
Total other long-term assets	5,620		138,052		—		—			143,672
Total assets	$	1,342,820	$	1,523,815	$	1,205	$	(1,333,022	)	$	1,534,818
LIABILITIES AND EQUITY:
Accounts payable – related parties	$	—	$	87,433	$	—	$	(87,433	)	$	—
Liabilities held for sale	—		2,094		—		—			2,094
Other current liabilities	42,099		112,479		—		—			154,578
Other long-term liabilities	15,940		77,425		—		—			93,365
Long-term debt	754,383		—		—		—			754,383
Equity	530,398		1,244,384		1,205		(1,245,589		)	530,398
Total liabilities and equity	$	1,342,820	$	1,523,815	$	1,205	$	(1,333,022	)	$	1,534,818

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Condensed Consolidating Statement of Operations
For the year ended December 31, 2010
(in thousands)	Parent Issuer			Subsidiary Guarantors			Non-guarantor investments		Consolidating Entries			Total
Total revenues	$	(8,296	)	$	740,605		$	—	$	—		$	732,309
Cost of natural gas and natural gas liquids	—			468,304			—		—			468,304
Operations and maintenance	—			76,415			—		—			76,415
Taxes other than income	2			12,224			—		—			12,226
General and administrative	3,680			42,095			—		—			45,775
Depreciation, depletion, amortization and impairment	165			112,899			—		—			113,064
(Loss) income from operations	(12,143		)	28,668			—		—			16,525
Interest expense	(15,145		)	(2		)	—		—			(15,147		)
Other non-operating income	8,300			2,755			26		(10,469		)	612
Other non-operating expense	(14,988		)	(22,667		)	—		10,469			(27,186		)
(Loss) income before income taxes	(33,976		)	8,754			26		—			(25,196		)
Income tax provision (benefit)	517			(3,102		)	—		—			(2,585		)
Equity in earnings of subsidiaries	29,144			—			—		(29,144		)	—
(Loss) income from continuing operations	(5,349		)	11,856			26		(29,144		)	(22,611		)
Discontinued operations	—			17,262			—		—			17,262
Net (loss) income	$	(5,349	)	$	29,118		$	26	$	(29,144	)	$	(5,349	)



Condensed Consolidating Statement of Operations
For the year ended December 31, 2009
(in thousands)	Parent Issuer			Subsidiary Guarantors			Non-guarantor investments		Consolidating Entries			Total
Total revenues	$	(37,432	)	$	610,362		$	—	$	—		$	572,930
Cost of natural gas and natural gas liquids	—			470,099			—		—			470,099
Operations and maintenance	—			71,496			—		—			71,496
Taxes other than income	—			10,709			—		—			10,709
General and administrative	2,803			43,016			—		—			45,819
Other operating income	—			(3,552		)	—		—			(3,552		)
Depreciation, depletion, amortization and impairment	—			130,318			—		—			130,318
Loss from operations	(40,235		)	(111,724		)	—		—			(151,959		)
Interest expense	(21,568		)	(23		)	—		—			(21,591		)
Other non-operating income	6,886			2,788			153		(8,706		)	1,121
Other non-operating expense	(5,572		)	(10,551		)	—		8,706			(7,417		)
Income (loss) before income taxes	(60,489		)	(119,510		)	153		—			(179,846		)
Income tax provision (benefit)	1,547			(558		)	—		—			989
Equity in losses of subsidiaries	(109,222		)	—			—		109,222			—
Loss from continuing operations	(171,258		)	(118,952		)	153		109,222			(180,835		)
Discontinued operations	—			9,577			—		—			9,577
Net loss	$	(171,258	)	$	(109,375	)	$	153	$	109,222		$	(171,258	)

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Condensed Consolidating Statement of Operations
For the year ended December 31, 2008
(in thousands)	Parent Issuer			Subsidiary Guarantors			Consolidating Entries			Total
Total revenues	$	8,809		$	1,419,948		$	—		$	1,428,757
Cost of natural gas and natural gas liquids	—			886,019			—			886,019
Operations and maintenance	—			73,203			—			73,203
Taxes other than income	—			18,210			—			18,210
General and administrative	15			45,603			—			45,618
Other operating expense	—			10,699			—			10,699
Depreciation, depletion, amortization and impairment	—			281,466			—			281,466
Income from operations	8,794			104,748			—			113,542
Interest expense	(33,842		)	—			—			(33,842		)
Other non-operating income	5,617			2,318			(5,846		)	2,089
Other non-operating expense	(5,665		)	(33,109		)	5,846			(32,928		)
(Loss) income before income taxes	(25,096		)	73,957			—			48,861
Income tax provision (benefit)	1,087			(2,546		)	—			(1,459		)
Equity in earnings of subsidiaries	113,703			—			(113,703		)	—
Income from continuing operations	87,520			76,503			(113,703		)	50,320
Discontinued operations	—			37,200			—			37,200
Net income	$	87,520		$	113,703		$	(113,703	)	$	87,520

