UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2011

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File No. 001-33016

EAGLE ROCK ENERGY PARTNERS, L.P.

(Exact Name of Registrant as Specified in Its Charter)

Delaware	68-0629883
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification Number)

1415 Louisiana Street, Suite 2700

Houston, Texas 77002

 (Address of principal executive offices, including zip code)

(281) 408-1200

(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes  x   No  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one): 

Large accelerated filer  o	Accelerated filer  x
Non-accelerated filer  o	Smaller Reporting Company  o
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  o    No  x

The issuer had 121,763,523 common units outstanding as of August 1, 2011.

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements	2
	Unaudited Condensed Consolidated Balance Sheets as of June 30, 2011 and December 31, 2010	2
	Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2011 and 2010	3
	Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2011 and 2010	5
	Unaudited Condensed Consolidated Statement of Member's Equity for the six months ended June 30, 2011	6
	Notes to the Unaudited Condensed Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	65
Item 4.	Controls and Procedures	67
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	68
Item 1A.	Risk Factors	68
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	70
Item 3.	Defaults Upon Senior Securities	70
Item 4.	[Removed and Reserved]	70
Item 5.	Other Information	70
Item 6.	Exhibits	71

1

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

($ in thousands)

	June 30, 2011		December 31, 2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	6,825	$	4,049
Accounts receivable(a)	94,629		75,695
Risk management assets	1,976		—
Prepayments and other current assets	9,031		2,498
Assets held for sale	—		8,615
Total current assets	112,461		90,857
PROPERTY, PLANT AND EQUIPMENT — Net	1,705,056		1,137,239
INTANGIBLE ASSETS — Net	112,365		113,634
DEFERRED TAX ASSET	1,739		1,969
RISK MANAGEMENT ASSETS	2,936		1,075
OTHER ASSETS	18,879		4,623
TOTAL	$	1,953,436	$	1,349,397
LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	130,006	$	91,886
Due to affiliate	44		56
Accrued liabilities	12,537		10,940
Taxes payable	598		1,102
Risk management liabilities	30,371		39,350
Liabilities held for sale	—		1,705
Total current liabilities	173,556		145,039
LONG-TERM DEBT	745,855		530,000
ASSET RETIREMENT OBLIGATIONS	32,973		24,711
DEFERRED TAX LIABILITY	39,994		38,662
RISK MANAGEMENT LIABILITIES	20,697		31,005
OTHER LONG TERM LIABILITIES	2,307		867
COMMITMENTS AND CONTINGENCIES (Note 13)
MEMBERS' EQUITY (b)	938,054		579,113
TOTAL	$	1,953,436	$	1,349,397

________________________ 

(a) Net of allowance for bad debt of $1,345 as of June 30, 2011 and $4,496 as of December 31, 2010.

(b) 119,879,395 and 83,425,378 common units were issued and outstanding as of June 30, 2011 and December 31, 2010, respectively. These amounts do not include unvested restricted common units granted under the Partnership's long-term incentive plan of 1,821,328 and 1,744,454 as of June 30, 2011 and December 31, 2010, respectively.

See notes to unaudited condensed consolidated financial statements.  

2

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

($ in thousands)

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
REVENUE:
Natural gas, natural gas liquids, oil, condensate and sulfur sales	$	265,317		$	164,972		$	468,372		$	356,973
Gathering, compression, processing and treating fees	12,304			16,230			25,549			28,713
Commodity risk management gains (losses)	34,338			35,592			(26,107		)	46,387
Other revenue	(244		)	(251		)	1,265			(215		)
Total revenue	311,715			216,543			469,079			431,858
COSTS AND EXPENSES:
Cost of natural gas, natural gas liquids, and condensate	172,674			108,643			319,993			246,545
Operations and maintenance	21,951			19,926			41,426			38,797
Taxes other than income	5,189			2,806			8,505			6,340
General and administrative	15,902			12,806			27,678			25,817
Other operating income	(2,893		)	—			(2,893		)	—
Impairment	4,560			3,130			4,884			3,130
Depreciation, depletion and amortization	31,576			27,469			55,274			54,913
Total costs and expenses	248,959			174,780			454,867			375,542
OPERATING INCOME	62,756			41,763			14,212			56,316
OTHER INCOME (EXPENSE):
Interest income	3			173			6			175
Interest expense	(6,311		)	(4,384		)	(9,535		)	(8,798		)
Interest rate risk management losses	(1,643		)	(9,306		)	(4,305		)	(19,018		)
Other (expense) income	(114		)	(21		)	(164		)	78
Total other (expense) income	(8,065		)	(13,538		)	(13,998		)	(27,563		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	54,691			28,225			214			28,753
INCOME TAX (BENEFIT) PROVISION	(691		)	(425		)	(733		)	274
INCOME FROM CONTINUING OPERATIONS	55,382			28,650			947			28,479
DISCONTINUED OPERATIONS, NET OF TAX	(311		)	39,493			407			43,645
NET INCOME	$	55,071		$	68,143		$	1,354		$	72,124

 See notes to unaudited condensed consolidated financial statements.  

3

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (continued)

(in thousands, except per unit amounts)

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
NET INCOME PER COMMON UNIT—BASIC AND DILUTED:
Income from Continuing Operations
Common units - Basic	$	0.50	$	0.41	$	—	$	0.40
Common units - Diluted	$	0.47	$	0.41	$	—	$	0.40
Subordinated units - Basic and diluted			$	0.38			$	0.35
General partner units - Basic and diluted			$	0.41			$	0.40
Discontinued Operations
Common units - Basic	$	—	$	0.56	$	—	$	0.59
Common units - Diluted	$	—	$	0.56	$	—	$	0.59
Subordinated units - Basic and diluted			$	0.56			$	0.59
General partner units - Basic and diluted			$	0.56			$	0.59
Net Income
Common units - Basic	$	0.50	$	0.96	$	0.01	$	0.98
Common units - Diluted	$	0.47	$	0.96	$	0.01	$	0.98
Subordinated units - Basic and diluted			$	0.94			$	0.93
General partner units - Basic and diluted			$	0.96			$	0.98
Weighted Average Units Outstanding (in thousands)
Common units - Basic	108,117		56,597		96,130		55,344
Common units - Diluted	115,897		56,808		103,950		55,515
Subordinated units - Basic and diluted			12,278				16,683
General partner units - Basic and diluted			845				845

See notes to unaudited condensed consolidated financial statements.  

4

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

($ in thousands)

	Six Months Ended June 30,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	1,354		$	72,124
Adjustments to reconcile net income to net cash provided by operating activities:
Discontinued operations	(407		)	(43,645		)
Depreciation, depletion and amortization	55,274			54,913
Impairment	4,884			3,130
Amortization of debt discount	18			—
Amortization of debt issuance costs	601			820
Write-off of debt issuance costs	427			—
Equity in earnings of unconsolidated affiliates	11			—
Distribution from unconsolidated affiliates—return on investment	57			67
Reclassing financing derivative settlements	(2,443		)	(628		)
Equity-based compensation	1,934			3,358
Loss (gain) of sale of assets	137			(19		)
Other operating income	(2,893		)	—
Other	(374		)	801
Changes in assets and liabilities—net of acquisitions:
Accounts receivable	(2,215		)	9,346
Prepayments and other current assets	(3,268		)	(635		)
Risk management activities	(19,769		)	(45,707		)
Accounts payable	(8,701		)	(6,026		)
Due to affiliates	—			(3,552		)
Accrued liabilities	1,681			(904		)
Other assets	(17		)	(84		)
Other current liabilities	(598		)	(697		)
Net cash provided by operating activities	25,693			42,662
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(31,195		)	(23,910		)
Acquisitions, net of cash acquired	(220,326		)	—
Proceeds from sale of assets	6,093			171,664
Purchase of intangible assets	(1,315		)	(968		)
Net cash (used in) provided by investing activities	(246,743		)	146,786
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	709,329			36,000
Repayment of long-term debt	(791,329		)	(225,000		)
Proceeds from senior notes	297,837			—
Payment of debt issuance costs	(13,802		)	—
Proceeds from derivative contracts	2,443			628
Exercise of warrants	45,897			—
Payment of transaction costs	—			(2,557		)
Repurchase of common units	(119		)	(219		)
Distributions to members and affiliates	(26,250		)	(3,024		)
Net cash provided by (used in) financing activities	224,006			(194,172		)
CASH FLOWS FROM DISCONTINUED OPERATIONS:
Operating activities	(180		)	8,417
Investing activities	—			(104		)
Net cash (used in) provided by discontinued operations	(180		)	8,313
NET INCREASE IN CASH AND CASH EQUIVALENTS	2,776			3,589
CASH AND CASH EQUIVALENTS—Beginning of period	4,049			2,732
CASH AND CASH EQUIVALENTS—End of period	$	6,825		$	6,321
NONCASH INVESTING AND FINANCING ACTIVITIES:
Units issued for acquisitions	$	336,125		$	2,089
Issuance of common units for transaction fee	$	—		$	29,000
Transaction fees, not paid	$	1,234		$	478
Investments in property, plant and equipment, not paid	$	20,653		$	8,429
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid—net of amounts capitalized	$	11,225		$	8,325
Cash paid for taxes	$	984		$	1,437

See notes to unaudited condensed consolidated financial statements.

5

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF MEMBERS’ EQUITY

($ in thousands, except unit amounts)

	Number of Common Units		Common Units
BALANCE — January 1, 2011	83,425,378		$	579,113
Net income	—		1,354
Distributions	—		(26,250		)
Vesting of restricted units	62,071		—
Exercised warrants	7,649,544		45,897
Repurchase of common units	(10,772	)	(119		)
Equity based compensation	—		1,934
Units issued for acquisitions	28,753,174		336,125
BALANCE — June 30, 2011	119,879,395		$	938,054

 See notes to unaudited condensed consolidated financial statements.  

6

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 are wholly-owned subsidiaries of Eagle Rock Energy. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements presented in the Partnership's annual report on Form 10-K for the year ended December 31, 2010. That report contains a more comprehensive summary of the Partnership's major accounting policies. In the opinion of management, the accompanying unaudited condensed consolidated financial statements contain all of the appropriate adjustments, all of which are normally recurring adjustments unless otherwise noted, considered necessary to present fairly the financial position of the Partnership and its consolidated subsidiaries and the results of operations and cash flows for the respective periods. Operating results for the three and six months endedJune 30, 2011 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2011.

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 or natural gas liquids ("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 in the Partnership's pipelines or third party pipelines, is treated to remove contaminants and conditioned or processed into marketable natural gas and NGLs. 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.  The Partnership reports its Upstream Business through one segment.

Other Reclassifications—Certain prior period financial statement balances have been reclassified to conform to the current year presentation. These reclassifications had no effect on the recorded net income and are not significant.

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 ("U.S. GAAP"). 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 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.

The preparation of financial statements in conformity with U.S. GAAP 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 and derivative valuations. 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.

The Partnership has provided a discussion of significant accounting policies in its annual report on Form 10-K for the year ended December 31, 2010. Certain items from that discussion are repeated or updated below as necessary to assist in understanding these financial statements.

7

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 is found to have 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

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 negative revision or unfavorable 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 each of the three and six months endedJune 30, 2011 and 2010, the Partnership did not incur any impairment charges related to proved properties. 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. In the first quarter of 2011, the Partnership incurred $0.3 million of impairment charges related to certain drilling locations in its unproved properties which the Partnership no longer intends to develop based on the performance of offsetting wells. During each of the three months endedJune 30, 2011 and 2010, the Partnership did not incur any impairment charges related to unproved properties.

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 changes 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

8

• 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 three and six months endedJune 30, 2011, the Partnership recorded an impairment charge of $4.6 million in its Texas Panhandle Segment to fully write-down its idle Turkey Creek plant. The Partnership determined that the components of its Turkey Creek plant could not be used elsewhere within the business and thus the Partnership decided to remove all above ground equipment and structures.

Other Significant Accounting Policies

Transportation and Exchange Imbalances—In the course of transporting natural gas and NGLs for others, the Partnership may receive for redelivery different quantities of natural gas or NGLs 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 NGLs 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 June 30, 2011, the Partnership had imbalance receivables totaling $0.8 million and imbalance payables totaling $1.9 million. 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. 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.

Inventory—Inventory is stated at the lower of cost or market, with cost being determined using the average cost method. At June 30, 2011 and December 31, 2010, the Partnership had $3.1 million and $0.5 million, respectively, of crude oil finished goods inventory which is recorded as part of Other Current Assets within the unaudited condensed consolidated balance sheet.

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, condensate and sulfur; 

• 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, condensate and sulfur 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 in the period when the services are provided.

For gathering and processing services, the Partnership either receives fees or commodities from natural gas producers under various types of contracts, including, percentage-of-proceeds, fixed recovery and percent-of-index arrangements. The Partnership also recognizes fee-based service revenues for services such as transportation, compression and processing.

The Partnership's Upstream Segment recognizes revenues based on the amount of natural gas sold to purchasers. The volumes of natural gas sold may differ from the volumes to which the Partnership is entitled based on its interests in the properties. Differences between volumes sold and volumes based on entitlements create natural gas imbalances. Material imbalances are reflected as adjustments to reported natural gas reserves and future cash flows.  As of June 30, 2011 and December 31, 2010, the Partnership's Upstream Segment had an imbalance receivable balance of $1.3 million and $0.5 million, respectively, and it had a long-term payable balance of $1.4 million as of June 30, 2011.

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 sale contracts, when appropriately designated, are not subject to the guidance. Normal purchases and sales are contracts which provide for the purchase or sale of something, other than a financial

9

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. The terms of these contracts generally preclude unplanned netting. The Partnership uses financial instruments such as swaps, collars 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 and specifies a hierarchy of valuation techniques based on the inputs used to measure fair value. See Note 12 for additional information regarding the Partnership's assets and liabilities carried at fair value.

NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS

In September 2009, the Financial Accounting Standards Board ("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 did not have a material impact on the Partnership's 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, which was adopted by the Partnership on January 1, 2011 (see Note 12).

In May 2011, the FASB issued additional guidance intended to result in convergence between U.S. GAAP and International Financial Reporting Standards (“IFRS”) requirements for measurement of and disclosures about fair value. The amendments are not expected to have a significant impact on companies applying U.S. GAAP. Key provisions of the amendments include: a prohibition on grouping financial instruments for purposes of determining fair value, except when an entity manages market and credit risks on the basis of the entity’s net exposure to the group; an extension of the prohibition against the use of a blockage factor to all fair value measurements (that prohibition currently applies only to financial instruments with quoted prices in active markets); and a requirement that for recurring Level 3 fair value measurements, entities disclose quantitative information about unobservable inputs, a description of the valuation process used and qualitative details about the sensitivity of the measurements. In addition, for items not carried at fair value but for which fair value is disclosed, entities will be required to disclose the level within the fair value hierarchy that applies to the fair value measurement disclosed. This guidance is effective for interim and annual periods beginning after December 15, 2011. The adoption of this guidance is not expected to have a significant impact on the Partnership’s fair value measurements, financial condition, results of operations or cash flows.

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NOTE 4. ACQUISITIONS

Acquisition of CC Energy II L.L.C.

On May 3, 2011, the Partnership completed the acquisition of all of the outstanding membership interests of CC Energy II L.L.C (together with its subsidiaries, "Crow Creek Energy"), a portfolio company of Natural Gas Partners, VIII, L.P. ("NGP VIII") (the "Crow Creek Acquisition"). Crow Creek Energy has oil and natural gas properties located in multiple basins across Oklahoma, north Texas and Arkansas (the "Mid-Continent" properties) and provides the Partnership with an extensive inventory of low-risk development prospects in established plays such as the Golden Trend Field and developing plays such as the Cana Shale. The aggregate purchase price of $563.7 million has been calculated as follows (in thousands, except unit and per unit amounts):

Number of Partnership Common Units Issued	28,753,174
Closing common unit price on May 3, 2011	$	11.69
Value of common units issued	$	336,125
Crow Creek Energy outstanding debt assumed	212,638
Cash	14,945
Total purchase price	$	563,708

The number of common units of the Partnership issued was determined based on the value of the equity to be issued to the sellers of $301.9 million divided by $10.50, the ceiling price of the agreed upon range in the contribution agreement between the Partnership and Crow Creek Energy. The cash portion of the acquisition consideration and the repayment of Crow Creek Energy’s outstanding debt were funded through borrowings under the Partnership’s revolving credit facility. In addition, the Partnership incurred $2.3 million of acquisition related expenses, which are included within general and administrative expenses for the three and six months ended June 30, 2011.

The following presents the preliminary purchase price allocation for the Crow Creek Energy assets, based on preliminary estimates of fair value (in thousands):

Current assets	$	25,329
Oil and gas properties	575,637
Property, plant and equipment	4,463
Intangible assets	3,192
Other assets	450
Derivatives	3,355
Current liabilities	(37,032		)
Asset retirement obligations	(7,483		)
Deferred tax liability	(2,763		)
Other liabilities	(1,440		)
	$	563,708

As of June 30, 2011, the purchase price and the allocation of the purchase price are considered preliminary due to the pending completion of certain final closing purchase price adjustments and the final calculation of the asset retirement obligations and the deferred tax liability.

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The amounts of Crow Creek Energy's revenue and net income included within the Partnership's condensed consolidated statement of operations for the six months ended June 30, 2011, and the pro forma revenue and net income of the combined entity had the acquisition date been January 1, 2010, are as follows:

	Revenue		Net Income		Net Income Per Diluted Common Unit
	($ in thousands)
Actual from May 3, 2011 to June 30, 2011	$	23,589	$	15,651
Supplemental pro forma from January 1, 2011 to June 30, 2011	$	490,135	$	6,813	$	0.05
Supplemental pro forma from January 1, 2010 to June 30, 2010	$	476,651	$	97,132	$	0.92

NOTE 5. PROPERTY PLANT AND EQUIPMENT

Fixed assets consisted of the following:

	June 30, 2011			December 31, 2010
	($ in thousands)
Land	$	2,607		$	2,629
Plant	277,250			251,436
Gathering and pipeline	670,228			666,163
Equipment and machinery	28,478			26,408
Vehicles and transportation equipment	4,256			4,251
Office equipment, furniture, and fixtures	1,121			1,120
Computer equipment	8,502			8,486
Corporate	126			126
Linefill	4,269			4,269
Proved properties	971,447			471,781
Unproved properties	106,364			1,304
Construction in progress	21,113			42,416
	2,095,761			1,480,389
Less: accumulated depreciation, depletion and amortization	(390,705		)	(343,150		)
Net property plant and equipment	$	1,705,056		$	1,137,239

Depreciation expense for the three and six months endedJune 30, 2011 and 2010 was approximately $13.5 million, $27.1 million, $12.9 million and $26.4 million, respectively. Depletion expense for the three and six months endedJune 30, 2011 and 2010 was approximately $15.2 million, $22.3 million, $8.8 million and $17.0 million, respectively. During the three and six months endedJune 30, 2011, the Partnership recorded impairment charges of $4.6 million and $4.9 million, respectively, of which $0.3 million related to unproved properties during the six months ended June 30, 2011 and $4.6 million related to plant assets in its Panhandle Segment during the three and six months ended June 30, 2011. During the three and six months endedJune 30, 2010, the Partnership recorded impairment charges of $2.0 million and $0.6 million, respectively, to its pipeline and plant assets due to the loss of a significant gathering contract in its South Texas Segment.  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 three and six months endedJune 30, 2011 and 2010, the Partnership capitalized interest costs of $0.1 million for each of the periods.

NOTE 6. 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

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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.