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Condensed Consolidating Statement of Cash Flows
For the year ended December 31, 2010
(in thousands)	Parent Issuer			Subsidiary Guarantors			Non-guarantor investments			Consolidating Entries			Total
Net cash flows provided by operating activities	$	43,756		$	50,318		$	54		$	—		$	94,128
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(1,152		)	(63,345		)	—			—			(64,497		)
Purchase of intangible assets	—			(2,660		)	—			—			(2,660		)
Acquisitions,net of cash acquired	—			(30,984		)	—			—			(30,984		)
Proceeds from sale of asset	171,686			—			—			—			171,686
Contributions to subsidiaries	(27,043		)	—			—			27,043			—
Net cash flows provided by (used in) investing activities	143,491			(96,989		)	—			27,043			73,545
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	90,617			—			—			—			90,617
Repayment of long-term debt	(315,000		)	—			—			—			(315,000		)
Proceeds from derivative contracts	—			1,131			—			—			1,131
Deferred transaction fees	(3,066		)	—			—			—			(3,066		)
Proceeds from Rights Offering	53,893			—			—			—			53,893
Exercise of Warrants	5,351			—			—			—			5,351
Repurchase of common units	(1,177		)	—			—			—			(1,177		)
Contributions from parent	—			27,043			—			(27,043		)	—
Distributions to members and affiliates	(7,195		)	—			—			—			(7,195		)
Net cash flows provided by (used in) financing activities	(176,577		)	28,174			—			(27,043		)	(175,446		)
Net cash flows provided by discontinued operations	—			9,090			—			—			9,090
Net (decrease) increase in cash and cash equivalents	10,670			(9,407		)	54			—			1,317
Cash and cash equivalents at beginning of year	4,922			(2,179		)	(11		)	—			2,732
Cash and cash equivalents at end of year	$	15,592		$	(11,586	)	$	43		$	—		$	4,049

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Condensed Consolidating Statement of Cash Flows
For the year ended December 31, 2009
(in thousands)	Parent Issuer			Subsidiary Guarantors			Non-guarantor Investments			Consolidating Entries		Total
Net cash flows provided by operating activities	$	57,933		$	19,306		$	(11	)	$	—	$	77,228
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(84		)	(36,050		)	—			—		(36,134		)
Purchase of intangible assets	—			(1,626		)	—			—		(1,626		)
Proceeds from sale of asset	—			476			—			—		476
Net cash flows used in investing activities	(84		)	(37,200		)	—			—		(37,284		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	131,000			—			—			—		131,000
Repayment of long-term debt	(176,000		)	—			—			—		(176,000		)
Proceeds from derivative contracts	—			8,939			—			—		8,939
Deferred transactions fees	(1,480		)	—			—			—		(1,480		)
Repurchase of common units	(64		)	—			—			—		(64		)
Distributions to members and affiliates	(35,655		)	—			—			—		(35,655		)
Net cash flows (used in) provided by financing activities	(82,199		)	8,939			—			—		(73,260		)
Net cash flows provided by discontinued operations	—			18,132			—			—		18,132
Net (decrease) increase in cash and cash equivalents	(24,350		)	9,177			(11		)	—		(15,184		)
Cash and cash equivalents at beginning of year	29,272			(11,356		)	—			—		17,916
Cash and cash equivalents at end of year	$	4,922		$	(2,179	)	$	(11	)	$	—	$	2,732