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

	Six Months Ended June 30,
	2011			2010
	($ in thousands)
Asset retirement obligations—January 1	$	24,711		$	19,829
Additional liabilities	54			—
Liabilities settled	(148		)	(261		)
Additional liability related to acquisitions	7,528			—
Accretion expense	828			1,062
Asset retirement obligations—June 30	$	32,973		$	20,630

NOTE 7. INTANGIBLE ASSETS

Intangible assets consist of rights-of-way and easements and acquired customer contracts, which the Partnership amortizes over the term of the agreement or estimated useful life. The Partnership recorded impairment charges of $0.5 million related to rights-of-way in the three and six months endedJune 30, 2010. The Partnership did not incur any impairment charges during the three and six months endedJune 30, 2011. Amortization expense was approximately $2.9 million, $5.9 million, $5.8 million and $11.5 million for the three and six months endedJune 30, 2011 and 2010, respectively. Estimated aggregate amortization expense for the remainder of 2011 and each of the four succeeding years is as follows: 2011—$6.1 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 June 30, 2011 and December 31, 2010): 

	June 30, 2011			December 31, 2010
	($ in thousands)
Rights-of-way and easements—at cost	$	96,057		$	91,490
Less: accumulated amortization	(23,104		)	(20,552		)
Contracts	121,387			122,601
Less: accumulated amortization	(81,975		)	(79,905		)
Net intangible assets	$	112,365		$	113,634

The amortization period for the Partnership's rights-of-way and easements is 20 years. The amortization period for contracts ranges from 5 to 20 years and is approximately 8 years on average as of June 30, 2011.  

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NOTE 8. LONG-TERM DEBT

Long-term debt consisted of the following:

	June 30, 2011			December 31, 2010
	($ in thousands)
Revolving credit facility:	$	448,000		$	530,000
Senior Notes:				—
8 3/8% senior notes due 2019	300,000			—
Unamortized bond discount-senior notes due 2019	(2,145		)	—
Total senior notes	297,855			—
Total long-term debt	$	745,855		$	530,000

Revolving Credit Facility

On June 22, 2011, the Partnership entered into an Amended and Restated Credit Agreement (the “Credit Agreement”) with Wells Fargo Bank, National Association, as administrative agent and swingline lender, Bank of America, N.A. and The Royal Bank of Scotland plc, as co-syndication agents, BNP Paribas, as documentation agent, and the other lenders who are parties to the Credit Agreement. The Credit Agreement amended and restated the Partnership’s prior $880 million Credit Agreement (the “Prior Credit Agreement”). Upon the effectiveness of the Credit Agreement, all commitments of the lenders party to the Prior Credit Agreement were terminated and all loans and other indebtedness of the Partnership under the Prior Credit Agreement were renewed and extended, inclusive of new lender commitments, on the terms and conditions of the Credit Agreement. The Credit Agreement matures on June 22, 2016.

The credit facility under the Credit Agreement consists of aggregate initial commitments of $675 million that may, at the Partnership’s request and subject to the terms and conditions of the Credit Agreement, be increased up to an aggregate total amount of $1.2 billion. Availability under the credit facility is subject to a borrowing base comprised of two components: the upstream component and the midstream component. The upstream component of the borrowing base is determined semi-annually as an amount equal to the loan value of the proved oil and gas reserves of the Partnership and its subsidiaries as determined by the lenders party to the Credit Agreement. The midstream component of the borrowing base is determined quarterly as an amount equal to the lesser of (i) 55% of the total borrowing base (subject to increase for certain periods following certain material acquisitions up to 60% of the total borrowing base) and (ii) 3.75 times Consolidated EBITDA (as defined in the Credit Agreement) attributable to the midstream assets of the Partnership and its subsidiaries for the trailing four fiscal quarters. Pro forma adjustments to each component of the borrowing base, and thus total availability under the credit facility, are made upon the occurrence of certain events including material acquisitions and dispositions. Availability under the Credit Agreement is based on the lower of the current borrowing base and the total commitments. As of June 30, 2011, the Partnership had approximately $218.4 million of availability under the credit facility. The Partnership currently pays a 0.45% commitment fee per year on the difference between total commitments and the amount drawn under the credit facility.

The initial borrowings under the Credit Agreement were used to repay in full the borrowings under the Prior Credit Agreement and to pay fees and expenses incurred in connection with the Credit Agreement. Also, in connection with the Credit Agreement, the Partnership incurred debt issuance costs of $6.4 million and recorded a charge of $0.4 million to write off a portion of the unamortized debt issuance costs related to the Prior Credit Agreement. As of June 30, 2011, the Partnership had unamortized debt issuance costs of $7.5 million.

The Credit Agreement includes a sub limit for the issuance of standby letters of credit for a total of $150 million. As of June 30, 2011, the Partnership had $3.4 million of outstanding letters of credit.

In general, at the Partnership's election, interest will accrue on the credit facility at either LIBOR plus a margin ranging from 1.75% to 2.75% (currently 2.25% per annum based on the Partnership's borrowing base utilization percentage) or the base rate plus a margin ranging from 0.75% to 1.75% (currently 1.25% per annum based on the Partnership's borrowing base utilization percentage). The applicable margin is determined based on the utilization of the then existing borrowing base. The credit facility under the Credit Agreement may be prepaid, without any premium or penalty, at any time. The base rate is generally the highest of the federal funds rate plus 0.5%, the prime rate as announced from time to time by the Administrative Agent, or daily LIBOR for a term of one month plus 1.0%. As of June 30, 2011, the weighted average interest rate (excluding the impact of interest rate swaps) on the Partnership's outstanding debt under its revolving credit facility was 2.43%.

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The obligations under the Credit Agreement are secured by first priority liens on substantially all of the Partnership’s material assets, including a pledge of all of the equity interests of each of the Partnership’s material subsidiaries.

The Credit Agreement requires the Partnership and certain of its subsidiaries to make certain representations and warranties that are customary for credit facilities of this type. The Credit Agreement also contains affirmative and negative covenants that are customary for credit facilities of this type, including compliance with financial covenants. The financial covenants prohibit the Partnership from:

• permitting, as of any fiscal quarter-end, the ratio of the Partnership’s Consolidated EBITDA (as defined in the Credit Agreement) for the four fiscal quarter period ending with such fiscal quarter to Consolidated Interest Expense (as defined in the Credit Agreement) for such four fiscal quarter period to be less than 2.50 to 1.00;

• permitting, as of any fiscal quarter-end, the ratio of the Partnership's Total Funded Indebtedness (as defined in the Credit Agreement) to Consolidated EBITDA for the four fiscal quarter period ending with such fiscal quarter to be greater than 4.50 to 1.00; and

• permitting the ratio of the Partnership’s consolidated current assets (including availability under the Credit Agreement up to the loan limit, as defined within the Credit Agreement but excluding non-cash assets under the accounting guidance for derivatives) to consolidated current liabilities (excluding non-cash obligations under the accounting guidance for derivatives) to be less than 1.00 to 1.00.

As of June 30, 2011, the Partnership was in compliance with the financial covenants under the Credit Agreement.

Senior Notes

On May 27, 2011, the Partnership, along with its subsidiary, Eagle Rock Energy Finance Corp. ("Finance Corp"), as co-issuer, completed the sale of $300 million of senior unsecured notes (the "Senior Notes") through a private placement. The Senior Notes bear a coupon of 8 3/8%. The Senior Notes will mature on June 1, 2019 and interest is payable on each June 1 and December 1, commencing December 1, 2011. After the original discount of $2.2 million and excluding related offering expenses, the Partnership received net proceeds of approximately $297.8 million, which were used to repay borrowings outstanding under the Prior Credit Agreement. As of June 30, 2011, the Partnership had an unamortized debt discount of $2.1 million, which is recorded as an offset to the principal amount of the Senior Notes, and unamortized debt issuance costs of $8.5 million.

The Senior Notes are general unsecured senior obligations and rank equally in right of payment with all of the Partnership's existing and future senior indebtedness and rank senior in right of payment to any of the Partnership's future subordinated indebtedness. The Senior Notes are effectively junior in right of payment to all of the Partnership's existing and future secured indebtedness and other obligations, including borrowings outstanding under the Partnership's Credit Agreement, to the extent of the value of the assets securing such indebtedness and other obligations. The Senior Notes are jointly and severally guaranteed on a senior unsecured basis by the Partnership's existing and future subsidiaries, who are referred to as the "subsidiary guarantors," that guarantee our credit facility or other indebtedness.

The indenture, as supplemented, governing the Senior Notes, among other things, restricts the Partnership's ability and the ability of the Partnership's restricted subsidiaries to: (i) incur, assume or guarantee additional indebtedness or issue redeemable stock; (ii) pay dividends on stock, repurchase stock or redeem subordinated debt; (iii) make certain investments; (iv) enter into certain transactions with affiliates; (v) create liens on their assets; (vi) sell or otherwise dispose of certain assets, including capital stock of subsidiaries; (vii) restrict dividends, loans or other asset transfers from the Partnership's restricted subsidiaries; (viii) enter into new lines of business; and (ix) consolidate with or merge with or into, or sell all or substantially all of their properties (taken as a whole) to, another person.

The Partnership has the option to redeem all or a portion of the Senior Notes at any time on or after June 1, 2015 at the redemption prices specified in the indenture plus accrued and unpaid interest. The Partnership may also redeem the Senior Notes, in whole or in part, at a "make-whole" redemption price specified in the Indenture, plus accrued and unpaid interest, at any time prior to June 1, 2015. In addition, the Partnership may redeem up to 35% of the Senior Notes prior to June 1, 2014 under certain circumstances with the net cash proceeds from certain equity offerings at 108.375% of the principal amount of the notes redeemed.

In connection with the issuance and sale of the Senior Notes, the Partnership entered into a registration rights agreement (the "Senior Notes Registration Rights Agreement") with representatives of the initial purchasers. Pursuant to the Senior Notes Registration Rights Agreement, the Partnership agreed to file a registration statement with the Securities and

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Exchange Commission so that holders can exchange the Senior Notes for registered notes that have substantially identical terms as the Senior Notes and evidence the same indebtedness as the Senior Notes. In addition, the subsidiary guarantors agreed to exchange the guarantee related to the Senior Notes for a registered guarantee having substantially the same terms as the original guarantees. The Partnership is obligated to use commercially reasonable efforts to cause the exchange to be completed by June 30, 2012. If the Partnership fails to satisfy these obligations on a timely basis, it will be required to pay an additional 1% of interest to holders of the Senior Notes, until the exchange offer is completed or the shelf registration statement is declared (or becomes) effective, as applicable.

NOTE 9. MEMBERS’ EQUITY

At June 30, 2011, there were 119,879,395 common units outstanding. In addition, there were 1,821,328 unvested restricted common units outstanding.

During the six months endedJune 30, 2011, 7,649,544 warrants were exercised for a total of 7,649,544 newly issued common units. As of June 30, 2011 and December 31, 2010, 13,015,701 and 20,665,245 warrants were outstanding, respectively.

On February 7, 2011, the Partnership declared its fourth quarter 2010 cash distribution of $0.15 per unit to its common unitholders of record as of the close of business on February 14, 2011. The distribution was paid on February 14, 2011.

On April 26, 2011, the Partnership declared its first quarter 2011 cash distribution of $0.15 per unit to its common unitholders of record as of the close of business on May 9, 2011, except for the common units issued in connection with the acquisition of CC Energy II L.L.C. on May 3, 2011, which were not eligible to receive the first quarter 2011 distribution (see Note 4 for further discussion). The distribution was paid on May 13, 2011.  

On July 27, 2011, the Partnership declared its second quarter 2011 cash distribution of $0.1875 per unit to its common unitholders of record as of the close of business on August 5, 2011. The distribution will be paid on August 12, 2011.

NOTE 10. RELATED PARTY TRANSACTIONS

During the three and six months endedJune 30, 2011 and 2010, the Partnership purchased natural gas from certain companies affiliated with one or more NGP private equity firms and incurred $1.6 million, $3.2 million, $1.7 million and $4.0 million, respectively, in expenses owed to these related parties, of which there was an outstanding accounts payable balance of $0.6 million and $0.5 million as of June 30, 2011 and December 31, 2010, respectively.

The Partnership received 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 because NGP sold all of its interests in SFS. During the three and six months endedJune 30, 2010, the Partnership incurred approximately $0.4 million and $1.1 million, respectively, for services performed by SFS. As of both June 30, 2011 and December 31, 2010, there were no outstanding accounts payable balances to SFS.

On May 3, 2011, the Partnership completed the acquisition of Crow Creek Energy, a portfolio company of NGP VIII (see Note 4). Due to Crow Creek Energy being a portfolio company of NGP VIII and NGP's ownership interest in the Partnership and board of directors representation, the Board of Directors of the general partner of the Partnership's general partner, authorized its Conflicts Committee to review, evaluate, and, if determined appropriate, approve the acquisition of Crow Creek Energy, due to the potential conflict of interest among the Partnership, the NGP Parties and the Partnership's public unitholders. The Conflicts Committee, consisting of independent directors of the Partnership, determined that the acquisition of Crow Creek Energy was fair and reasonable to the Partnership and its public unitholders and recommended to the Board of Directors that the transaction be approved and authorized. In determining the consideration for the acquisition of Crow Creek Energy, the Conflicts Committee, with the assistance of a third-party, 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 flows of Crow Creek Energy.

In connection with the closing of the acquisition of Crow Creek Energy, the Partnership entered into a registration rights agreement ("Registration Rights Agreement") with NGP VIII. The Registration Rights Agreement grants NGP VIII and certain of its affiliates registration rights with respect to the common units acquired pursuant to the Partnership's acquisition of Crow Creek Energy and their outstanding warrants to purchase common units that were previously acquired by NGP VIII and certain of its affiliates in connection with the Partnership's previously completed recapitalization transaction. Pursuant to the Registration Rights Agreement, NGP VIII and certain of its affiliates have the ability to demand that the Partnership register for resale their common units acquired pursuant to the acquisition of Crow Creek Energy and their existing warrants to purchase

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common units. This registration may be an underwritten offering at the discretion of NGP VIII and certain of its affiliates. NGP VIII and certain of its affiliates may demand up to four such registrations, subject to an increase to up to seven if the registration rights are amended. Additionally, the Registration Rights Agreement provides that NGP VIII and certain of its affiliates have piggyback registration rights in certain circumstances, which would require inclusion of their common units and warrants on registration statements that the Partnership files, subject to certain customer exceptions. There are no limits on the number of times NGP VIII and certain of its affiliates can exercise these piggyback registration rights.

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 June 20, 2011, in conjunction with the refinancing of the credit facility under its Prior Credit Agreement (see Note 8), the Partnership consummated the following transactions to restructure certain of its interest rate swaps:

• Terminated a $150 million notional amount 2.56% fixed rate interest rate swap at a cost of $5.0 million; and

• Extended $250 million notional amount of its interest rate swaps from their original maturity date of December 31, 2012 to a new maturity date of June 22, 2015 and blended the existing swap rate for these extended swaps with the then prevailing interest rate swap rate, which lowered the rate from 4.095% to 2.95%. There was no cost associated with this extension.

The following table sets forth certain information regarding the Partnership's various interest rate swaps as of June 30, 2011:

Effective Date	Expiration Date	Notional Amount	Fixed Rate
9/30/2008	12/31/2012	150,000,000	4.295	%
10/3/2008	12/31/2012	50,000,000	4.095	%
6/22/2011	6/22/2015	250,000,000	2.95	%

The Partnership's interest rate derivative counterparties include Wells Fargo Bank National Association 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 objectives 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%, on an incurrence basis, of expected future production and has historically hedged substantially less than 80%, on an incurrence basis, of its expected future production for periods beyond 24 months. 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.  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

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future equity share of the commodities.

The Partnership uses fixed-price swaps, costless collars and put options 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 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 may 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 and reports this information to the Board of Directors at least quarterly.

The Partnership has not designated, for accounting purposes, any of its commodity derivative instruments as hedges and therefore marks these derivative contracts to fair value (see Note 12).  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 counterparty credit risk. Historically. the Partnership's counterparties have all been participants or affiliates of participants within its revolving credit facility (see Note 8), 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. In July 2011, the Partnership formed Eagle Rock Gas Services to market natural gas on behalf of itself and third parties. Eagle Rock Gas Services, through its financial derivative activity, will have credit exposure to additional 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.

The Partnership's commodity derivative counterparties include BNP Paribas, Wells Fargo Bank, National Association, Comerica Bank, Bank of Nova Scotia, The Royal Bank of Scotland plc, Bank of America N.A., J Aron and Company (an affiliate of Goldman Sachs) and BBVA Compass Bank.

During the three months ended June 30, 2011, the Partnership entered into the following hedging transactions:

• 20,000 barrel per month NYMEX WTI crude oil swap at $104.85 per barrel for its 2013 calendar year;

• 45,000 barrel per month NYMEX WTI crude oil swap at $102.45 per barrel for its 2014 calendar year;

• 105,000 MMbtu per month Henry Hub natural gas swap at $5.30 per MMbtu for its 2013 calendar year;

• 80,000 MMbtu per month Henry Hub natural gas swap at $4.87 per MMbtu for its 2012 calendar year;

• 2,100,000 gallon per month OPIS ethane swap at $0.69 per gallon for June through December 2011;

• 150,000 MMbtu per month Henry Hub natural gas swap at $4.76 per MMbtu for July through December 2011;

• 200,000 MMbtu per month Henry Hub natural gas swap at $5.06 per MMbtu for its calendar year 2012;

• 300,000 MMbtu per month Henry Hub natural gas swap at $5.34 per MMbtu for its calendar year 2013;

• 100,000 MMbtu per month Henry Hub natural gas swap at $5.54 per MMbtu for its calendar year 2014; and

• 250,000 MMbtu per month Henry Hub natural gas swap at $5.55 per MMbtu for its calendar year 2014.

As part of the Crow Creek Acquisition (see Note 4), the Partnership acquired the following commodity derivative contracts (volumes presented include amounts that settled during the three months ended June 30, 2011):

Natural Gas - Inside FERC Panhandle East Natural Gas and Centerpoint Energy Gas Transmission Co. - East - Inside FERC:

• Puts - An average of 142,500 MMbtu per month at an average strike price of $5.58 for the remaining months of 2011.

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• Swaps - An average of 485,000 MMbtu per month at an average strike price of $5.90 for the remaining months of 2011. An average of 410,000 MMbtu per month at an average strike price of $5.67 for calendar year 2012. An average of 159,167 MMbtu per month at an average strike price of $5.50 for calendar year 2013.

• Costless collars - An average of 162,500 MMbtu per month with an average floor price of $6.00 and an average cap price of $7.84 for the remaining months of 2011. An average of 252,500 MMbtu per month with an average floor price of $4.972 and an average cap price of $6.42 for calendar year 2012. An average of 295,000 MMbtu per month with an average floor price of $4.93 and an average cap price of $5.49.

Crude Oil -NYMEX WTI:

• Puts - 8,000 barrels per month at a strike price of $55.00 for the remaining months of 2011.

• Swaps - An average of 8,750 barrels per month at an average strike price of $61.68 for the remaining months of 2011. An average of 2,000 barrels per month at a strike price of $81.50 for the last six months of 2012 An average of 3,000 barrels per month at a strike price of $81.95 for the last nine months of 2013.

• Costless collars - An average of 9,500 barrels per month with an average floor price of $83.21 and an average cap price of $117.40 for the remaining months of 2011. An average of 12,000 barrels per month with an average floor price of $72.73 and an average cap price of $106.06 for calendar year 2012. An average of 8,250 barrels per month with an average floor price of $74.38 and an average cap price of 106.72 for calendar year 2013.

In conjunction with the refinancing of its revolving credit facility (see Note 8), the Partnership consummated the following transactions to restructure certain of its existing commodity hedges to remove two institutions not continuing as lenders under the Credit Agreement.

• Terminated, at a cost of $1.7 million, the remainder of a calendar year 2011 17,000 barrel per month WTI crude oil swap at $83.30 per barrel. The Partnership entered into a 17,000 barrel per month WTI crude oil swap at $96.50 per barrel for July through December 31, 2011 to re-hedge these volumes.

• Terminated, at a cost of $3.1 million, a calendar year 2013 32,000 barrel per month WTI crude oil swaps at $90.75 per barrel. In July 2011, the Partnership entered into a 32,000 barrel per month WTI crude oil swap at $101.96 per barrel for calendar year 2013 to re-hedge these volumes.

• Novated a portfolio of calendar year 2011, 2012 and 2013 hedges and, at a cost of $14.6 million, adjusted the strike price to reflect current market prices of the following novated hedges:

• The remainder of a calendar year 2011 252,000 gallon per month OPIS propane swap from $1.11 per gallon to $1.55 a gallon;

• The remainder of a calendar year 2011 5,000 barrel per month WTI crude oil swap from $75.00 per barrel to $95.44 per barrel;

• A calendar year 2012 20,000 barrel per month WTI crude oil swap from $76.00 per barrel to $97.42 per barrel;

• A calendar year 2013 20,000 barrel per month WTI crude oil swap from $90.20 per barrel to $98.01 per barrel; and

• A calendar year 2013 60,000 barrel per month WTI crude oil swap from $89.95 per barrel to $98.01 per barrel.

19

The following tables set forth certain information regarding the Partnership's commodity derivatives. Within each table, some trades of the same commodities with the same tenors have been aggregated and shown as weighted averages.

Commodity derivatives, as of June 30, 2011, that will mature during the year ended December 31, 2011:

Underlying	Period	Notional Volumes (units)	Type	Weighted Average Floor Strike Price ($/unit)		Weighted Average Cap Strike Price ($/unit)
Natural Gas:
NYMEX Henry Hub	Jul-Dec 2011	600,000 mmbtu	Costless Collar	$	7.500	$	8.850
IF Panhandle East	Jul-Dec 2011	960,000 mmbtu	Costless Collar	5.844		7.631
IF Panhandle East	Jul-Dec 2011	300,000 mmbtu	Put	5.000
IF Centerpoint East	Jul-Dec 2011	480,000 mmbtu	Put	5.375
NYMEX Henry Hub	Jul-Dec 2011	1,950,000 mmbtu	Swap	6.248
NYMEX Henry Hub	Jul-Dec 2011	(204,000) mmbtu	Swap	4.450
IF Panhandle East	Jul-Dec 2011	2,220,000 mmbtu	Swap	5.887
IF Centerpoint East	Jul-Dec 2011	660,000 mmbtu	Swap	5.375
Crude Oil:
NYMEX WTI	Jul-Dec 2011	369,576 bbls	Costless Collar	78.085		92.746
NYMEX WTI	Jul-Dec 2011	48,000 bbls	Put	55.000
NYMEX WTI	Jul-Dec 2011	494,628 bbls	Swap	75.068
Natural Gas Liquids:
OPIS Nbutane Mt. Belv non TET	Jul-Dec 2011	5,796,000 gallons	Swap	1.500
OPIS IsoButane Mt. Belv non TET	Jul-Dec 2011	2,772,000 gallons	Swap	1.543
OPIS Natural Gasoline Mt. Belv non TET	Jul-Dec 2011	2,268,000 gallons	Swap	1.853
OPIS Propane Mt. Belv non TET	Jul-Dec 2011	11,592,000 gallons	Swap	1.173
OPIS Ethane Mt. Belv non TET	Jul-Dec 2011	21,168,000 gallons	Swap	0.631

20

Commodity derivatives, as of June 30, 2011, that will mature during the year ended December 31, 2012:

Underlying	Period	Notional Volumes (units)	Type	Weighted Average Floor Strike Price ($/unit)		Weighted Average Cap Strike Price ($/unit)
Natural Gas:
NYMEX Henry Hub	Jan-Dec 2012	1,080,000 mmbtu	Costless Collar	$	7.350	$	8.650
IF Panhandle East	Jan-May 2012	1,350,000 mmbtu	Costless Collar	5.287		6.912
IF Panhandle East	Jan-Dec 2012	1,680,000 mmbtu	Costless Collar	4.364		5.476
NYMEX Henry Hub	Jan-Dec 2012	6,480,000 mmbtu	Swap	5.854
IF Panhandle East	Jan-May 2012	750,000 mmbtu	Swap	5.715
IF Panhandle East	Jan-Dec 2012	720,000 mmbtu	Swap	5.110
IF Centerpoint East	Jan-May 2012	300,000 mmbtu	Swap	5.795
IF Centerpoint East	Jun-Dec 2012	3,150,000 mmbtu	Swap	5.715
Crude Oil:
NYMEX WTI	Jan-Dec 2012	699,576 bbls	Costless Collar	77.631		95.314
NYMEX WTI	Jan-May 2012	50,000 bbls	Costless Collar	70.000		101.705
NYMEX WTI	Jan-Jun 2012	18,000 bbls	Costless Collar	70.000		92.740
NYMEX WTI	June 2012	54,000 bbls	Costless Collar	73.889		107.669
NYMEX WTI	Jul-Dec 2012	10,000 bbls	Costless Collar	75.000		112.500
NYMEX WTI	Jan-Dec 2012	1,248,468 bbls	Swap	85.097
NYMEX WTI	Jul-Dec 2012	12,000 bbls	Swap	81.500

Commodity derivatives, as of June 30, 2011, that will mature during the year ended December 31, 2013:

Underlying	Period	Notional Volumes (units)	Type	Weighted Average Floor Strike Price ($/unit)		Weighted Average Cap Strike Price ($/unit)
Natural Gas:
IF Panhandle East	Jan-Dec 2013	1,440,000 mmbtu	Costless Collar	$	4.450	$	5.430
IF Panhandle East	Jan-May 2013	700,000 mmbtu	Costless Collar	5.100		5.610
IF Panhandle East	Jun-Dec 2013	1,400,000 mmbtu	Costless Collar	5.100		5.450
NYMEX Henry Hub	Jan-Dec 2013	6,660,000 mmbtu	Swap	5.350
IF Centerpoint East	Jan-May 2013	500,000 mmbtu	Swap	5.970
IF Panhandle East	Jan-May 2013	500,000 mmbtu	Swap	5.353
IF Panhandle East	Jun-Dec 2013	910,000 mmbtu	Swap	5.260
Crude Oil:
NYMEX WTI	Jan-Dec 2013	36,000 bbls	Costless Collar	80.000		108.000
NYMEX WTI	Jan-Mar 2013	27,000 bbls	Costless Collar	78.085		92.746
NYMEX WTI	Apr-Dec 2013	36,000 bbls	Costless Collar	70.000		96.410
NYMEX WTI	Jan-Dec 2013	1,320,000 bbls	Swap	98.360
NYMEX WTI	Apr-Dec 2013	27,000 bbls	Swap	81.950

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Commodity derivatives, as of June 30, 2011, that will mature during the year ended December 31, 2014:

Underlying	Period	Notional Volumes (units)	Type	Weighted Average Floor Strike Price ($/unit)		Weighted Average Cap Strike Price ($/unit)
Natural Gas:
NYMEX Henry Hub	Jan-Dec 2014	4,200,000 mmbtu	Swap	$	5.546
Crude Oil:
NYMEX WTI	Jan-Dec 2014	540,000 bbls	Swap	102.450

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 June 30, 2011 and December 31, 2010:

	As of June 30, 2011
	Derivative Assets				Derivative Liabilities
	Balance Sheet Classification	Fair Value			Balance Sheet Classification	Fair Value
	($ in thousands)
Interest rate derivatives - liabilities		$	—		Current liabilities	$	(12,629	)
Interest rate derivatives - liabilities		—			Long-term liabilities	(11,619		)
Commodity derivatives - assets	Current assets	9,153			Current liabilities	10,795
Commodity derivatives - assets	Long-term assets	5,237			Long-term liabilities	7,492
Commodity derivatives - liabilities	Current assets	(7,177		)	Current liabilities	(28,537		)
Commodity derivatives - liabilities	Long-term assets	(2,301		)	Long-term liabilities	(16,570		)
Total derivatives		$	4,912			$	(51,068	)
	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 liabilities	9,150
Commodity derivatives - assets	Long-term assets	2,402			Long-term liabilities	5,347
Commodity derivatives - liabilities		—			Current liabilities	(28,678		)
Commodity derivatives - liabilities	Long-term assets	(1,327		)	Long-term liabilities	(21,595		)
Total derivatives		$	1,075			$	(70,355	)

The following table sets forth the location of gains and losses for derivatives not designated as hedging instruments within the Partnership's unaudited condensed consolidated statement of operations (in thousands):

Amount of Gain (Loss) Recognized in Income on Derivatives		Three Months Ended June 30,						Six Months Ended June 30,
		2011			2010			2011			2010
Interest rate derivatives	Interest rate risk management losses	$	(1,643	)	$	(9,306	)	$	(4,305	)	$	(19,018	)
Commodity derivatives	Commodity risk management gains (losses)	34,338			35,592			(26,107		)	46,387
	Total	$	32,695		$	26,286		$	(30,412	)	$	27,369

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NOTE 12. FAIR VALUE OF FINANCIAL INSTRUMENTS

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.

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As of June 30, 2011, the Partnership has recorded its interest rate swaps and commodity derivative instruments (see Note 11), which includes crude oil, natural gas and 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 considered to be less liquid and thinly traded, 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 June 30, 2011 and December 31, 2010: 

	As of June 30, 2011
	Level 1		Level 2			Level 3			Netting (a)			Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	1,727		$	—		$	(7,245	)	$	(5,518	)
Natural gas derivatives	—		30,853			—			(16,499		)	14,354
NGL derivatives	—		—			61			(3,985		)	(3,924		)
Total	$	—	$	32,580		$	61		$	(27,729	)	$	4,912
Liabilities:
Crude oil derivatives	$	—	$	(44,835	)	$	—		$	7,245		$	(37,590	)
Natural gas derivatives	—		(20		)	—			16,499			16,479
NGL derivatives	—		—			(9,693		)	3,985			(5,708		)
Interest rate swaps	—		(24,249		)	—			—			(24,249		)
Total	$	—	$	(69,104	)	$	(9,693	)	$	27,729		$	(51,068	)

____________________________

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

	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 agreement governing such derivative contracts.

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The following table sets forth a reconciliation of changes in the fair value of the Level 3 NGL derivatives during the three and six months endedJune 30, 2011 and 2010 (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Net liability beginning balance	$	(12,264	)	$	(7,658	)	$	(5,733	)	$	(14,784	)
Settlements	5,669			2,265			9,406			6,394
Total gains or losses (realized and unrealized)	(3,037		)	3,533			(13,305		)	6,530
Net liability ending balance	$	(9,632	)	$	(1,860	)	$	(9,632	)	$	(1,860	)

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 $(1.6) million, $(7.5) million, $3.4 million and $5.1 million in the three and six months endedJune 30, 2011 and 2010, respectively, that are attributable to the change in unrealized gains or losses related to those assets and liabilities still held at June 30, 2011 and 2010, 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 unaudited condensed 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 unaudited condensed consolidated statements of operations. 

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.

As of June 30, 2011, the outstanding debt associated with the Credit Agreement bore interest at a floating rate; as such, the Partnership believes that the carrying value of this debt approximates its fair value. The outstanding debt associated with the Senior Notes bears interest at a fixed rate; based on the market price of the Senior Notes as of June 30, 2011, the Partnership estimates that the fair value of the Senior Notes is $298.1 million compared to a carrying value of $297.9 million.

NOTE 13. COMMITMENTS AND CONTINGENT LIABILITIES

Litigation—The Partnership is subject to 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 had no accruals as of June 30, 2011 and December 31, 2010 related to legal matters, and current lawsuits are not expected to have a material adverse effect on our financial position, results of operations or cash flows. The Partnership has been indemnified up to a certain dollar amount for two lawsuits. If there ultimately is a finding against the Partnership in these two indemnified cases, the Partnership would expect to make a claim against the indemnification up to limits of the indemnification.

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

25

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 June 30, 2011 and December 31, 2010, the Partnership had accrued approximately $3.9 million and $4.0 million, respectively, for environmental matters.

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 Creek field, the retained revenue interest commenced in 2010 and continues 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 operations. Rental expense, including leases with no continuing commitment, amounted to approximately $2.0 million, $4.4 million, $1.7 million and $3.5 million for the three and six months endedJune 30, 2011 and 2010, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term.

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NOTE 14. SEGMENTS

On May 24, 2010, the Partnership completed the sale of its Minerals Business, and on May 20, 2011, the Partnership completed its sale of its Wildhorse Gathering System, which was previously reported under the South Texas Segment. As authoritative guidance requires, the operations for components of entities disposed of be recorded as part of discontinued operations, operating results for the Minerals Business for the three and six months ended June 30, 2010 and operating results for the the Wildhorse Gathering System for each of the three and six months ended June 30, 2011 and 2010, have been excluded from the Partnership’s segment presentation below. See Note 18 for a further discussion of the sale of the Partnership’s Minerals Business and the Wildhorse 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 and one functional (Corporate) 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 and crude oil logistics and marketing in the Texas Panhandle and Alabama;

(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, NGLs 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 tables:

Midstream Business Three Months Ended June 30, 2011	Texas Panhandle Segment		South Texas Segment			East Texas / Louisiana Segment		Gulf of Mexico Segment			Total Midstream Business
($ in thousands)
Sales to external customers	$	160,300	$	11,313		$	55,641	$	10,799		$	238,053
Cost of natural gas and natural gas liquids	111,488		10,714			41,386		9,086			172,674
Intersegment cost of oil and condensate	13,903		—			—		—			13,903
Operating costs and other (income) expenses	11,207		278			4,651		444			16,580
Depreciation, depletion, amortization and impairment	13,676		735			4,561		1,664			20,636
Operating income (loss) from continuing operations	$	10,026	$	(414	)	$	5,043	$	(395	)	$	14,260
Capital Expenditures	$	7,861	$	16		$	1,455	$	—		$	9,332
Segment Assets	$	569,463	$	48,236		$	255,668	$	79,561		$	952,928

Total Segments Three Months Ended June 30, 2011	Total Midstream Business		Upstream Segment		Corporate and Other Segment				Total Segments
($ in thousands)
Sales to external customers	$	238,053	$	39,324	$	34,338		(a)	$	311,715
Intersegment sales	—		13,021		(13,021		)		—
Cost of natural gas and natural gas liquids	172,674		—		—				172,674
Intersegment cost of oil and condensate	13,903		—		(13,903		)		—
Operating costs and other (income) expenses	16,580		10,560		13,009				40,149
Intersegment operations and maintenance	—		24		(24		)		—
Depreciation, depletion, amortization and impairment	20,636		15,180		320				36,136
Operating income from continuing operations	$	14,260	$	26,581	$	21,915			$	62,756
Capital Expenditures	$	9,332	$	19,158	$	682			$	29,172
Segment Assets	$	952,928	$	973,316	$	27,192		(c)	$	1,953,436

Midstream Business Three Months Ended June 30, 2010	Texas Panhandle Segment		South Texas Segment			East Texas / Louisiana Segment		Gulf of Mexico Segment			Total Midstream Business
($ in thousands)
Sales to external customers	$	84,003	$	14,480		$	50,779	$	7,428		$	156,690
Cost of natural gas and natural gas liquids	54,732		13,041			34,477		6,393			108,643
Operating costs and other expenses	8,413		654			4,210		531			13,808
Depreciation, depletion, amortization and impairment	11,639		3,741			4,112		1,567			21,059
Operating income (loss) from continuing operations	$	9,219	$	(2,956	)	$	7,980	$	(1,063	)	$	13,180
Capital Expenditures	$	7,743	$	55		$	5,267	$	5		$	13,070
Segment Assets	$	523,867	$	52,932		$	316,744	$	82,821		$	976,364

Total Segments Three Months Ended June 30, 2010	Total Midstream Business		Upstream Segment			Corporate and Other Segment			Total Segments
($ in thousands)
Sales to external customers	$	156,690	$	24,261		$	35,592	(a)	$	216,543
Cost of natural gas and natural gas liquids	108,643		—			—			108,643
Operating costs and other expenses	13,808		8,924		(b)	12,806			35,538
Depreciation, depletion, amortization and impairment	21,059		9,058			482			30,599
Operating income from continuing operations	$	13,180	$	6,279		$	22,304		$	41,763
Capital Expenditures	$	13,070	$	7,414		$	259		$	20,743
Segment Assets	$	976,364	$	358,908		$	53,103		$	1,388,375

_________________________________

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

(b) Includes costs to dispose of sulfur in the Upstream Segment of $0.9 million for the three months endedJune 30, 2010.

(c) Includes elimination of intersegment transactions.

28

Midstream Business Six Months Ended June 30, 2011	Texas Panhandle Segment		South Texas Segment			East Texas / Louisiana Segment		Gulf of Mexico Segment			Total Midstream Business
($ in thousands)
Sales to external customers	$	285,164	$	22,020		$	110,814	$	18,897		$	436,895
Cost of natural gas and natural gas liquids	200,327		20,634			83,054		15,978			319,993
Intersegment cost of oil and condensate	20,992		—			—		—			20,992
Operating costs and other expenses	20,608		655			9,203		899			31,365
Depreciation, depletion, amortization and impairment	22,797		1,473			9,117		3,330			36,717
Operating income (loss) from continuing operations	$	20,440	$	(742	)	$	9,440	$	(1,310	)	$	27,828
Capital Expenditures	$	15,251	$	89		$	2,375	$	34		$	17,749
Segment Assets	$	569,463	$	48,236		$	255,668	$	79,561		$	952,928

Total Segments Six Months Ended June 30, 2011	Total Midstream Business		Upstream Segment			Corporate and Other Segment				Total Segments
($ in thousands)
Sales to external customers	$	436,895	$	58,291	(c)	$	(26,107	)	(a)	$	469,079
Intersegment sales	—		22,524			(22,524		)		—
Cost of natural gas and natural gas liquids	319,993		—			—				319,993
Intersegment cost of oil and condensate	20,992		—			(20,992		)		—
Operating costs and other (income) expenses	31,365		18,566			24,785				74,716
Intersegment operations and maintenance	—		66			(66		)		—
Depreciation, depletion, amortization and impairment	36,717		22,734			707				60,158
Operating income (loss) from continuing operations	$	27,828	$	39,449		$	(53,065	)		$	14,212
Capital Expenditures	$	17,749	$	24,820		$	774			$	43,343
Segment Assets	$	952,928	$	972,633		$	27,192		(d)	$	1,952,753

Midstream Business Six Months Ended June 30, 2010	Texas Panhandle Segment		South Texas Segment			East Texas / Louisiana Segment		Gulf of Mexico Segment			Total Midstream Business
($ in thousands)
Sales to external customers	$	177,678	$	33,418		$	111,142	$	16,287		$	338,525
Cost of natural gas and natural gas liquids	121,702		30,303			80,682		13,858			246,545
Operating costs and other expenses	16,511		1,140			8,419		1,036			27,106
Depreciation, depletion, amortization and impairment	23,229		4,646			8,540		3,170			39,585
Operating income (loss) from continuing operations	$	16,236	$	(2,671	)	$	13,501	$	(1,777	)	$	25,289
Capital Expenditures	$	9,947	$	31		$	6,808	$	18		$	16,804
Segment Assets	$	523,867	$	52,932		$	316,744	$	82,821		$	976,364

Total Segments Six Months Ended June 30, 2010	Total Midstream Business		Upstream Segment			Corporate and Other Segment			Total Segments
($ in thousands)
Sales to external customers	$	338,525	$	46,946		$	46,387	(a)	$	431,858
Cost of natural gas and natural gas liquids	246,545		—			—			246,545
Operating costs and other expenses	27,106		18,031		(b)	25,817			70,954
Depreciation, depletion, amortization and impairment	39,585		17,623			835			58,043
Operating income from continuing operations	$	25,289	$	11,292		$	19,735		$	56,316
Capital Expenditures	$	16,804	$	12,392		$	893		$	30,089
Segment Assets	$	976,364	$	358,908		$	53,103		$	1,388,375

_________________________________

(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 six months endedJune 30, 2010.