Condensed Consolidating Statement of Cash Flows
For the year ended December 31, 2008
(in thousands)	Parent Issuer			Subsidiary Guarantors			Non-guarantor Investments		Consolidating Entries			Total
Net cash flows provided by operating activities	$	106,073		$	32,712		$	—	$	—		$	138,785
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(128		)	(66,613		)	—		—			(66,741		)
Purchase of intangible assets	—			(2,975		)	—		—			(2,975		)
Investment in partnerships	—			—			—		—			—
Acquisitions, net of cash acquired	(857		)	(261,388		)	—		—			(262,245		)
Proceeds from sale of asset	—			1,294			—		—			1,294
Contributions to subsidiaries	(261,981		)	—			—		261,981			—
Net cash flows used in investing activities	(262,966		)	(329,682		)	—		261,981			(330,667		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	432,128			—			—		—			432,128
Repayment of long-term debt	(199,814		)	—			—		—			(199,814		)
Proceeds from derivative contracts	—			(11,063		)	—		—			(11,063		)
Payment of debt issuance costs	(789		)	—			—		—			(789		)
Contributions from parent	—			261,981			—		(261,981		)	—
Distributions to members and affiliates	(117,646		)	—			—		—			(117,646		)
Net cash flows provided by financing activities	113,879			250,918			—		(261,981		)	102,816
Net cash flows provided by discontinued operations	—			38,430			—		—			38,430
Net decrease in cash and cash equivalents	(43,014		)	(7,622		)	—		—			(50,636		)
Cash and cash equivalents at beginning of year	72,286			(3,734		)	—		—			68,552
Cash and cash equivalents at end of year	$	29,272		$	(11,356	)	$	—	$	—		$	17,916

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NOTE 21. SUBSEQUENT EVENTS

In February 2011, the Partnership classified its Wildhorse Gathering System (which was accounted for in its South Texas Segment) and thus has retrospectively classified the assets and liabilities as held for sale and the operations as discontinued. As of December 31, 2010, liabilities held for sale consisted of accounts payable, and assets held for sale consisted of the following: (i) $2.1 million of accounts receivable, (ii) $6.2 million of pipelines and equipment, net and $0.3 million of intangible assets, net. As of December 31, 2009, liabilities held for sale consisted of accounts payable, and assets held for sale consisted of the following: (i) $2.3 million of accounts receivable, (ii) $31.0 million of pipelines and equipment, net and $3.6 million of intangible assets, net.

During the year ended December 31, 2010, the Wildhorse Gathering System generated revenues of $26.1 million and an operating loss of $25.9 million, which includes an impairment charge of $26.2 million. During the year ended December 31, 2009, the Wildhorse Gathering System generated revenues of $21.8 million and operating income of $0.2 million. During the year ended December 31, 2008, the Wildhorse Gathering System generated revenues of $6.5 million and operating income of less than $0.1 million.

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NOTE 22. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil and Natural Gas Reserves

Users of this information should be aware that the process of estimating quantities of proved oil and natural gas reserves is very complex, and requires significant subjective decisions in the evaluation of the available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and changing operating and market conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although reasonable effort is made to ensure the reported reserve estimates represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. Reserve data represent estimates only and should not be construed as being exact. Moreover, the Standardized Measure of Oil and Gas (“SMOG”) should not be construed as the current market value of the proved oil and natural gas reserves or the costs that would be incurred to obtain equivalent reserves. A market value determination would include many additional factors including (a) anticipated future changes in natural gas and crude oil prices, production and development costs, (b) an allowance for return on investment, (c) the value of additional reserves, not considered proved at present, which may be recovered as a result of further exploration and development activities, and (d) other business risks.

Recent Developments

On May 24, 2010, the Partnership sold its Minerals Business (see Notes 1, 13 and 19). Financial information, including reserve amounts and changes, related to the Minerals Business have been retrospectively adjusted to be reflected as assets and liabilities held-for-sale and discontinued operations, as discussed further in Note 1.

Proved Reserves Summary

The following table illustrates the Partnership's estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by Cawley, Gillespie and Associates. Oil and natural gas liquids prices for 2010 are based on a prior twelve month average West Texas Intermediate spot price of $79.63 per barrel and are adjusted for quality, transportation fees, and regional price differentials. Natural gas prices for 2010 are based on a prior 12 month average Henry Hub spot market price of $4.37 per MMBtu and are adjusted for energy content, transportation fees, and regional price differentials. All prices are held constant in accordance with SEC guidelines. All of the Partnership's reserves are located in the United States.