(c) Sales to external customers for the six months endedJune 30, 2011 includes $2.0 million of business interruption insurance recovery related to the shutdown of the Eustace plant in 2010 in the Upstream Segment, which is recognized as part of Other revenue in the unaudited condensed consolidated statement of operations.

(d) Includes elimination of intersegment transactions.

29

NOTE 15. INCOME TAXES

Provision for 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 certain entities acquired in the Redman acquisition) and Eagle Rock Energy Acquisition Co. II, Inc. (acquiring entity of certain entities acquired in the Stanolind Acquisition) and their wholly-owned subsidiary 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 (collectively, the "C Corporations").

As a result of the taxable income from the underlying partnerships owned by the C Corporations described above, statutory depletion carryforwards of $0.2 million, $0.5 million, $0.9 million and $1.8 million were used during the three and six months endedJune 30, 2011 and 2010, respectively.

Effective Rate - The effective rate for the six months endedJune 30, 2011 was 100% compared to 1.0% for the six months endedJune 30, 2010. Due to the fact that the effective rate is a ratio of total tax expense compared to pre-tax book net income, the change is due primarily to the fact that the Partnership was in a loss position during the six months ending June 30, 2011 versus a positive income position in the six months ended June 30, 2010.

Deferred Taxes - As of June 30, 2011, the net deferred tax liability was $38.3 million compared to $36.7 million as of December 31, 2010, primarily attributable to temporary book and tax basis differences of the entities subject to federal income taxes discussed above. These temporary differences result in a net deferred tax liability which will be reduced as allocation of depreciation and depletion 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 for the Stanolind and Redman acquisitions.

Texas Franchise Tax - On May 18, 2006, the State of Texas enacted revisions to the 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 corporations. 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. The Partnership makes appropriate accruals for this tax during the reporting period.

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 of 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 2008 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, 2010	$	(569	)
Increases related to prior year tax positions	—
Increases related to current year tax positions	—
Balance as of June 30, 2011	$	(569	)

NOTE 16. EQUITY-BASED COMPENSATION

Eagle Rock Energy G&P, LLC, the general partner of the general partner of 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. The LTIP provides for the issuance of an aggregate of up to 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. No options or phantom units have been issued to date.

The restricted units granted are valued at the market price as of the date issued. The weighted average fair value of the units granted during the six months endedJune 30, 2011 and 2010 were $10.76 and $5.94, respectively. The awards generally vest over three years 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.

30

A summary of the restricted common units’ activity for the six months endedJune 30, 2011 is provided below:

	Number of Restricted Units		Weighted Average Fair Value
Outstanding at December 31, 2010	1,744,454		$	6.27
Granted	241,625		$	10.76
Vested	(62,071	)	$	5.07
Forfeited	(102,680	)	$	6.46
Outstanding at June 30, 2011	1,821,328		$	6.89

For the three and six months endedJune 30, 2011 and 2010, non-cash compensation expense of approximately $1.0 million, $1.9 million, $1.6 million and $3.4 million, respectively, was recorded related to the granted restricted units.

As of June 30, 2011, unrecognized compensation costs related to the outstanding restricted units under the LTIP totaled approximately $9.1 million. The remaining expense is to be recognized over a weighted average of 2.25 years.

In connection with the vesting of certain restricted units during the three months endedJune 30, 2011, 10,772 of the newly-vested common units were cancelled by the Partnership in satisfaction of $0.1 million of employee tax liability paid by the Partnership. Pursuant to the terms of the LTIP, these cancelled units are available for future grants under the LTIP.

NOTE 17. EARNINGS PER UNIT

Basic earnings per unit is 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.

As of June 30, 2011 and 2010, the Partnership had 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.

Any warrants outstanding during the period are considered 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.

The restricted common units granted under the LTIP, as discussed in Note 16, contain non-forfeitable rights to the distributions declared by the Partnership and therefore meet the definition of participating securities. Participating securities are required to be included in the computation of earnings per unit pursuant to the two-class method. For the three months ended June 30, 2011 and three and six months ended June 30, 2010, 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. For the six months ended June 30, 2011, distributions were greater than the current period earnings, which resulted in an undistributed loss. Due to this undistributed loss, diluted earnings per unit would result in antidilution. Therefore, diluted earnings per unit was computed in the same manner as basic earnings per unit.

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 three and six months endedJune 30, 2010, 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, and they were eliminated.

31

In addition, all of the subordinated units and general partner units were contributed to the Partnership and cancelled on May 24, 2010 and July, 30, 2010, respectively.

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

	Three Months Ended June 30,		Six Months Ended June 30,
	2011	2010	2011	2010
	(Unit amounts in thousands)
Weighted average units outstanding during period:
Common units - Basic	108,117	56,597	96,130	55,344
Effect of Dilutive Securities:
Warrants	6,795	—	6,927	—
Restricted Units	985	208	893	171
Common units - Diluted	115,897	56,808	103,950	55,515
Subordinated units - Basic and Diluted		12,278		16,683
General partner units - Basic and Diluted		845		845

The following table presents the Partnership's basic income per unit for the three months endedJune 30, 2011:

	Total			Common Units			Restricted Common Units
	($ in thousands, except for per unit amounts)
Income from continuing operations	$	55,382
Distributions declared	20,549			$	20,272		$	277
Assumed income from continuing operations after distribution to be allocated	34,833			34,266			567
Assumed allocation of income from continuing operations	55,382			54,538			844
Discontinued operations	(311		)	(311		)	—
Assumed net income to be allocated	$	55,071		$	54,227		$	844
Basic income from continuing operations per unit				$	0.50
Basic discontinued operations per unit				$	—
Basic income per unit				$	0.50

32

The following table presents the Partnership's diluted income per unit for the three months endedJune 30, 2011:

	Total			Common Units			Restricted Common Units
	($ in thousands, except for per unit amounts)
Income from continuing operations	$	55,382
Distributions declared	21,823			$	21,546		$	277
Assumed income from continuing operations after distribution to be allocated	33,559			33,025			534
Assumed allocation of income from continuing operations	55,382			54,571			811
Discontinued operations	(311		)	(311		)	—
Assumed net income to be allocated	$	55,071		$	54,260		$	811
Diluted income from continuing operations per unit				$	0.47
Diluted discontinued operations per unit				$	—
Diluted income per unit				$	0.47

The following table presents the Partnership's basic and diluted loss per unit for the six months endedJune 30, 2011:

	Total			Common Units			Restricted Common Units
	($ in thousands, except for per unit amounts)
Income from continuing operations	$	947
Distributions declared	31,151			$	30,660		$	491
Assumed loss from continuing operations after distribution to be allocated	(30,204		)	(30,204		)	—
Assumed allocation of income from continuing operations	947			456			491
Discontinued operations	407			407			—
Assumed net income to be allocated	$	1,354		$	863		$	491
Basic and diluted income from continuing operations per unit				$	—
Basic and diluted discontinued operations per unit				$	—
Basic and diluted income per unit				$	0.01

33

The following table presents the Partnership's basic and diluted income per unit for the three months ended June 30, 2010:

	Total		Common Units		Restricted Common Units		Subordinated Units		General Partner Units
	($ in thousands, except for per unit amounts)
Income from continuing operations	$	28,650
Distributions declared	1,462		$	1,415	$	26	$	—	$	21
Assumed income from continuing operations after distribution to be allocated	27,188		21,671		492		4,701		324
Assumed allocation of income from continuing operations	28,650		23,086		518		4,701		345
Discontinued operations, net of tax	39,493		31,479		714		6,830		470
Assumed net income to be allocated	$	68,143	$	54,565	$	1,232	$	11,531	$	815
Basic and diluted income from continuing operations per unit			$	0.41			$	0.38	$	0.41
Basic and diluted discontinued operations per unit			$	0.56			$	0.56	$	0.56
Basic and diluted income per unit			$	0.96			$	0.94	$	0.96

The following table presents the Partnership's basic and diluted income per unit for the six months endedJune 30, 2010:

	Total		Common Units		Restricted Common Units		Subordinated Units		General Partner Units
	($ in thousands, except for per unit amounts)
Income from continuing operations	$	28,479
Distributions declared	2,867		$	2,770	$	55	$	—	$	42
Assumed income from continuing operations after distribution to be allocated	25,612		19,102		461		5,758		291
Assumed allocation of income from continuing operations	28,479		21,872		516		5,758		333
Discontinued operations, net of tax	43,645		32,550		785		9,813		497
Assumed net income to be allocated	$	72,124	$	54,422	$	1,301	$	15,571	$	830
Basic and diluted income from continuing operations per unit			$	0.40			$	0.35	$	0.40
Basic and diluted discontinued operations per unit			$	0.59			$	0.59	$	0.59
Basic and diluted income per unit			$	0.98			$	0.93	$	0.98

NOTE 18.   DISCONTINUED OPERATIONS

On April 1, 2009, the Partnership sold its producer services business (which was accounted for in its South Texas Segment). As part of the sale, the Partnership received a monthly payment equivalent to $0.01 per MMbtu on the volume of gas that flowed pursuant to the assigned contracts through March 31, 2011. During the six months endedJune 30, 2011, this business generated revenues of less than $0.1 million and no cost of natural gas and NGLs. During the three and six months endedJune 30, 2010, this business generated revenues of $0.1 million and no cost of natural gas and NGLs.

On May 24, 2010, the Partnership completed the sale of its Minerals Business. During the three and six months endedJune 30, 2011, the Partnership received payments of $0.1 million and $0.4 million, respectively, related to pre-effective date

34

operations and recorded this amount as part of discontinued operations for the period. For the three and six months endedJune 30, 2010, the Partnership generated revenues of $3.3 million and $8.9 million, respectively, and income from operations of $1.8 million and $5.6 million, respectively. During the three and six months ended June 30, 2010, the Minerals Business incurred state tax expense on discontinued operations of $0.4 million and $0.4 million, respectively. During the three and six months endedJune 30, 2010, the Partnership recorded income from discontinued operations of $2.2 million and $6.0 million, respectively.

On May 20, 2011, the Partnership sold its Wildhorse Gathering System (which was accounted for in its South Texas Segment), for net proceeds of approximately $6.1 million in cash. The Partnership recorded a loss of $0.6 million on the sale, which is recorded as part of discontinued operations for the three and six months ended June 30, 2011. Further upward or downward adjustments to the purchase price may occur post-closing to reflect customary true-ups. For the three and six months endedJune 30, 2011, the Partnership generated revenues of $1.8 million and $6.7 million, respectively and income from operations of $0.1 million and $0.6 million, respectively. For the three and six months endedJune 30, 2010, the Partnership generated revenues of $6.3 million and $14.0 million, respectively and income from operations of less than $0.1 million and $0.4 million, respectively. During the three and six months endedJune 30, 2011, the Partnership recorded a loss from discontinued operations of $0.4 million and income from discontinued operations of less than $0.1 million, respectively. During the three and six months endedJune 30, 2010, the Partnership recorded income from discontinued operations of less than $0.1 million and $0.4 million, respectively. During each of the three and six months endedJune 30, 2011 and 2010, this system incurred state tax expense of less than $0.1 million.

Assets and liabilities held for sale represent the assets and liabilities of the Wildhorse Gathering System. 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 and (iii) $0.3 million of intangible assets.

NOTE 19. OTHER OPERATING INCOME

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

Panhandle and East Texas midstream systems to SemGroup. 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 maintained the balance as a liability until it was clear that the repurchase obligations can no longer be triggered. Due to the expiration of the repurchase obligations during the three months ended June 30, 2011, the Partnership released its reserve for these receivables and recorded other operating income of $2.9 million related to these reserves.

NOTE 20. SUBSIDIARY GUARANTORS

In the future, the Partnership expects to 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 June 30, 2011 and December 31, 2010, and Condensed Consolidating Statements of Operations and Condensed Consolidating Statements of Cash Flows for the three and six months endedJune 30, 2011 and 2010, present financial information for Eagle Rock Energy 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.

35

Unaudited Condensed Consolidating Balance Sheet
June 30, 2011
	Parent Issuer		Subsidiary Guarantors		Non-guarantor investments		Consolidating Entries			Total
	($ in thousands)
ASSETS:
Accounts receivable – related parties	$	1,218	$	—	$	—	$	(1,218	)	$	—
Other current assets	3,784		108,677		—		—			112,461
Total property, plant and equipment, net	1,052		1,704,004		—		—			1,705,056
Investment in subsidiaries	1,710,559		—		1,066		(1,711,625		)	—
Total other long-term assets	19,605		116,314		—		—			135,919
Total assets	$	1,736,218	$	1,928,995	$	1,066	$	(1,712,843	)	$	1,953,436
LIABILITIES AND EQUITY:
Accounts payable – related parties	$	—	$	1,218	$	—	$	(1,218	)	$	—
Other current liabilities	29,967		143,589		—		—			173,556
Other long-term liabilities	22,342		73,629		—		—			95,971
Long-term debt	745,855		—		—		—			745,855
Equity	938,054		1,710,559		1,066		(1,711,625		)	938,054
Total liabilities and equity	$	1,736,218	$	1,928,995	$	1,066	$	(1,712,843	)	$	1,953,436

Unaudited Condensed Consolidating Balance Sheet
As of December 31, 2010
	Parent Issuer		Subsidiary Guarantors		Non-guarantor investments		Consolidating Entries			Total
	($ in thousands)
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

36

Unaudited Condensed Consolidating Statement of Operations
For the Three Months Ended June 30, 2011
	Parent Issuer			Subsidiary Guarantors			Non-guarantor investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	33,627		$	278,088		$	—		$	—		$	311,715
Cost of natural gas and natural gas liquids	—			172,674			—			—			172,674
Operations and maintenance	—			21,951			—			—			21,951
Taxes other than income	—			5,189			—			—			5,189
General and administrative	723			15,179			—			—			15,902
Other operating income	—			(2,893		)	—			—			(2,893		)
Depreciation, depletion, amortization and impairment	40			36,096			—			—			36,136
Income from operations	32,864			29,892			—			—			62,756
Interest expense	(6,306		)	(5		)	—			—			(6,311		)
Other non-operating income	2,163			1,113			—			(3,273		)	3
Other non-operating expense	(2,428		)	(2,596		)	(6		)	3,273			(1,757		)
Income (loss) before income taxes	26,293			28,404			(6		)	—			54,691
Income tax provision (benefit)	(224		)	(467		)	—			—			(691		)
Equity in earnings of subsidiaries	28,554			—			—			(28,554		)	—
Income (loss) from continuing operations	55,071			28,871			(6		)	(28,554		)	55,382
Discontinued operations, net of tax	—			(311		)	—			—			(311		)
Net income (loss)	$	55,071		$	28,560		$	(6	)	$	(28,554	)	$	55,071

Unaudited Condensed Consolidating Statement of Operations
For the Three Months Ended June 30, 2010
	Parent Issuer			Subsidiary Guarantors			Non-guarantor investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	28,515		$	188,028		$	—		$	—		$	216,543
Cost of natural gas and natural gas liquids	—			108,643			—			—			108,643
Operations and maintenance	—			19,926			—			—			19,926
Taxes other than income	1			2,805			—			—			2,806
General and administrative	2,249			10,557			—			—			12,806
Depreciation, depletion, amortization and impairment	78			30,521			—			—			30,599
Income from operations	26,187			15,576			—			—			41,763
Interest expense	(4,383		)	(1		)	—			—			(4,384		)
Other non-operating income	2,049			650			(21		)	(2,526		)	152
Other non-operating expense	(3,634		)	(8,198		)	—			2,526			(9,306		)
Income (loss) before income taxes	20,219			8,027			(21		)	—			28,225
Income tax provision (benefit)	—			(425		)	—			—			(425		)
Equity in earnings of subsidiaries	47,924			—			—			(47,924		)	—
Income (loss) from continuing operations	68,143			8,452			(21		)	(47,924		)	28,650
Discontinued operations, net of tax	—			39,493			—			—			39,493
Net income (loss)	$	68,143		$	47,945		$	(21	)	$	(47,924	)	$	68,143

37

Unaudited Condensed Consolidating Statement of Operations
For the Six Months Ended June 30, 2011
	Parent Issuer			Subsidiary Guarantors			Non-guarantor investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	(19,482	)	$	488,561		$	—		$	—		$	469,079
Cost of natural gas and natural gas liquids	—			319,993			—			—			319,993
Operations and maintenance	—			41,426			—			—			41,426
Taxes other than income	—			8,505			—			—			8,505
General and administrative	1,717			25,961			—			—			27,678
Other operating income	—			(2,893		)	—			—			(2,893		)
Depreciation, depletion, amortization and impairment	80			60,078			—			—			60,158
(Loss) income from operations	(21,279		)	35,491			—			—			14,212
Interest expense	(9,527		)	(8		)	—			—			(9,535		)
Other non-operating income	4,286			2,218			—			(6,498		)	6
Other non-operating expense	(5,200		)	(5,756		)	(11		)	6,498			(4,469		)
(Loss) income before income taxes	(31,720		)	31,945			(11		)	—			214
Income tax provision (benefit)	196			(929		)	—			—			(733		)
Equity in earnings of subsidiaries	33,270			—			—			(33,270		)	—
Income (loss) from continuing operations	1,354			32,874			(11		)	(33,270		)	947
Discontinued operations, net of tax	—			407			—			—			407
Net income (loss)	$	1,354		$	33,281		$	(11	)	$	(33,270	)	$	1,354

Unaudited Condensed Consolidating Statement of Operations
For the Six Months Ended June 30, 2010
	Parent Issuer			Subsidiary Guarantors			Non-guarantor investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	30,037		$	401,821		$	—		$	—		$	431,858
Cost of natural gas and natural gas liquids	—			246,545			—			—			246,545
Operations and maintenance	—			38,797			—			—			38,797
Taxes other than income	2			6,338			—			—			6,340
General and administrative	4,985			20,832			—			—			25,817
Depreciation, depletion, amortization and impairment	82			57,961			—			—			58,043
Income from operations	24,968			31,348			—			—			56,316
Interest expense	(8,794		)	(4		)	—			—			(8,798		)
Other non-operating income	4,053			1,221			(15		)	(5,006		)	253
Other non-operating expense	(7,397		)	(16,627		)	—			5,006			(19,018		)
(Loss) income before income taxes	12,830			15,938			(15		)	—			28,753
Income tax provision (benefit)	827			(553		)	—			—			274
Equity in earnings of subsidiaries	60,121			—			—			(60,121		)	—
Income (loss) from continuing operations	72,124			16,491			(15		)	(60,121		)	28,479
Discontinued operations, net of tax	—			43,645			—			—			43,645
Net income (loss)	$	72,124		$	60,136		$	(15	)	$	(60,121	)	$	72,124

38

Unaudited Condensed Consolidating Statement of Cash Flows
For the Six Months Ended June 30, 2011
	Parent Issuer			Subsidiary Guarantors			Non-guarantor investments		Consolidating Entries			Total
	($ in thousands)
Net cash flows provided by operating activities	$	(1,215	)	$	26,851		$	57	$	—		$	25,693
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions, net of cash acquired	—			(220,326		)	—		—			(220,326		)
Additions to property, plant and equipment	—			(31,195		)	—		—			(31,195		)
Purchase of intangible assets	—			(1,315		)	—		—			(1,315		)
Proceeds from sale of asset	—			6,093			—		—			6,093
Contribution to subsidiaries	(227,583		)	—			—		227,583			—
Net cash flows used in investing activities	(227,583		)	(246,743		)	—		227,583			(246,743		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	709,329			—			—		—			709,329
Repayment of long-term debt	(791,329		)	—			—		—			(791,329		)
Proceed from senior notes	297,837			—			—		—			297,837
Payment of debt issuance cost	(13,802		)	—			—		—			(13,802		)
Proceeds from derivative contracts	2,443			—			—		—			2,443
Repurchase of common units	(119		)	—			—		—			(119		)
Exercise of Warrants	45,897			—			—		—			45,897
Distributions to members and affiliates	(26,250		)	—			—		—			(26,250		)
Contribution from parrent	—			227,583			—		(227,583		)	—
Net cash flows provided by financing activities	224,006			227,583			—		(227,583		)	224,006
Net cash flows used in discontinued operations	—			(180		)	—		—			(180		)
Net (decrease) increase in cash and cash equivalents	(4,792		)	7,511			57		—			2,776
Cash and cash equivalents at beginning of year	4,890			(884		)	43		—			4,049
Cash and cash equivalents at end of year	$	98		$	6,627		$	100	$	—		$	6,825

39

Unaudited Condensed Consolidating Statement of Cash Flows
For the Six Months Ended June 30, 2010
	Parent Issuer			Subsidiary Guarantors			Non-guarantor Investments			Consolidating Entries		Total
	($ in thousands)
Net cash flows provided by (used in) operating activities	$	199,456		$	(156,848	)	$	54		$	—	$	42,662
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(532		)	(23,378		)	—			—		(23,910		)
Purchase of intangible assets	—			(968		)	—			—		(968		)
Proceeds from sale of asset	—			171,664			—			—		171,664
Net cash flows (used in) provided by investing activities	(532		)	147,318			—			—		146,786
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	36,000			—			—			—		36,000
Repayment of long-term debt	(225,000		)	—			—			—		(225,000		)
Repurchase of common units	(219		)	—			—			—		(219		)
Deferred transaction fees	(2,557		)	—			—			—		(2,557		)
Proceeds from derivative contracts	—			628			—			—		628
Distributions to members and affiliates	(3,024		)	—			—			—		(3,024		)
Net cash flows (used in) provided by financing activities	(194,800		)	628			—			—		(194,172		)
Net cash flows provided by discontinued operations				8,313			—			—		8,313
Net (decrease) increase in cash and cash equivalents	4,124			(589		)	54			—		3,589
Cash and cash equivalents at beginning of year	4,922			(2,179		)	(11		)	—		2,732
Cash and cash equivalents at end of year	$	9,046		$	(2,768	)	$	43		$	—	$	6,321

NOTE 21.  SUBSEQUENT EVENTS

Risk Management Activities

On July 6, 2011, the Partnership entered into a 32,000 barrel per month NYMEX WTI crude oil swap at $101.96 per barrel for its 2013 calendar year. This transaction replaces the 2013 crude oil swap that was terminated during the three months ended June 30, 2011 with a counterparty not continuing as a lender under the the partnership's revolving credit facility (see Note 11).

Woodall Plant

On July 27, 2011, the Partnership announced plans to install a state-of-the-art 60 MMcf/d cryogenic processing facility in the Granite Wash play in the Texas Panhandle. The processing plant (to be named the “Woodall Plant”) is expected to be completed in the first quarter of 2012 and will be located in Hemphill County.

The plant will be strategically located on a 40-acre site owned by the Partnership in the center of its existing high-pressure gathering system near multiple residue gas pipeline outlets. In addition, a new 6-inch NGL pipeline, a compressor station and other intra-system pipeline enhancements will be constructed to further facilitate product gathering, transportation and marketing. The supporting infrastructure is currently being designed to accommodate one or more additional expansions. The construction of the Woodall Plant and associated gathering and compression infrastructure is expected to cost approximately $67.0 million. The Partnership does not anticipate downtime or reduced throughput volumes across its East or West Panhandle Systems during the completion of the project.

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Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis of financial condition and results of operations should be read in conjunction with our unaudited condensed consolidated financial statements, and the notes thereto, appearing elsewhere in this report, as well as the Consolidated Financial Statements, Risk Factors and Management's Discussion and Analysis of Financial Condition and Results of Operations presented in our annual report on Form 10-K for the year ended December 31, 2010, filed with the Securities and Exchange Commission. For a description of oil and natural gas terms, see our 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 present our business in six segments for reporting purposes.

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, and crude oil logistics and marketing in Texas and Alabama. 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 three and six months endedJune 30, 2011, our Midstream Business generated operating income from continuing operations of $14.3 million and $27.8 million, respectively, compared to operating income from continuing operations of $13.2 million and $25.3 million generated during the three and six months endedJune 30, 2010, respectively, an increase of $1.1 million and $2.5 million, respectively.  

We conduct, evaluate and report on our Upstream Business as one segment. Our Upstream Segment includes operated and non-operated wells located in Alabama, Texas, Oklahoma, Arkansas, Mississippi and Louisiana, and operates two treating facilities, one natural gas processing plant and the related gathering systems in Escambia County, Alabama.   During the three and six months endedJune 30, 2011, our Upstream Business generated operating income of $26.6 million and $39.4 million, respectively, compared to operating income of $6.3 million and $11.3 million generated during the three and six months endedJune 30, 2010, respectively.  Of important note, our Upstream Business generated net revenue of $4.7 million and $7.7 million from the sale of sulfur during the three and six months endedJune 30, 2011, respectively, compared to net revenue of $1.2 million and $2.5 million during the three and six months endedJune 30, 2010, respectively.  

The final segment that we report on is our Corporate and Other Segment, which is where we account for our risk management activity, intersegment eliminations and our general and administrative expenses.   During the three and six months endedJune 30, 2011, our Corporate Segment generated operating income, excluding intersegment eliminations, of $21.0 million and an operating loss, excluding intersegment eliminations, of $51.6 million, respectively, compared to a operating income of $22.3 million and $19.7 million generated during the three and six months endedJune 30, 2010, respectively.  Results reflected net gains, realized and unrealized, on our commodity derivatives of $34.3 million and net losses of $26.1 million during the three and six months endedJune 30, 2011, respectively, compared to a net gain, realized and unrealized, on our commodity derivatives of $35.6 million and $46.4 million during the three and six months endedJune 30, 2010, respectively.  See "Summary of Consolidated Operating Results - Corporate and Other Segment" for a further discussion of the impact of our commodity derivatives.

Acquisition

On May 3, 2011, we completed the acquisition of all of the outstanding membership interests of CC Energy II L.L.C (together with its subsidiaries, "Crow Creek Energy"), a portfolio company of Natural Gas Partners, VIII, L.P. ("NGP VIII") (the "Crow Creek Acquisition") for total consideration of $563.7 million including 28.8 million common units valued at $336.1 million, debt assumed of $212.6 million and cash of approximately $15.0 million. The cash portion of the acquisition consideration and the repayment of Crow Creek Energy’s outstanding debt was funded through borrowings under our revolving

41

credit facility. In addition, we incurred $2.3 million of acquisition related expenses, which are included within general and administrative expenses for the three and six months ended June 30, 2011. The oil and natural gas properties acquired from Crow Creek Energy are located in multiple basins across Oklahoma, north Texas and Arkansas (the "Mid-Continent Properties") and provides the Partnership with an extensive inventory of low-risk development prospects.

The Mid-Continent Properties contained approximately 257 Bcfe of proved reserves as of December 31, 2010, of which approximately 79% was natural gas and approximately 66% was proved developed. The acquired operating areas include 327 gross (271 net) productive operated wells and 1,040 gross (82 net) productive non-operated wells on approximately 115,500 net acres across the Golden Trend field, Verden field, the Cana Shale play and other various fields, all located in the Anadarko basin in Oklahoma; the Mansfield field and other various fields in the Arkoma basin in Arkansas; and the Barnett Shale in Texas.

Net production from the Mid-Continent Properties from the May 3, 2011 closing date through June 30, 2011, was approximately 2.4 Bcf of natural gas, 60 Mbbl of crude oil and 63 Mbbl of NGLs, of which approximately 76% was produced from wells we operate. The majority of the interests in the Cana Shale are operated by large upstream companies with significant experience and expertise in developing shale gas reserves.

Upon closing the Crow Creek Acquisition, we identified 182 proved undeveloped drilling locations on the Mid-Continent Properties, of which approximately 12 are expected to be drilled in 2011. In addition to the current cash flow and lower-risk development opportunities provided by the acquired proved reserve base, the acquired assets include approximately 12,700 net acres with 413 identified low-risk probable drilling locations in the emerging Cana Shale play in Oklahoma. This play is experiencing a high level of horizontal drilling activity, with over 50 rigs currently active across the trend.

Subsequent Events

Woodall Plant - On July 27, 2011, we announced plans to install a state-of-the-art 60 MMcf/d cryogenic processing facility in the Granite Wash play in the Texas Panhandle. The processing plant (to be named the “Woodall Plant”) is expected to be completed in the first quarter of 2012 and will be located in Hemphill County.

The plant will be strategically located on a 40-acre site owned by us in the center of our existing high-pressure gathering system near multiple residue gas pipeline outlets. In addition, a new 6-inch NGL pipeline, a compressor station and other intra-system pipeline enhancements will be constructed to further facilitate product gathering, transportation and marketing. The supporting infrastructure is currently being designed to accommodate one or more additional expansions. The construction of the Woodall Plant and associated gathering and compression infrastructure is expected to cost approximately $67.0 million. We do not anticipate downtime or reduced throughput volumes across its East or West Panhandle Systems during the completion of the project. The addition of our Woodall Plant to our existing processing infrastructure in the Texas Panhandle, together with the announced expansion of our Arrington Ranch - Phoenix plant discussed in the Texas Panhandle Segment below, is in response to incremental processing needs driven by increased drilling activity by producers in the Granite Wash Play.

Impairment

We incurred impairment charges during the three and six months endedJune 30, 2011 of $4.6 million and $4.9 million, respectively. During the three and six months endedJune 30, 2011, we recorded an impairment charge of $4.6 million in our Texas Panhandle Segment to fully write-down our idle Turkey Creek plant. We determined that the assets that made up our Turkey Creek plant could not be used elsewhere within our business, and thus we decided to remove all above ground equipment and structures. During the six months endedJune 30, 2011, we incurred impairment charges of $0.3 million in our Upstream Business related to certain legacy drilling locations in our unproved properties which we no longer intend to develop based on the performance of offsetting wells.  During the three and six months endedJune 30, 2010, we recorded $3.1 million in impairment charges within our Midstream Segment due to the loss of a significant gathering contract in our South Texas Segment.

Pursuant to generally accepted accounting principles in the United States ("U.S. GAAP"), 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.

42

Other Matters

Potential Impact of New Environmental Standards - The Partnership has certain permit obligations to lower its SO₂ emissions at its Alabama plant operations.  Additionally, in mid-2010, the Environmental Protection Agency (“EPA”) enacted new National Ambient Air Quality Standards (“2010 NAAQS”) which substantially lowered the emissions limits for SO₂ and mandated timelines for compliance.  In order to fulfill its permit obligations and comply with the new 2010 NAAQS requirements, the Partnership expects to spend in excess of $40 million over the next several years to enhance its SO₂ recovery capabilities at its Alabama operations.  The expected facility upgrades to Eagle Rock's Alabama operations should not only increase the marketable sulfur recovered from the inlet gas stream, but also are anticipated to reduce plant fuel consumption, improve the plant's operating reliability and extend the plant's operating life. Management does not anticipate, however, that the required spending will generate returns consistent with the Partnership's internal rate of return thresholds for discretionary capital investment. At this time, management has identified no other operational areas impacted by the 2010 NAAQS.     

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

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 March 11, 2011, the date the facility was brought back into service. The shut-down of the Eustace facility impacted our Upstream Segment's net revenues by approximately $11.0 million, including an impact of $3.9 million for the six months endedJune 30, 2011. We recognized $3.0 million in 2010 under our business interruption insurance and recognized the remaining $2.0 million during the three months ended March 31, 2011 as other revenue. The maximum recovery under our business interruption insurance policy is $5.0 million per occurrence.

43

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report may include “forward-looking statements” as defined by the SEC. All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These statements are based on certain assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control, which may cause our actual results to differ materially from those implied or expressed by the forward-looking statements. We do not assume any obligation to update such forward-looking statements following the date of this report. For a complete description of these risks, please read our risk factors set forth in our annual report on Form 10-K for the year ended December 31, 2010 and in “Part II. Item 1A. Risk Factors.” These factors include but are not limited to:

• Drilling and geological / exploration risks;

• Assumptions regarding oil and natural gas reserve levels and costs to exploit and timing of development;

• Volatility or declines in commodity prices;

• Our significant existing indebtedness, including indebtedness we assumed in connection with the Crow Creek Acquisition;

• Hedging activities;

• Ability to obtain credit and access capital markets;

• Ability to remain in compliance with the covenants set forth in our existing credit facility (and those expected to be set forth in our new credit facility);

• Conditions in the securities and/or capital markets;

• Future processing volumes and throughput;

• Loss of significant customers;

• Availability and cost of processing and transportation of NGLs;

• Competition in the oil and natural gas industry;

• Relevant legislative or regulatory changes, including retroactive royalty or production tax regimes, changes in environmental, health and safety regulation, hydraulic fracturing regulation, environmental risks and liability under federal, state and foreign environmental laws and regulations;

• Ability to make favorable acquisitions and integrate operations from such acquisitions, including our recent Crow Creek Acquisition;

• Shortages of personnel and equipment;

• Potential losses associated with trading in derivative contracts;

• Increases in interest rates;

• Creditworthiness of our counterparties;

• Weather, including the occurrence of any adverse weather conditions and/or natural disasters affecting our business;

• Any other factors that impact or could impact the exploration of oil or natural gas resources, including but not limited to the geology of a resource, the total amount and costs to develop recoverable reserves, legal title, regulatory, natural gas administration, marketing and operations factors relating to the extraction of oil and natural gas; and

• Tax risk associated with pass-through investment, including potential reduction in tax shield or creation of phantom income in the event distributions are not enough to support the tax burden.

44

RESULTS OF OPERATIONS

Summary of Consolidated Operating Results

Below is a table of a summary of our consolidated operating results for the three and six months endedJune 30, 2011 and 2010.

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	($ in thousands)
Revenues:
Sales of natural gas, NGLs, oil, condensate and sulfur	$	265,317		$	164,972		$	468,372		$	356,973
Gathering, compression, processing and treating fees	12,304			16,230			25,549			28,713
Realized commodity derivative losses	(8,813		)	(5,813		)	(15,260		)	(8,496		)
Unrealized commodity derivative gains (losses)	43,151			41,405			(10,847		)	54,883
Other revenue	(244		)	(251		)	1,265			(215		)
Total revenues	311,715			216,543			469,079			431,858
Cost of natural gas, natural gas liquids, and condensate	172,674			108,643			319,993			246,545
Costs and expenses:
Operating and maintenance	21,951			19,926			41,426			38,797
Taxes other than income	5,189			2,806			8,505			6,340
General and administrative	15,902			12,806			27,678			25,817
Other operating income	(2,893		)	—			(2,893		)	—
Impairment expense	4,560			3,130			4,884			3,130
Depreciation, depletion and amortization	31,576			27,469			55,274			54,913
Total costs and expenses	76,285			66,137			134,874			128,997
Total operating income	62,756			41,763			14,212			56,316
Other income (expense):
Interest income	3			173			6			175
Interest expense	(6,311		)	(4,384		)	(9,535		)	(8,798		)
Unrealized interest rate derivatives gains (losses)	2,791			(4,354		)	5,356			(9,176		)
Realized interest rate derivative losses	(4,434		)	(4,952		)	(9,661		)	(9,842		)
Other (expense) income	(114		)	(21		)	(164		)	78
Total other income (expense)	(8,065		)	(13,538		)	(13,998		)	(27,563		)
Income (loss) from continuing operations before income taxes	54,691			28,225			214			28,753
Income tax (benefit) provision	(691		)	(425		)	(733		)	274
Income from continuing operations	55,382			28,650			947			28,479
Discontinued operations, net of tax	(311		)	39,493			407			43,645
Net income	$	55,071		$	68,143		$	1,354		$	72,124
Adjusted EBITDA(a)	$	53,948		$	31,474		$	84,242		$	62,267

________________________

(a) See "- Non-GAAP Financial Measures" for a definition and reconciliation to GAAP.

45

Midstream Business (Four Segments)

Texas Panhandle Segment

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Sales of natural gas, NGLs, oil and condensate	$	156,073		$	80,955		$	277,151		$	171,688
Gathering and treating services	4,227			3,048			8,013			5,990
Total revenues	160,300			84,003			285,164			177,678
Cost of natural gas, NGLs, and condensate (a)	125,391			54,732			221,319			121,702
Operating costs and expenses:
Operations and maintenance	11,207			8,413			20,608			16,511
Depreciation and amortization	9,116			11,639			18,237			23,229
Impairment	4,560			—			4,560			—
Total operating costs and expenses	24,883			20,052			43,405			39,740
Operating income	$	10,026		$	9,219		$	20,440		$	16,236
Capital expenditures	$	7,861		$	7,743		$	15,251		$	9,947
Realized prices:
Oil and condensate (per Bbl)	$	87.54		$	67.37		$	83.81		$	67.89
Natural gas (per Mcf)	$	4.00		$	3.45		$	4.00		$	4.28
NGLs (per Bbl)	$	58.27		$	45.95		$	56.48		$	47.08
Production volumes:
Gathering volumes (Mcf/d)(b)	153,870			132,625			149,103			130,570
NGLs (net equity Bbls)	181,186			234,677			377,132			462,200
Condensate (net equity Bbls)	243,238			269,340			468,632			476,522
Natural gas short position (MMbtu/d)(b)	(360		)	(7,134		)	(4,551		)	(5,725		)

_______________________

(a) Includes purchase of oil and condensate of $13,903 and $20,992 from the Upstream Segment for the three and six months endedJune 30, 2011, respectively.

(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 NGLs. For the three and six months endedJune 30, 2011, revenues minus cost of natural gas, NGLs and condensate for our Texas Panhandle Segment operations totaled $34.9 million and $63.8 million, respectively, compared to $29.3 million and $56.0 million, respectively, for the three and six months endedJune 30, 2010. The increase was primarily driven by higher product prices, increased volumes from new drilling activity in the area and volumes associated with the acquisition of gathering assets from CenterPoint Energy Field Services (our "East Hemphill" system) in October of 2010; however, these benefits were substantially offset by operating downtime at three facilities and a reduction in existing volumes of natural gas, NGLs and condensate due to severe winter weather in our Texas Panhandle Segment. The severe weather and operating downtime that occurred in January and February 2011 impacted revenues minus cost of natural gas by $2.0 million and $4.1 million across the Texas Panhandle Segment during the three and six months endedJune 30, 2011, respectively. This event also caused damage to our Cargray processing facility, resulting in reduced recoveries of NGLs. The Cargray processing facility was repaired in late June 2011 and is now back to its previous operating conditions. Also, Eagle Rock Marketing, LLC, which began operations during the fourth quarter of 2010, contributed $0.7 million and $1.2 million, respectively, of revenues minus cost of NGLs and condensate during the three and six months endedJune 30, 2011.

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

46

share of the production, the overall decline will continue. However, we have seen a resurgence of drilling activity in the East Panhandle by our producer customers beginning in the third quarter of 2010 as higher NGL prices and continued improvements in horizontal drilling technology and fracturing practices resulted in favorable drilling economics. We began to experience the benefit of this increase in drilling activity on our processed volumes during the fourth quarter of 2010 and expect it would have continued in the first half of 2011 had it not been for the severe winter weather experienced in January and February. We expect drilling activity and the resulting volumes to continue to improve during the remainder of 2011.