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	Proved Reserves - 2008
	Oil (MBbls)		Gas (MMcf)		Natural Gas Liquids (MBbls)
Proved reserves, January 1, 2008	10,081		44,643		5,743
Extensions and discoveries	139		2,639		45
Purchase of minerals in place	3,513		8,157		1,432
Production	(832	)	(4,123	)	(482	)
Revision of previous estimates	(2,864	)	(6,182	)	(1,099	)
Changes from discontinued operations	(31	)	(546	)	—
Proved reserves, December 31, 2008	10,006		44,588		5,639

Proved developed reserves - continuing operations, December 31, 2008	6,425		31,286		4,883
Proved developed reserves - discontiued operations, December 31, 2008	2,775		4,871		—
Proved undeveloped reserves - continuing operations, December 31, 2008	806		8,431		756

	Proved Reserves - 2009
	Oil (MBbls)		Gas (MMcf)		Natural Gas Liquids (MBbls)
Proved reserves, January 1, 2009	10,006		44,588		5,639
Extensions and discoveries	298		1,782		241
Purchase of minerals in place	18		—		—
Production	(829	)	(6,647	)	(493	)
Revision of previous estimates	797		(1,030	)	718
Changes from discontinued operations	162		(53	)	—
Proved reserves, December 31, 2009	10,452		38,640		6,105

Proved developed reserves - continuing operations, December 31, 2009	7,121		26,263		5,410
Proved developed reserves - discontinued operations, December 31, 2009	2,937		4,819		—
Proved undeveloped reserves - continuing operations, December 31, 2009	394		7,558		695

	Proved Reserves - 2010
	Oil (MBbls)		Gas (MMcf)		Natural Gas Liquids (MBbls)
Proved reserves, January 1, 2010	10,452		38,640		6,105
Extensions and discoveries	7		3,930		—
Purchase of minerals in place	216		555		102
Production	(808	)	(3,514	)	(437	)
Revision of previous estimates	1,766		3,590		406
Change from discontinued operations	(54	)	(342	)	—
Sale of minerals in place	(2,883	)	(4,477	)	—
Proved reserves, December 31, 2010	8,696		38,382		6,176

Proved developed reserves - continuing operations, December 31, 2010	8,299		29,686		5,758
Proved undeveloped reserves - continuing operations, December 31, 2010	397		8,696		418

In 2009, the Partnership experienced significant revisions to its proved reserves. The Partnership revised its oil and natural gas liquids reserves upwards due to changes in production forecasts and engineering factors such as condensate and natural gas liquids yields. The Partnership also revised its natural gas reserves downward due to technical factors (such as increased shrinkage related to fuel usage and plant processing) and economic factors. Revisions due to economic factors are due to the relatively low prior twelve

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month average natural gas price that was used to determine the reserves and higher operating cost estimates in its Permian Basin operations. The Partnership also experienced negative oil and natural gas revisions in its Permian Basin operations, particularly in its lease in the Ward Estes and surrounding fields. These revisions were primarily due to poorer than expected performance in recent San Andres drilling and recompletions, changes to decline curves to reflect recent production performance, and the upward adjustment of operating costs which rendered several leases non-commercial. The Partnership is working to improve its cost structure on these leases and is optimistic that some of these negative reserves may be reversed in the future.

Proved Reserves Summary - Equity Method Entities

As part of the sale of the Minerals Business, the Partnership sold it 13.2% limited partner interest in IWI, which it had accounted for under the equity method. IWI is managed by Black Stone and is not required to make public disclosures about its proved reserves and the agreements that governed the Partnership's rights as limited partners in IWI do not require Black Stone to provide us with detailed reserve data of the type that would be sufficient to make all of the disclosures that the SEC now requires with respect to proved reserves of equity method entities. As a result, the Partnership lacks the date needed to prepare the Supplemental Oil and Gas Disclosures for its equity interests.

Capitalized Costs Relating to Oil and Natural Gas Producing Activities

The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization at December 31, 2010, 2009 and 2008:



	As of December 31, 2010			As of December 31, 2009			As of December 31, 2008
($ in thousands)
Evaluated properties	$	471,781		$	435,789		$	437,865
Unevaluated properties—excluded from depletion	1,304			7,264			7,599
Gross oil and gas properties	473,085			443,053			445,464
Accumulated depreciation, depletion, amortization	(125,832		)	(95,135		)	(60,833		)
Net oil and gas properties	347,253			347,918			384,631
Net oil and gas properties held-for-sale	—			120,149			127,807
Total net oil and gas properties	$	347,253		$	468,067		$	512,438

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

Costs incurred in property acquisition, exploration and development activities were as follows for the years ended December 31, 2010, 2009 and 2008:



	Years Ended December 31,
	2010		2009		2008
($ in thousands)
Property acquisition costs, proved	$	4,222	$	512	$	110,747
Property acquisition costs, unproved	259		20		7,597
Exploration and extension well costs	—		1		1,610
Development costs	25,922		8,137		12,294
Total costs	$	30,403	$	8,670	$	132,248

The Partnership's exploration and extension well costs are primarily related to low risk drilling around its existing fields.