Operating Expenses. Operating expenses, including taxes other than income, for the three and six months endedJune 30, 2011, increased $2.8 million and $4.1 million, respectively, as compared to the three and six months endedJune 30, 2010. The increase was primarily driven by costs related to the East Hemphill gathering system acquired in October 2010, routine plant turnarounds and higher costs associated with our high-efficiency cryogenic Arrington Ranch - Phoenix Plant ("Arrington Ranch - Phoenix Plant"). Additionally, the costs incurred related to February's extreme weather during the three and six months ended June 30, 2011were approximately $0.5 million and $1.3 million, respectively.

Depreciation and Amortization. Depreciation and amortization expenses for the three and six months endedJune 30, 2011 decreased $2.5 million and $5.0 million, respectively, from the three and six months endedJune 30, 2010. The major item impacting the decrease was a reduction in amortization expense due to certain intangible assets becoming fully amortized during the fourth quarter of 2010. This decrease was offset by increased depreciation expense associated with the capital expenditures placed into service during the period.

Impairment. During the three and six months endedJune 30, 2011, we recorded an impairment charge of $4.6 million in our Texas Panhandle Segment to fully write down our idle Turkey Creek plant. We determined that the components of our Turkey Creek plant could not be used elsewhere within our business, and thus we decided to remove all above ground equipment and structures.

Capital Expenditures. Capital expenditures for the three and six months endedJune 30, 2011 increased $0.1 million and $5.3 million, respectively, compared to the three and six months endedJune 30, 2010. The increase was primarily driven by spending related to: (i) the construction of our Arrington Ranch - Phoenix Plant, including an interconnect between it and our System 97 gathering system, (ii) spending related to improvements to our Cargray Stabilizer and Goad Treater, and (iii) interconnects between our East Hemphill system and our Arrington Ranch - Phoenix Plant.

On April 27, 2011, we announced our intention to expand the Arrington Ranch - Phoenix Plant by an incremental 30 MMcf/d. Once the expansion is completed, the plant capacity will total 80 MMcf/d. The expansion of the Arrington Ranch - Phoenix Plant, coupled with additional expansions of related gathering systems (the "Phoenix Expansion"), will increase our total processing and gathering capacity and accommodate volume growth from the Granite Wash play. The expansion is a direct complement to our acquisition of the East Hemphill system in October 2010, which extended our reach into Hemphill and Wheeler Counties in the Texas Panhandle.

The expansion of the Arrington Ranch - Phoenix Plant and related gathering systems is expected to be completed in the fourth quarter of 2011 at a cost of approximately $20 million. We do not anticipate downtime or reduced throughput volumes across our East or West Panhandle Systems during the completion of the project. In addition, due to the increased demand for additional processing capacity in the area, we do not intend to shut down and re-direct gas volumes from our Canadian Plant in Hemphill County, Texas into the Arrington Ranch - Phoenix Plant as previously announced. Our Canadian Plant will remain operating, with total processing capacity of 25 MMcf/d.

47

  East Texas/Louisiana Segment

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Sales of natural gas, NGLs, oil and condensate	$	47,828	$	38,623	$	94,420	$	90,464
Gathering and treating services	7,813		12,156		16,394		20,678
Total revenues	55,641		50,779		110,814		111,142
Cost of natural gas and NGLs	41,386		34,477		83,054		80,682
Operating costs and expenses:
Operations and maintenance	4,651		4,210		9,203		8,419
Depreciation and amortization	4,561		4,112		9,117		8,540
Total operating costs and expenses	9,212		8,322		18,320		16,959
Operating income	$	5,043	$	7,980	$	9,440	$	13,501
Capital expenditures	$	1,455	$	5,267	$	2,375	$	6,808
Realized prices:
Oil and condensate (per Bbl)	$	109.51	$	75.48	$	95.54	$	73.99
Natural gas (per Mcf)	$	4.61	$	4.94	$	4.61	$	5.45
NGLs (per Bbl)	$	53.23	$	33.26	$	47.90	$	36.03
Production volumes:
Gathering volumes (Mcf/d)(a)	191,735		211,157		195,986		212,027
NGLs (net equity Bbls)(b)	99,483		101,104		178,298		212,522
Condensate (net equity Bbls)(b)	6,939		8,392		24,018		19,613
Natural gas short position (MMbtu/d)(a)	1,717		719		1,437		1,270

________________________

(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) For the three and six months ended June 30, 2011, volumes from our Indian Springs plant, in which we own 25%, are included in equity NGL and condensate volumes, as we believe including these volumes is more illustrative of current operating trends. In addition, volumes associated with a certain contract at our Brookeland plant have been excluded from the three and six months periods ended June 30, 2011 due to a change in reporting methodology.

Revenue and Cost of Natural Gas and NGLs. For the three and six months endedJune 30, 2011, revenues minus cost of natural gas and NGLs for our East Texas/Louisiana Segment totaled $14.3 million and $27.8 million, respectively, compared to $16.3 million and $30.5 million, respectively, for the three and six months endedJune 30, 2010. During the three and six months endedJune 30, 2011 and 2010, we recorded revenues associated with deficiency payments of $0.2 million, $1.4 million, $6.5 million and $8.1 million, respectively. 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, NGLs and condensate for the three and six months endedJune 30, 2011 and 2010 would have been $14.1 million, $26.3 million, $9.8 million and $22.3 million, respectively. The increase for the three and six months endedJune 30, 2011 compared to the three and six months endedJune 30, 2010, excluding the impact of the deficiency payments, is primarily due to higher condensate and NGL prices and increased condensate and NGL equity volumes, and is partially offset by a decrease in gathering volumes and lower natural gas prices.

The gathering volumes on our East Texas Mainline ("ETML") system and certain other East Texas/Louisiana systems for the three and six months endedJune 30, 2011 decreased as compared to the three and six months endedJune 30, 2010, due to natural declines in the production of the existing wells, reduced drilling activity related to a decline in natural gas prices and

48

to certain mechanical and completion difficulties experienced by our producer customers during the three months ended June 30, 2011. Despite the slight decrease in gathering volumes, NGL volumes increased by 26% as compared to the first quarter of 2011 due to an accounting true-up to our March 2011 estimate recorded in the second quarter and to lower-than-normal liquids recoveries in the first quarter caused by severe winter weather. Condensate volumes declined in the second quarter relative to the first quarter of 2011 due in part to reduced pipeline pigging operations, which help recover condensate from the pipeline, in the second quarter.

Operating Expenses. Operating expenses for the three and six months endedJune 30, 2011 increased $0.4 million and $0.8 million, respectively, compared to the three and six months endedJune 30, 2010 as a result of higher costs at the Indian Springs Plant (which is operated by a third party), compressor repairs and labor and benefits, offset by lower compressor rental costs and chemicals.

Depreciation and Amortization. Depreciation and amortization expenses for the three and six months endedJune 30, 2011 increased $0.4 million and $0.6 million, respectively, compared to the three and six months endedJune 30, 2010. The increase was due to depreciation expense associated with the capital assets placed into service during the period.

Capital Expenditures. Capital expenditures for the three and six months endedJune 30, 2011 decreased $3.8 million and $4.4 million, respectively, compared to the three and six months endedJune 30, 2010. Costs incurred to connect new wells decreased $2.9 million and $1.9 million, respectively, during the three and six months endedJune 30, 2011 compared to the same periods in 2010. In addition, capital expenditures for the three and six months endedJune 30, 2011 were offset by the sale of $0.6 million and $2.9 million, respectively, of excess pipe inventory related to the ETML expansion project which was cancelled in 2010.

49

South Texas Segment

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Sales of natural gas, NGLs, oil and condensate	$	11,151		$	13,627		$	21,144		$	31,981
Gathering and treating services	162			853			876			1,437
Total revenues	11,313			14,480			22,020			33,418
Cost of natural gas and NGLs	10,714			13,041			20,634			30,303
Operating costs and expenses:
Operations and maintenance	278			654			655			1,140
Impairment	—			3,130			—			3,130
Depreciation and amortization	735			611			1,473			1,516
Total operating costs and expenses	1,013			4,395			2,128			5,786
Operating loss from continuing operations	(414		)	(2,956		)	(742		)	(2,671		)
Discontinued operations (a)	(449		)	30			3			378
Operating loss	$	(863	)	$	(2,926	)	$	(739	)	$	(2,293	)
Capital expenditures	$	16		$	55		$	89		$	31
Realized prices:
Oil and condensate (per Bbl)	$	—		$	72.51		$	82.40		$	75.21
Natural gas (per Mcf)	$	4.26		$	3.85		$	4.13		$	4.66
NGLs (per Bbl)	$	55.37		$	43.91		$	51.76		$	46.95
Production volumes:
Gathering volumes (Mcf/d)(b)	27,221			60,361			31,584			61,745
NGLs (net equity Bbls)	1,069			2,267			2,145			4,511
Condensate (net equity Bbls)	—			7,193			890			11,587
Natural gas short position (MMbtu/d)(b)	145			1,152			630			1,108

________________________

(a) Includes sales of natural gas of $24 and $66 to the Upstream Segment for the three and six months endedJune 30, 2011.

(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 NGLs. During the three and six months endedJune 30, 2011, the South Texas Segment contributed revenues minus cost of natural gas and NGLs of $0.6 million and $1.4 million, respectively, as compared to $1.4 million and $3.1 million, respectively, for the three and six months endedJune 30, 2010.   Our South Texas Segment was negatively impacted by declining gathering volumes due to the loss of a significant producer during the third quarter of 2010.

Operating Expenses. Operating expenses for the three and six months endedJune 30, 2011 decreased $0.4 million and $0.5 million, respectively, compared to the three and six months endedJune 30, 2010 due to reduced gathering volumes in 2011. Additionally, a major pigging project and pipeline integrity work contributed to the higher expenses in 2010.

Impairment. We recorded impairment expense of $3.1 million in the three and six months endedJune 30, 2010 due to the loss of a significant gathering contract. No impairment charges were incurred in the three and six months endedJune 30, 2011.

Depreciation and Amortization. Depreciation and amortization expenses for the three and six months endedJune 30, 2011 remained consistent as compared to the three and six months endedJune 30, 2010.  

50

Capital Expenditures. Capital expenditures for the three and six months endedJune 30, 2011 remained consistent as compared to the three and six months endedJune 30, 2010.  

Discontinued Operations.  On April 1, 2009, we sold our producer services line of business and classified the revenues minus the cost of natural gas and NGLs as discontinued operations.  During the six months endedJune 30, 2011 and the three and six months endedJune 30, 2010, this business generated revenues of less than $0.1 million and no cost of natural gas and NGLs. As of March 31, 2011, we ceased generating any revenue related to this business, due to us no longer receiving payments related to the volume of gas flows pursuant to the assigned contracts of this business.

On May 20, 2011, we sold our Wildhorse Gathering System. After transaction costs of approximately $0.2 million, we received net proceeds of approximately $6.1 million. We recorded a loss of $0.6 million on the sale, which is recorded as part of discontinued operations for the three and six months ended June 30, 2011. Further upward or downward adjustments to the purchase price may occur post-closing to reflect customary true-ups, including adjustments to reflect an effective date for the sale of March 1, 2011. For the three and six months endedJune 30, 2011, we generated revenues of $1.8 million and $6.7 million, respectively, and income from operations of $0.1 million and $0.6 million, respectively, attributable to the Wildhorse Gathering System. For the three and six months endedJune 30, 2010, we generated revenues of $6.3 million and $14.0 million, respectively, and income from operations of less than $0.1 million and $0.4 million, respectively. During the three and six months endedJune 30, 2011, we recorded a loss from discontinued operations of $0.4 million and income from discontinued operations of less than $0.1 million, respectively, attributable to the Wildhorse Gathering System. During the three and six months endedJune 30, 2010, we recorded income from discontinued operations of less than $0.1 million and $0.4 million, respectively. During each of the three and six months endedJune 30, 2011 and 2010, this system incurred state tax expense of less than $0.1 million.

51

Gulf of Mexico Segment

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Sales of natural gas, NGLs, oil and condensate	$	10,697		$	7,255		$	18,631		$	15,679
Gathering and treating services	102			173			266			608
Total revenues	10,799			7,428			18,897			16,287
Cost of natural gas and NGLs	9,086			6,393			15,978			13,858
Operating costs and expenses:
Operations and maintenance	444			531			899			1,036
Depreciation and amortization	1,664			1,567			3,330			3,170
Total operating costs and expenses	2,108			2,098			4,229			4,206
Operating loss	$	(395	)	$	(1,063	)	$	(1,310	)	$	(1,777	)
Capital Expenditures	$	—		$	5		$	34		$	18
Realized average prices:
NGLs (per Bbl)	$	61.23		$	43.86		$	57.26		$	46.24
Production volumes:
Gathering volumes (Mcf/d)(a)	115,581			97,926			113,040			100,096
NGLs and condensate (net equity barrels)	26,373			24,078			50,532			49,966

________________________

(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 NGLs. During the three and six months endedJune 30, 2011, the Gulf of Mexico Segment contributed $1.7 million and $2.9 million, respectively, in revenues minus cost of natural gas and NGLs compared to $1.0 million and $2.4 million, respectively, in the three and six months endedJune 30, 2010.  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 October 2010. Our ownership in North Terrebonne Plant increased to 2.63% in January 2011 from 1.67% for 2010.

Operating Expenses.  Operating expenses for the three and six months endedJune 30, 2011 decreased $0.1 million and $0.1 million, respectively, compared to the three and six months endedJune 30, 2010.

Depreciation and Amortization. Depreciation and amortization expenses for the three and six months endedJune 30, 2011 increased $0.1 million and $0.2 million, respectively, compared to the three and six months endedJune 30, 2010.

Capital Expenditures. Capital expenditures for the three and six months endedJune 30, 2011 remained consistent as compared to the three and six months endedJune 30, 2010.

52

Upstream Segment

	Three Months Ended June 30,						Six Months Ended June 30,
	2011(a)			2010			2011(a)		2010
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Oil and condensate (b) (c)	$	24,193		$	12,377		$	39,054	$	23,362
Natural gas (d)	11,886			4,733			15,280		9,365
NGLs (e)	11,826			5,290			17,492		11,254
Sulfur (f)	4,684			2,112			7,724		3,180
Other	(244		)	(251		)	1,265		(215		)
Total revenues	52,345			24,261			80,815		46,946
Operating Costs and expenses:
Operations and maintenance (g)	10,584			8,010			18,632		17,302
Sulfur disposal costs	—			914			—		729
Depletion, depreciation and amortization	15,180			9,058			22,410		17,623
Impairment	—			—			324		—
Total operating costs and expenses	25,764			17,982			41,366		35,654
Operating income	$	26,581		$	6,279		$	39,449	$	11,292
Capital expenditures	$	19,158		$	7,414		$	24,820	$	12,392
Realized average prices (i):
Oil and condensate (per Bbl)	$	88.67		$	63.11		$	83.17	$	61.36
Natural gas (per Mcf)	$	3.74		$	4.08		$	3.81	$	4.65
NGLs (per Bbl)	$	58.29		$	43.92		$	57.61	$	47.28
Sulfur (per Long ton) (h)	$	182.73		$	102.96		$	174.70	73.34
Production volumes:
Oil and condensate (Bbl)	272,850			203,767			469,584		401,232
Natural gas (Mcf)	3,165,060			1,022,627			3,997,365		1,965,090
NGLs (Bbl)	206,251			132,085			305,609		252,503
Total (Mcfe)	6,039,672			3,037,739			8,648,524		5,887,500
Sulfur (Long ton) (h)	25,268			33,191			43,803		52,307

________________________

(a) Includes operations related to the Mid-Continent Acquisition starting on May 3, 2011

(b) Includes sales of oil and condensate to the Texas Panhandle Segment of $13,021 and $22,524 for the three and six months endedJune 30, 2011 respectively.

(c) Revenues include a change in the value of product imbalances by $181 for the three months endedJune 30, 2010.

(d) Revenues include a change in the value of product imbalances by $53, $60, $845 and $567 for the three and six months endedJune 30, 2011 and 2010, respectively.

(e) Revenues include a change in the value of product imbalances by $(195) and $(115) for the three and six months endedJune 30, 2011, respectively.

(f) Revenues include a change in the value of product imbalances by $66 and $71 for the three and six months endedJune 30, 2011, respectively.

(g) Includes purchase of natural gas of $24 and $66 from the South Texas Segment for the three and six months endedJune 30, 2011, respectively.

(h) During the six months endedJune 30, 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.

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

Revenue. For the three and six months endedJune 30, 2011, Upstream Segment revenues increased by $28.1 million and $33.9 million, respectively, as compared to the three and six months endedJune 30, 2010.  The addition of production volumes from the Crow Creek Acquisition with a May 3, 2011 closing date positively impacted the Upstream Segment's revenues by $14.9 million during the three and six months endedJune 30, 2011. The increase in revenue was also due to higher realized prices for oil, NGLs and sulfur during three and six months endedJune 30, 2011 compared to the three and six months endedJune 30, 2010. This increase was partially offset by the shut-in of our East Texas production beginning August 11, 2010

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through March 11, 2011. From May 3, 2011 to June 30, 2011, the Mid-Continent properties contributed 2.4 Bcf natural gas, 60 Mbbl oil and 63 Mbbl of NGLs to the Upstream Segment's total production.

In August 2010, we announced that our East Texas oil and natural gas production was temporarily shut-in due to an unscheduled shut-down of the Eustace processing facility owned and operated by a third-party. The shut-down 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 shut-down would take 30 to 45 days to complete, but the facility was not brought back into service until March 11, 2011. The shut-in negatively impacted our net revenues from January 1, 2011 to March 11, 2011 by approximately $3.9 million (excluding recoveries). As of June 30, 2011, we had recognized $5.0 million related to our business interruption insurance claim in other revenue, of which $2.0 million was recognized in the three months ended March 31, 2011 and $3.0 million was recognized in the fourth quarter of 2010. The maximum recovery under our business interruption insurance policy is $5.0 million per occurrence.

During the three and six months endedJune 30, 2011, sulfur revenue was $4.7 million and $7.7 million, respectively, as compared to $2.1 million and $3.2 million, respectively, during the three and six months endedJune 30, 2010. Historically, sulfur was viewed as a low value by-product in the production of oil and natural gas. During the three and six months endedJune 30, 2011, we saw a recovery in sulfur prices, with prices ranging from $185 per long ton on February 10, 2011 to $220 per long ton on August 1, 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 from the Tampa, Florida market our product is produced. 

Operating Expenses. Operating expenses, including severance and ad valorem taxes, increased by $2.6 million and $1.3 million, respectively, for the three and six months endedJune 30, 2011, as compared to the three and six months endedJune 30, 2010.  The increase for the three and six months endedJune 30, 2011 is primarily due to expenses of $2.0 million incurred from May 3, 2011 through June 30, 2011 related to the Mid-Continent properties and increased severance taxes as a result of the increase in revenue.

Depletion, Depreciation and Amortization. Depletion, depreciation and amortization expense increased by $6.1 million and $4.8 million, respectively, for the three and six months endedJune 30, 2011, as compared to the same period in the prior year.  The increase was primarily due to $5.8 million of depletion expense incurred for operations from the Mid-Continent Acquisition during the three and six months ended June 30, 2011. This increase was partially offset for the six months ended June 30, 2011 due to decreases in production as a result of our East Texas wells being shut-in, as discussed above.

Impairment.  Impairment charges of $0.3 million incurred during the six months endedJune 30, 2011 related to certain drilling locations in our unproved properties which we no longer intend to develop based on the performance of offsetting wells. During the three months ended June 30, 2011 and the three and six months endedJune 30, 2010, we did not incur any impairment charges.

Capital Expenditures.  Capital expenditures increased by $11.7 million and $12.4 million, respectively, for the three and six months endedJune 30, 2011, as compared to the three and six months endedJune 30, 2010.   During the three and six months ended June 30, 2011, we spent approximately $14.1 million of capital expenditures associated with the drilling and completion of  7 operated wells and 22 non-operated wells on leases acquired from our Crow Creek Acquisition.  In addition, for the three months ended June 30, 2011, we spent $1.9 million of capital expenditures on the drilling and completion of 2 operated wells and 1 non-operated well, $2.0 million of capital expenditures on 8 recompletions and capital workovers, and $1.2 million on lesser plant, facilities and leasing projects all associated with our legacy assets.  As of June 30, 2011, the segment is operating two drilling rigs in the Mid-Continent area and is participating with a non-operated working interest in 5 additional drilling rigs.

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Corporate and Other Segment

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	($ in thousands)
Revenues:
Realized commodity derivative losses	$	(8,813	)	$	(5,813	)	$	(15,260	)	$	(8,496	)
Unrealized commodity derivative gains (losses)	43,151			41,405			(10,847		)	54,883
Intersegment elimination - Sales of natural gas, oil and condensate	(13,021		)	—			(22,524		)	—
Total revenues	21,317			35,592			(48,631		)	46,387
Intersegment elimination - Cost of oil and condensate	(13,903		)	—			(20,992		)	—
General and administrative	15,902			12,806			27,678			25,817
Intersegment elimination - Operations and maintenance	(24		)	—			(66		)	—
Other operating income	(2,893		)	—			(2,893		)	—
Depreciation and amortization	320			482			707			835
Operating income (loss)	21,915			22,304			(53,065		)	19,735
Other income (expense):
Interest income	3			173			6			175
Interest expense	(6,311		)	(4,384		)	(9,535		)	(8,798		)
Unrealized interest rate derivative (losses) gains	2,791			(4,354		)	5,356			(9,176		)
Realized interest rate derivative losses	(4,434		)	(4,952		)	(9,661		)	(9,842		)
Other (expense) income	(114		)	(21		)	(164		)	78
Total other income (expense)	(8,065		)	(13,538		)	(13,998		)	(27,563		)
Income (loss) from continuing operations before taxes	13,850			8,766			(67,063		)	(7,828		)
Income tax (benefit) provision	(691		)	(425		)	(733		)	274
Income (loss) from continuing operations	14,541			9,191			(66,330		)	(8,102		)
Discontinued operations, net of tax	138			39,463			404			43,267
Segment income (loss)	$	14,679		$	48,654		$	(65,926	)	$	35,165

Revenue. Our Corporate and Other Segment's revenue consists of our intersegment eliminations and our commodity derivatives activity. Our commodity derivatives activities impact our Corporate and Other 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 three and six months endedJune 30, 2011, we experienced significant unrealized gains in our commodity derivative portfolio due to the hedging contracts we assumed in the Crow Creek Acquisition and to decreases in the crude oil and NGL forward curves, partially offset by increases in the natural gas forward curve.  This compares to the unrealized loss in our commodity derivative portfolio for the three months endedJune 30, 2011 and an unrealized gain in our commodity derivative portfolio for the six months endedJune 30, 2010. Included with our unrealized commodity derivative gains (losses) for the three and six months endedJune 30, 2010, are the amortization of put premiums and other derivative costs, including the costs of hedge resets, of $0.4 million and $3.1 million, respectively.

We recognized realized commodity derivative losses during both the three and six months endedJune 30, 2011 and 2010. The increase in the realized losses for the three and six months endedJune 30, 2011, as compared to the same period in the prior year, was due to higher crude oil and NGL market prices during the three and six months endedJune 30, 2011, in relation to the strike prices of our settled contracts, as compared to the same period in the prior year. The increase in the

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realized losses for three and six months endedJune 30, 2011 was partially offset by the net realized gains recorded for the derivative contracts assumed in the Crow Creek Acquisition that settled during the period.

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 three and six months endedJune 30, 2011, our South Texas Segment within our Midstream Business sold natural gas to our Upstream Segment to be used as fuel, and our Upstream Segment sold oil and condensate to the marketing group within our Midstream Business for resale.

General and Administrative Expenses. General and administrative expenses increased by $3.1 million and $1.9 million, respectively, for the three and six months endedJune 30, 2011 as compared to the same periods in 2010. This increase was partially due to an increase in salaries and benefits of $1.6 million and $2.4 million due to increased headcount over the last 12 months. The increase in salaries and benefits was offset by a decrease in equity-based compensation expense of approximately $0.5 million and $1.4 million, respectively, during the three and six months endedJune 30, 2011, as compared to the three and six months endedJune 30, 2010, primarily as a result of natural run-off (through vesting) of restricted common units granted in prior periods at higher prices. In addition, included within our general and administrative expenses for the three and six months endedJune 30, 2011 are legal and other professional advisory fees of $2.3 million related to the Crow Creek Acquisition, while the three and six months endedJune 30, 2010 include $0.6 million and $1.5 million, respectively, of legal and other professional advisory fees related to the recapitalization and related transactions and the associated lawsuit.

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

Other Operating Income. 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 the Texas Panhandle and East Texas midstream systems to SemGroup. As a result of the bankruptcy, we took a $10.7 million bad debt charge during the year ended December 31, 2008, which was included in “Other Operating Expense” in the consolidated statement of operations. In August 2009, we sold $3.9 million of our outstanding receivables from SemGroup, which represented its 20-day administrative claims under 503(b)(9) of the United States Bankruptcy Code, for which we received a payment of $3.0 million. Due to certain repurchase obligations under the assignment agreement, we recorded the payment as a current liability within accounts payable as of December 31, 2010 and maintained the balance as a liability until it was clear that the repurchase obligations can no longer be triggered. Due to the expiration of the repurchase obligations during the three months ended June 30, 2011, we released our reserve for these receivables and recorded other operating income of $2.9 million related to these reserves.

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 and our senior unsecured notes. On June 22, 2011, we terminated a $150 million notional amount 2.56% fixed rate interest rate swap at a total cost of $5.0 million, and extended the maturity of $250 million notional amount of our 4.095% fixed rate interest rate swaps from December 31, 2012 to June 22, 2015 with a fixed rate of 2.95%. During 2011, our realized settlements decreased by about $0.5 million and $0.2 million, respectively, as compared to 2010, as a result of increased LIBOR rates in 2011 and due to the two transactions described above. For the three and six months endedJune 30, 2011, we recognized an unrealized gain of $2.8 million and $5.4 million, respectively, as compared to unrealized losses of $4.4 million and $9.2 million, respectively, during the same period in 2010, as a result of an increase in 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 increased by $1.9 million and $0.7 million, during the three and six months endedJune 30, 2011, respectively, 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.  On May 27, 2011, we issued $300 million of senior unsecured notes with a coupon of 8 3/8% through a private placement, and on June 22, 2011, we entered into an Amended and Restated Credit Agreement (see Note 8 to our unaudited condensed consolidated financial statements), which bears interest currently at LIBOR plus 2.25%.  The increase in interest expense is due to the transactions discussed above and to higher LIBOR rates during 2011, as compared to the same period in 2010.

Income Tax (Benefit) Provision. Income tax provision for 2011 and 2010 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

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Redman Energy Corporation in 2008) and Eagle Rock Energy Acquisition Co. II, Inc. (acquiring entity of certain entities acquired in the Stanolind Acquisition) and their wholly-owned subsidiary 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 three and six months endedJune 30, 2011, our tax benefit increased by $0.3 million and $1.0 million, respectively, 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.   

Discontinued Operations. On May 24, 2010, we completed the sale of our fee mineral and royalty interests as well as our equity investment in Ivory Working Interests, L.P. (collectively, the "Minerals Business"). During the three and six months endedJune 30, 2011, we received payments of $0.1 million and $0.4 million, respectively, related to pre-effective date operations and recorded this amount as part of discontinued operations. For the three and six months endedJune 30, 2010, we generated revenues of $3.3 million and $8.9 million, respectively, and income from operations of $1.8 million and $5.6 million. During the three and six months endedJune 30, 2010, we recorded income to discontinued operations of $2.2 million and $6.0 million, respectively.

Adjusted EBITDA

Adjusted EBITDA, as defined under "- Non-GAAP Financial Measures," increased by $22.5 million and $22.0 million from $31.5 million and $62.3 million, respectively, for the three and six months endedJune 30, 2010 to $53.9 million and $84.2 million, respectively, for the three and six months endedJune 30, 2011.

As described above, revenues minus cost of natural gas and NGLs for the Midstream Business (including the Texas Panhandle, East Texas/Louisiana, South Texas and Gulf of Mexico Segments) increased by $3.4 million and $3.9 million, respectively, during the three and six months endedJune 30, 2011, as compared to the comparable period in 2010. The Upstream Segment revenues increased $29.2 million and $34.4 million, respectively, during the three and six months endedJune 30, 2011, as compared to the comparable periods in 2010. Intercompany eliminations revenues minus cost of natural gas and NGLs resulted in a $0.9 million increase and $1.5 million decrease, respectively. Our Corporate and Other Segment's realized commodity derivatives loss decreased by $3.0 million and $6.8 million, respectively, during the three and six months endedJune 30, 2011 as compared to the comparable period in 2010. This resulted in total incremental revenues minus cost of natural gas and NGLs increasing by $30.5 million and $30.1 million, respectively, during the three and six months endedJune 30, 2011 as compared to the comparable periods in 2010.  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 $2.8 million and $4.3 million, respectively, for the three and six months endedJune 30, 2011, as compared to the same period in 2010, and operating expenses (including taxes other than income) for the Upstream Segment increased $1.7 million and $0.6 million, respectively, for the three and six months endedJune 30, 2011, as compared to the comparable period in 2010.

General and administrative expense, excluding the impact of non-cash compensation charges related to our long-term incentive program and other non-recurring items and captured within our Corporate and Other Segment, increased during the three and six months endedJune 30, 2011 by $3.6 million and $3.2 million, respectively, as compared to the respective period in 2010.

As a result, revenues (excluding the impact of unrealized commodity derivative activity) minus cost of natural gas and NGLs for the three and six months endedJune 30, 2011, as compared to the same period in 2010 increased by $30.5 million and $30.1 million, respectively, operating expenses increased by $4.4 million and $4.0 million, respectively, and general and administrative expenses increased by $3.6 million and $3.2 million, respectively.  The increases in revenues minus the cost of natural gas and NGLs, the increases in operating costs and the increases in general and administrative expenses resulted in a increase to Adjusted EBITDA during the three and six months endedJune 30, 2011, as compared to the three and six months endedJune 30, 2010. Adjusted EBITDA excludes amortization of commodity hedge costs (including costs of hedge reset transactions) for the three and six months endedJune 30, 2010 of $0.4 million and $3.1 million, respectively.   Including these amortization costs, our Adjusted EBITDA for the three and six months endedJune 30, 2010 would have been $31.0 million and $59.2 million, respectively.

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LIQUIDITY AND CAPITAL RESOURCES

Historically, our sources of liquidity have included cash generated from operations, issuances of equity and debt securities through private offerings and borrowings under our revolving credit facility, and our primary cash requirements have included general administrative and operating expenses, maintenance and growth capital expenditures, short-term working capital needs, interest payments on our outstanding debt, distributions to our unitholders and acquisitions of new assets or businesses. In 2010, we raised additional liquidity through a series of transactions that included the sale of our Minerals Business for approximately $171.6 million and a rights offering through which the Partnership received net proceeds of approximately $53.9 million. As part of the rights offering, we issued approximately 21.6 million warrants entitling holders the right to purchase a common unit of Eagle Rock Energy for a price of $6.00 through May 2012. During the six months endedJune 30, 2011, 7,649,544 warrants were exercised for which the Partnership received proceeds of $45.9 million. A total of approximately 13.0 million warrants remained outstanding as of June 30, 2011.

On May 27, 2011, we completed the sale of $300 million of our senior unsecured notes (the "Senior Notes") through a private placement. The Senior Notes carry a coupon of 8 3/8%. The Senior Notes will mature on June 1, 2019, and interest is payable on each June 1 and December 1, commencing December 1, 2011. We used the net proceeds of approximately $290.3 million to repay borrowings outstanding under our revolving credit facility. See Note 8 to our unaudited condensed consolidated financial statements for a further description of our Senior Notes.

We believe that our historical sources of liquidity, including additional proceeds from warrant exercises, will be sufficient to fund our 2011 capital budget and to satisfy our short-term liquidity needs. With the acquisition of the Crow Creek properties, however, we expect the level of organic growth spending in our Upstream Business will increase substantially. We also intend to continue to pursue attractive development and acquisition opportunities in the midstream and upstream sectors. Accordingly, we may utilize various additional financing sources available to us, including the issuance of equity or debt securities through public offerings or private placements, to fund a portion of our organic growth expenditures and acquisitions. Our ability to complete future offerings of equity or debt securities and the timing of these offerings will depend upon various factors including prevailing market conditions and our financial condition.

Capital Expenditures

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 Midstream 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 Midstream assets and extend their useful lives, or to maintain production in our Upstream Business.

Our 2011 capital budget, which excludes the Crow Creek Acquisition, anticipates that we will spend approximately $218 million in total in 2011 on capital expenditures, including approximately $38 million related to the installation of the Woodall Plant as discussed in "Subsequent Events." Our capital expenditures, excluding acquisitions, were approximately $29.2 million and $43.3 million, respectively, for the three and six months endedJune 30, 2011. On May 3, 2011, we completed the Crow Creek Acquisition for a total purchase price of $563.7 million.

The Partnership expects its capital expenditures to increase in response to environmental compliance associated with sulfur dioxide (SO₂) emissions.  The Partnership has certain permit obligations to lower its SO₂ emissions at its Alabama plant operations.  Additionally, in mid-2010, the Environmental Protection Agency (“EPA”) enacted new National Ambient Air Quality Standards (“2010 NAAQS”) which substantially lowered the emissions limits for SO₂ and mandated timelines for compliance.  In order to fulfill its permit obligations and comply with the new 2010 NAAQS requirements, the Partnership expects to spend in excess of $40 million over the next several years to enhance its SO₂ recovery capabilities at its Alabama operations.  The expected facility upgrades to Eagle Rock's Alabama operations should not only increase the marketable sulfur recovered from the inlet gas stream, but also are anticipated to reduce plant fuel consumption, improve the plant's operating reliability and extend the plant's operating life. Management does not anticipate, however, that the required spending will generate returns consistent with the Partnership's internal rate of return thresholds for discretionary capital investment. At this time, management has identified no other operational areas impacted by the 2010 NAAQS.

Management expects a substantial percentage of the total capital invested to achieve the SO₂ emissions standard at the

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

Distribution Policy

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.

Revolving Credit Facility

On June 22, 2011, we entered into an Amended and Restated Credit Agreement (the “Credit Agreement”) with Wells Fargo Bank, National Association, as administrative agent and swingline lender, Bank of America, N.A. and The Royal Bank of Scotland plc, as co-syndication agents, BNP Paribas, as documentation agent, and the other lenders who are parties to the Credit Agreement. The Credit Agreement amended and restated our prior $880 million Credit Agreement (the “Prior Credit Agreement”). Upon the effectiveness of the Credit Agreement, all commitments of the lenders party to the Prior Credit Agreement were terminated and all loans and other indebtedness of the Partnership under the Prior Credit Agreement were renewed and extended, inclusive of new lender commitments, on the terms and conditions of the Credit Agreement. The Credit Agreement matures on June 22, 2016.

The credit facility under the Credit Agreement consists of aggregate initial commitments of $675 million that may, at our request and subject to the terms and conditions of the Credit Agreement, be increased up to a total aggregate amount of $1.2 billion. Availability under the credit facility is subject to a borrowing base comprised of two components: the upstream component and the midstream component. The initial borrowing base is $675 million. As of June 30, 2011, we had approximately $218.4 million of availability under the credit facility.

Debt Covenants

At June 30, 2011, 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 5.4 as compared to a minimum interest coverage covenant of 2.5, our leverage ratio, as defined in the Credit Agreement (i.e., Total Funded Indebtedness divided by Consolidated EBITDA), was 3.4 as compared to a maximum leverage ratio of 4.5 and a current ratio, as defined in the Credit Agreement was 2.3 as compared to a minimum current ratio covenant of 1.0.  We believe that we will remain in compliance with our financial covenants through 2011.

Our goal is to reduce our ratio of outstanding debt to Adjusted EBITDA, or “leverage ratio,” to approximately 3.0 to 3.5 on a sustained basis. We believe this leverage ratio range to be appropriate for our business.  We expect our efforts to reduce our leverage ratio to our desired range during 2011 will be primarily through investing in attractive growth opportunities that will increase our Adjusted EBITDA. We also expect our leverage ratio to benefit from any exercise of our approximately 13.0 million warrants outstanding as of June 30, 2011, which carry an exercise price of $6.00 per common unit and expire on May 15, 2012. Proceeds to us from the remaining warrants, if exercised in full, would total approximately $78 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.

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For a detailed description of our Credit Agreement, see Note 8 to our unaudited condensed consolidated financial statements.

Cash Flows

Cash Distributions

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 the close of business on February 7, 2011. The distribution was paid on February 14, 2011.

On April 26, 2011, we declared our first quarter 2011 cash distribution of $0.15 per unit to our common unitholders of record as of the close of business on May 9, 2011, except for the common units issued in connection with the acquisition of Crow Creek Energy on May 3, 2011 (see further discussion within "- Overview - Acquisitions"), which were not eligible to receive the first quarter 2011 distribution. This distribution was paid on May 13, 2011.

On July 27, 2011, we declared our second quarter 2011 cash distribution of $0.1875 per unit to our common unitholders of record as of the close of business on August 5, 2011. The distribution will be paid on August 12, 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 June 30, 2011, working capital was a negative $61.1 million as compared to a negative $54.2 million as of December 31, 2010.

The net decrease in working capital of $6.9 million from December 31, 2010 to June 30, 2011 resulted primarily from the following factors:

• cash balances and marketable securities increased overall by $2.8 million;

• trade accounts receivable increased by $18.9 million primarily from the impact of the Crow Creek Acquisition and higher revenues due to higher commodity prices;

• risk management net working capital balance increased by a net $11.0 million as a result of derivative contracts acquired as part of the Crow Creek Acquisition and changes in current portion of mark-to-market unrealized positions as a result of decreases to the forward crude oil and NGL price curves;

• accounts payable increased by $38.1 million from December 31, 2010 primarily as a result of the Crow Creek Acquisition, activities and timing of payments, including capital expenditures activities; and

• accrued liabilities increased by $1.6 million primarily reflecting payment of employee benefit accruals, higher interest payments and the timing of payment of unbilled expenditures related primarily to capital expenditures.

Cash Flows for the Six Months Ended June 30,2011 Compared to the for the Six Months Ended June 30,2010

Cash Flow from Operating Activities. Cash flows from operating activities decreased $17.0 million during the six months endedJune 30, 2011 as compared to the six months endedJune 30, 2010. This decrease was primarily due to our payment of $5.0 million to unwind an interest rate derivative contract, a payment of $4.8 million to unwind certain commodity derivative contracts and a payment to $14.6 million to adjust the strike price on certain existing commodity derivative contracts to the forward market price as of the date of the adjustment, as compared to a payment of $5.9 million during the six months ended June 30, 2010 to adjust the strike price on an existing commodity derivative contract to the forward market price as of the date the adjustment was executed. These payments were partially offset by an increase in our results of operations due to our Crow Creek Acquisition and higher commodity prices, which resulted in higher cash flows from the sale of our equity crude oil 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 the six months ended June 30, 2011.

Cash Flows from Investing Activities. Cash flows used in investing activities for the six months endedJune 30, 2011 were $246.7 million as compared to cash flows provided by investing activities of $146.8 million for the six months endedJune 30, 2010. The key difference between periods is our cash outlay of $220.3 million for the Crow Creek Acquisition during six months endedJune 30, 2011, as compared to the net proceeds of $171.6 million received from the sale of our Minerals

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Business during six months endedJune 30, 2010. In addition, we incurred increased cash outlays of $7.3 million for capital expenditures, in particular spending related to our Arrington Ranch - Phoenix Plant, partially offset by proceeds from the sale of our Wildhorse Gathering System of $6.1 million during the six months endedJune 30, 2011.  