No costs were incurred associated with the Minerals Business which is classified as Discontinued Operations on the Consolidated Statements of Operations and Assets Held for Sale on the Consolidated Balances sheet.

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Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following information has been developed utilizing authoritative guidance procedures and is based on oil and natural gas reserves estimated by the Partnership's independent reserves engineer. It can be used for some comparisons, but should not be the only method used to evaluate the Partnership or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flow be viewed as representative of the current value of the Partnership.

The Partnership believes that the following factors should be taken into account when reviewing the following information:


•	future costs and selling prices will probably differ from those required to be used in these calculations;


•	due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations; and


•	a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues.

Under the Standardized Measure, future cash inflows were estimated by applying year-end oil and natural gas prices to the estimated future production of year-end proved reserves. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor.

In the Partnership's 2009 Standardized Measure calculations it included the future revenues that would be associated with the sales of sulfur; however the cash flows only partially offset the costs of transporting and marketing the sulfur. As such, it is a net negative cash flow in the Standardized Measure. Also, the Partnership included the expected impact of the retained revenue interests as a revenue reduction.

The recent changes to the disclosure rules relating to proved reserves require the inclusion of the Partnership's share of the reserves associated with entities that it reports under the equity method. As discussed above, the Partnership sold these interests as part of the sale of its Minerals Business. As the Partnership did not have the right and has been unable to gather the data needed to include these reserves in its Standardized Measure calculations, the tables below reflect only the reserves for the Partnership's consolidate entities.

The Standardized Measure is as follows as of December 31, 2010, 2009 and 2008:



	As of December 31, 2010			As of December 31, 2009			As of December 31, 2008
($ in thousands)
Future cash inflows	$	1,027,417		$	650,564		$	654,901
Future production costs	(336,080		)	(307,605		)	(316,920		)
Future development costs	(97,745		)	(72,577		)	(60,189		)
Future net cash flows before income taxes	593,592			270,382			277,792
Future income tax (expense) benefit	(1,005		)	554			1,992
Future net cash flows before 10% discount	592,587			270,936			279,784
10% annual discount for estimated timing of cash flows	(258,594		)	(111,321		)	(116,773		)
Standardized measure of discounted future net cash flows related to continuing operations	333,993			159,615			163,011
Standardized measure of discounted future net cash flows related to discontinued operations	—			55,038			46,733
Total standardized measure of discounted future net cash flows	$	333,993		$	214,653		$	209,744

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Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for the Partnership's proved oil and natural gas reserves for the years ended December 31, 2010, 2009 and 2008:



	Years Ended December 31,
	2010			2009			2008
($ in thousands)
Beginning of year	$	214,653		$	209,744		$	556,960
Sale of oil and gas produced, net of production costs	(54,353		)	(40,824		)	(99,968		)
Net changes in prices and production costs	147,003			6,146			(257,840		)
Extensions, discoveries and improved recovery, less related costs	5,492			7,859			5,603
Previously estimated development costs incurred during the period	25,922			(8,137		)	(12,294		)
Net changes in future development costs	(30,033		)	8,733			11,766
Revisions of previous quantity estimates	74,864			9,404			(50,144		)
Purchases of property	7,342			347			45,239
Sales of property	(70,845		)	—			—
Accretion of discount	14,528			14,777			42,524
Net changes in income taxes	(793		)	(908		)	1,069
Other	(15,594		)	(793		)	7,860
Change from discontinued operations	15,807			8,305			(41,031		)
End of year	$	333,993		$	214,653		$	209,744

Results of Operations

The following are the results of operations for the Partnership's oil and natural gas producing activities for the years ended December 31, 2010, 2009 and 2008:



Year Ended December 31,	2010		2009			2008
($ in thousands)
Revenues	$	87,211	$	67,159		$	138,082
Costs and expenses:
Production costs	32,858		26,335			38,114
General and administrative	6,349		5,151			4,282
Depreciation, depletion, and amortization	30,424		34,009			44,997
Impairment	3,536		8,114			107,017
Total costs and expenses	73,167		73,609			$	194,410
Results of continuing operations	14,044		(6,450		)	(56,328		)
Discontinued operations	5,262		5,686			17,642
Total result of operations	$	19,306	$	(764	)	$	(38,686	)

* * * *

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EAGLE ROCK ENERGY PARTNERS L P - FORM 8-K - EX-99.1 - EXHIBIT 99.1 - May 17, 2011

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EAGLE ROCK ENERGY PARTNERS L P Reports