Cash Flows from Financing Activities. Cash flows provided by financing activities during the six months endedJune 30, 2011 were $224.0 million as compared to cash flows used in financing activities of $194.2 million for the six months endedJune 30, 2010. Key differences between periods include net repayments to our revolving credit facility of $82.0 million during the six months endedJune 30, 2011 as compared to net repayments of $189.0 million to our revolving credit facility during the six months endedJune 30, 2010.  We also received $297.8 million from to the sale of our Senior Notes during the six months ended June 30, 2011. Cash outflows related to our distributions increased to $26.3 million during the six months endedJune 30, 2011 as compared to $3.0 million during the six months endedJune 30, 2010 as a result of increasing our quarterly distribution from $0.025 for the payments made in the first two quarters of 2010 (for the fourth quarter of 2009 and the first quarter of 2010) to $0.15 paid in the first two quarters of 2011 (for the fourth quarter of 2010 and the first quarter of 2011). We also received $45.9 million due to the exercise of warrants during the six months endedJune 30, 2011.

Hedging Strategy

We use a variety of hedging instruments such as fixed-price swaps, costless collars and put options to manage our risks related to our commodity price and interest rate exposure. At times our hedging strategy may involve adjusting strike prices of existing hedges to better reflect current market conditions or to meet other corporate 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. Under this strategy, and in conjunction with the refinancing of our revolving credit facility, we novated a portfolio of calendar year 2011, 2012 and 2013 hedges from a counterparty that was not continuing as a lender under our revolving credit facility and, at a cost of $14.6 million, adjusted the strike price to reflect current market prices of the following novated hedges;

• The remainder of a calendar year 2011 252,000 gallon per month OPIS propane swap from $1.11 per gallon to $1.55 a gallon;

• The remainder of a calendar year 2011 5,000 barrel per month WTI crude oil swap from $75.00 per barrel to $95.44 per barrel;

• A calendar year 2012 20,000 barrel per month WTI crude oil swap from $76.00 per barrel to $97.42 per barrel;

• A calendar year 2013 20,000 barrel per month WTI crude oil swap from $90.20 per barrel to $98.01 per barrel; and

• A calendar year 2013 60,000 barrel per month WTI crude oil swap from $89.95 per barrel to $98.01 per barrel.

Off-Balance Sheet Obligations.

We have no off-balance sheet transactions or obligations. 

Total Contractual Obligations.

Since December 31, 2011, the material change in our total contractual obligations consisted of an increase in our total long-term debt from $530.0 million to $745.9 million as of June 30, 2011.  The increase is attributable in part to our issuance of $300 million of Senior Notes in May 2011.  Additionally, on June 22, 2011 we entered into a Credit Agreement pursuant to which all commitments of the lenders party to the Prior Credit Agreement were terminated and all loans and other indebtedness of the Partnership were renewed and extended through the new Credit Agreement.  For further description of the Senior Notes and Credit Agreement, see “Revolving Credit Facility" and "Debt Covenants" above.

Recent Accounting Pronouncements

In September 2009, the Financial Accounting Standards Board ("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 us on January 1, 2011 and did not have a material impact on our financial statements.

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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, which was adopted by us on January 1, 2011.

In May 2011, the FASB issued additional guidance which is intended to result in convergence between U.S. GAAP and International Financial Reporting Standards (“IFRS”) requirements for measurement of and disclosures about fair value. The amendments are not expected to have a significant impact on companies applying U.S. GAAP. Key provisions of the amendments include: a prohibition on grouping financial instruments for purposes of determining fair value, except when an entity manages market and credit risks on the basis of the entity’s net exposure to the group; an extension of the prohibition against the use of a blockage factor to all fair value measurements (that prohibition currently applies only to financial instruments with quoted prices in active markets); and a requirement that for recurring Level 3 fair value measurements, entities disclose quantitative information about unobservable inputs, a description of the valuation process used and qualitative details about the sensitivity of the measurements. In addition, for items not carried at fair value but for which fair value is disclosed, entities will be required to disclose the level within the fair value hierarchy that applies to the fair value measurement disclosed. This guidance is effective for interim and annual periods beginning after December 15, 2011. The adoption of this guidance is not expected to have a significant impact on our fair value measurements, financial condition, results of operations or cash flows.

Non-GAAP Financial Measures

We include in this report Adjusted EBITDA, a non-GAAP financial measure. We provide reconciliations of this non-GAAP financial measure to its most directly comparable financial measures as calculated and presented in accordance with U.S. 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 our financial statements such as investors, commercial banks and research analysts.  For example, the compliance covenant used by our lenders under our revolving credit facility which is designed to measure the viability of us and our ability to perform under the terms of our revolving credit facility uses our Adjusted EBITDA.  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. Our 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 us. 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. 

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 U.S. GAAP.

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Adjusted EBITDA does not include interest expense, income taxes or depreciation and amortization expense. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate net income. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net income determined under U.S. GAAP, as well as Adjusted EBITDA, to evaluate our performance and liquidity.

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The following table sets forth a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with U.S. GAAP:

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Reconciliation of Adjusted EBITDA to net cash flows provided by (used in) operating activities and net income:
Net cash flows provided by operating activities	$	6,059		$	25,269		$	25,693		$	42,662
Add (deduct):
Discontinued operations	(311		)	39,493			407			43,645
Depreciation, depletion, amortization and impairment	(36,136		)	(30,599		)	(60,158		)	(58,043		)
Amortization and write-offs of debt issuance costs and discounts	(806		)	(551		)	(1,046		)	(820		)
Risk management portfolio value changes	71,202			37,051			19,769			45,707
Reclassing financing derivative settlements	2,443			323			2,443			628
Other	2,273			(1,726		)	1,128			(4,207		)
Accounts receivable and other current assets	(18,434		)	(7,879		)	5,483			(8,711		)
Accounts payable, due to affiliates and accrued liabilities	28,208			7,646			7,020			10,482
Other assets and liabilities	573			(884		)	615			781
Net income	55,071			68,143			1,354			72,124
Add (deduct):
Interest (income) expense net	10,856			9,163			19,354			18,465
Depreciation, depletion, amortization and impairment	36,136			30,599			60,158			58,043
Income tax (benefit) provision	(691		)	(425		)	(733		)	274
EBITDA	101,372			107,480			80,133			148,906
Add:
Risk management portfolio value changes	(45,942		)	(37,051		)	5,491			(45,707		)
Restricted unit compensation expense	1,024			1,550			1,934			3,358
Non-cash mark-to-market Upstream imbalances	76			(1,033		)	(16		)	(567		)
Discontinued operations	311			(39,493		)	(407		)	(43,645		)
Other income	90			21			90			(78		)
Other operating income	(2,983		)	—			(2,983		)	—
ADJUSTED EBITDA(a)	$	53,948		$	31,474		$	84,242		$	62,267

________________________

(a)    Adjusted EBITDA excludes amortization of commodity hedge costs (including costs of hedge reset transactions) for the three and six months endedJune 30, 2010 of $0.4 million and $3.1 million, respectively.  Including these amortization costs, our Adjusted EBITDA for the three and six months endedJune 30, 2010 would have been $31.0 million and $59.2 million, respectively.

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Item 3.    Quantitative and Qualitative Disclosures About Market Risk.

Risk and Accounting Policies

We are exposed to market risks associated with adverse changes in commodity prices, interest rates and counterparty credit. We may use financial instruments such as put and call options, swaps and other derivatives to mitigate the effects of the identified risks. Adverse effects on our cash flow from changes in crude oil, natural gas, NGL product prices or interest rates could adversely impact our ability to make distributions to our unitholders, meet debt service obligations, fund required capital expenditures, and other similar requirements. Our management has established a comprehensive review of our market risks and has developed risk management policies and procedures to monitor and manage these market risks. Our general partner is responsible for the overall approval of market risk management policies, delegation of transaction authority levels, and for the establishment of a Risk Management Committee ("RMC"). The RMC is composed of officers (including, on an ex officio basis, our chief executive officer) who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The RMC is responsible for the overall management of commodity price risk, interest rate risk and credit risk, including monitoring exposure limits.

Commodity Price Risk

We are exposed to the impact of market fluctuations in the prices of crude oil, natural gas, NGLs and other commodities as a result of our gathering, processing, producing and marketing activities, which produce a naturally long position in these commodities. Our profitability and cash flow are affected by changes in prices of these commodities. These prices are impacted by changes in the supply and demand for these commodities, as well as market uncertainty and other factors beyond our control. Historically, changes in the prices of NGLs have generally correlated with changes in the price of crude oil.

We manage this commodity price exposure through an integrated strategy that includes management of our contract portfolio, matching sales prices of commodities with purchases, optimization of our portfolio by monitoring basis and other price differentials in our areas of operations, and the use of derivative contracts. Crude oil, natural gas and NGL prices can also indirectly affect our profitability by influencing the level of drilling activity and related opportunities for our service.

We frequently use financial derivatives (“hedges”) to reduce our exposure to commodity price risk. We have implemented a Risk Management Policy which allows management to execute crude oil, natural gas liquids and natural gas hedging instruments, which may include swaps, collars, options and other derivatives, in order to reduce exposure to substantial adverse changes in the prices of these commodities. These hedges are only intended to mitigate the risk associated with our natural physical position. We monitor and ensure compliance with this Risk Management Policy through senior level executives in our operations, finance and legal departments.

We have not designated our contracts as accounting hedges based on authoritative guidance. As a result, we mark our derivatives to market with the resulting change in fair value being included in our statement of operations. For the three and six months endedJune 30, 2011, we recorded a gain on risk management instruments of $34.3 million and a loss of $26.1 million, respectively, representing a fair value (unrealized) gain of $43.2 million and a loss of $10.8 million and net (realized) settlement losses of $8.8 million and $15.3 million, respectively. For the three and six months endedJune 30, 2010, we recorded gains on risk management instruments of $35.6 million and $46.4 million, respectively, representing fair value (unrealized) gains of $41.4 million and $54.9 million, respectively, amortization of put premiums and other derivative costs of $0.4 million and $3.1 million, respectively, and net (realized) settlement losses of $5.8 million and $8.5 million, respectively. As of June 30, 2011, the fair value net liability of these commodity contracts, including put premiums and other derivative costs, totaled approximately $21.9 million.

We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.

In addition, we have recently begun operations through our natural gas marketing subsidiary. Though we intend for these activities to complement our existing operations, they may expose us to additional and different risks, as our activities are expected to be more comprehensive than our commodities derivative activities described above. To minimize our exposure to trading losses, we have established procedures to monitor and limit risk, including the use of value-at-risk metrics. 

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Interest Rate Risk

We are exposed to variable interest rate risk as a result of borrowings under our revolving credit facility. To mitigate its interest rate risk, we have 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. As of June 30, 2011, the notional amount of our interest rate swaps was in excess of our outstanding borrowings by approximately $2.0 million. Absent any change to our near term borrowing expectations, we plan to terminate a portion of our interest swaps to eliminate our over-hedged interest rate exposure.

We have not designated our contracts as accounting hedges. As a result, we mark our derivatives to market with the resulting change in fair value included in our statement of operations. For the three and six months endedJune 30, 2011, we recorded fair value (unrealized) gains of $2.8 million and $5.4 million, respectively, and realized losses of $4.4 million and $9.7 million, respectively. For the three and six months endedJune 30, 2010, we recorded fair value (unrealized) losses of $4.4 million and $9.2 million, respectively, and realized losses of $5.0 million and $9.8 million, respectively. As of June 30, 2011, the fair value liability of these interest rate contracts totaled approximately $24.2 million.

Credit Risk

Our principal natural gas sales customers are large gas marketing companies that, in turn, typically sell to large end users such as local distribution companies and electrical utilities. With respect to the sale of our NGLs and condensates, our principle customers are large natural gas liquids purchasers, fractionators and marketers, and large condensate aggregators that then typically sell to large multi-national petrochemical and refining companies. We also sell a small amount of propane to medium sized, local distributors.

This concentration of credit risk may affect our overall credit risk in that these customers may be similarly affected by changes in the natural gas, natural gas liquids, petrochemical and other segments of the energy industry, the economy in general, the regulatory environment and other factors.

Our derivative counterparties include BNP Paribas, Wells Fargo Bank, National Association, Comerica Bank, Bank of Nova Scotia, The Royal Bank of Scotland plc, Bank of America N.A., J Aron & Company (an affiliate of Goldman Sachs) and BBVA Compass Bank.

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Item 4.    Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Based on the evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) required by Exchange Act Rules 13a-15(b) or 15d-15(b), our principal executive officer and principal financial officer have concluded that as of the end of the period covered by this report, our disclosure controls and procedures were effective at the reasonable assurance level to ensure that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including the principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the second quarter of 2011, we completed the acquisition of CC Energy II L.L.C. Because of the timing of the acquisition, management anticipates that it will not include the internal control process for this entity in its 2011 internal control assessment included in our Annual Report for the year ended December 31, 2011. The acquisition is excluded from the certification required under Section 302 of the Sarbanes-Oxley Act of 2002. We will include all aspects of internal control over financial reporting for this acquisition, including changes to our internal controls over financial reporting based on this acquisition, in our 2012 assessment.

There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d - 15(f) under the Exchange Act) that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1.    Legal Proceedings.

Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we are and

may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business.

However, we are not currently a party to any material litigation. We maintain insurance policies with insurers in amounts and

with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and

prudent. We cannot, however, assure that this insurance will be adequate to protect us from all material expenses related to

potential future claims for personal and property damage or that these levels of insurance will be available in the future at

economical prices.

Item 1A.    Risk Factors.

In addition to the other information set forth in this quarterly report on Form 10-Q, you should carefully consider the risks discussed in our annual report on Form 10-K for the year ended December 31, 2010, under the headings “Item 1. Business,” “Item 1A. Risk Factors,” “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” which risks could materially affect our business, financial condition or future results. Except for the risk factors set forth below, there have been no material changes in our risk factors from those described in our annual report on Form 10-K for the year ended December 31, 2010.

Our operations will require substantial capital expenditures, which will reduce our cash available to pay distributions to unitholders. We may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a decline in our cash flows.

The oil and natural gas industry is capital intensive. We expect to continue to make substantial capital expenditures in our business for the maintenance, construction and acquisition of midstream assets and oil and natural gas reserves. We intend to finance our future capital expenditures with cash flows from operations, borrowings under our credit facility and the issuance of debt and equity securities, when market conditions allow. The incurrence of debt will require that a portion of our cash flows from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. Our cash flows from operations and access to capital are subject to a number of variables, including:

• volume throughput through our pipelines and processing facilities;

• the estimated quantities of our oil and natural gas reserves;

• the amount of oil and natural gas produced from existing wells;

• the prices at which we sell our production or that of our midstream customers;

• the strike prices of our hedges;

• our operating and general and administrative expenses; and

• our ability to acquire, locate and produce new reserves.

If our revenues or the borrowing base under our credit facility decrease as a result of lower commodity prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, or to pursue our growth strategy. Our credit facility may restrict our ability to obtain new financing. In addition, our Mid-Continent properties hold a substantial amount of proved undeveloped and unproved properties. We expect that the Crow Creek Acquisition will result in a meaningful increase in our capital expenditures with respect to the exploration and development of oil and natural gas properties. Our capital budget for the remainder of 2011 related to our Mid-Continent properties is expected to total approximately $63.5 million.

If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our capital projects, which in turn could lead to a possible decline in our gathering and processing available capacity or in our natural gas and crude oil reserves and production, which could adversely effect our business, results of operations, financial condition and ability to pay distributions to our unitholders. In addition, we may lose opportunities to acquire oil and natural gas properties and businesses.

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We have limited control over the activities on properties we do not operate, which includes a substantial number of the properties we acquired in the Crow Creek Acquisition.

Other companies operate some of the properties in which we have an interest, including the properties we acquired in the Crow Creek. We have less ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them versus those fields in which we are the operator. The success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be largely outside our control, including:

• the operator's expertise and financial resources;

• the timing and amount of their capital expenditures;

• the rate of production of the reserves;

• approval of other participants to drill wells and implement other work programs;

• the availability of suitable drilling rigs, drilling equipment, production and transportation infrastructure and qualified operating personnel; and

• selection of technology.

Our dependence on the operator and other working interest owners for these projects and our reduced influence or ability to control the operation and future development of these properties could materially adversely affect our business, results of operations, financial condition and ability to pay distributions to our unitholders.

The properties we acquired in the Crow Creek Acquisition are located in areas where we have not historically conducted upstream operations, which exposes us to additional risk.

Our Mid-Continent properties are located in North Texas, Oklahoma and Arkansas, all of which are areas where we have not historically conducted upstream operations. In addition, Mid-Continent's interests include properties in the emerging Cana Shale play in Oklahoma. Because we have limited production history in these geographic regions and do not have extensive experience in emerging unconventional resource plays like that Cana Shale, we are less able to use past operational results to help predict future results. Our lack of experience may result in our not being able to fully execute our expected drilling programs in this region, and the return on investment from our operations may not be as attractive as expected. We cannot assure you that our efforts will be successful, or if successful will achieve the resource potential levels that we currently anticipate or achieve the anticipated economic returns based on our current financial models. As a result, our business, results of operations, financial condition and ability to pay distributions to our unitholders may be affected.

We have recently begun conducting commodity derivatives trading activities, where we have limited experience, which exposes us to additional risks associated with selling and marketing products in energy markets.

We have recently begun conducting commodity derivatives trading activities through our natural gas marketing subsidiary, Eagle Rock Gas Services, LLC. Our portfolio of derivative and other energy contracts may consist of contracts to buy and sell commodities that are settled by the delivery of the commodity or cash. If the values of these contracts change in a direction or manner that we do not anticipate or cannot manage, it could negatively affect our results of operations. In the past, certain marketing and trading companies have experienced severe financial problems due to price volatility in the energy commodity markets. In certain instances this volatility has caused companies to be unable to deliver energy commodities that they had guaranteed under contract. If such a delivery failure were to occur in one of our contracts, we might incur additional losses to the extent of amounts, if any, already paid to, or received from, counterparties. In addition, our lack of experience in these activities may result in our not being able to execute our operations. As a result, our business, results of operations, financial condition and ability to pay distributions to our unitholders may be adversely affected.

Certain of our properties, including some of our operations in Oklahoma, are located on Native American tribal lands and are subject to various federal and tribal approvals and regulations, which may increase our costs and delay or prevent our efforts to conduct planned operations.

Various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs, Bureau of Land Management and the Office of Natural Resources Revenue, along with each Native American tribe, promulgate and enforce regulations pertaining to gas and oil operations on Native American tribal lands. These regulations and approval requirements relate to such matters as lease provisions, drilling and production requirements, environmental standards and royalty considerations. In addition, each Native American tribe is a sovereign nation having the right to enforce laws and regulations and to grant approvals independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees, requirements to employ Native American tribal members and other conditions that apply to lessees, operators and contractors

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conducting operations on Native American tribal lands. Lessees and operators conducting operations on tribal lands are generally subject to the Native American tribal court system. In addition, if our relationships with any of the relevant Native American tribes were to deteriorate, we could face significant risks to our ability to continue the projected development of our leases on Native American tribal lands. One or more of these factors may increase our costs of doing business on Native American tribal lands and impact the viability of, or prevent or delay our ability to conduct, our natural gas or oil development and production operations on such lands.

Item 2.    Unregistered Sales of Equity Securities and Use of Proceeds.

On May 3, 2011, we issued 28,753,174 common units in a private placement as partial consideration for our Acquisition of all of the outstanding membership interests of CC Energy II LLC.

The following table sets forth certain information with respect to repurchases of common units during the three months ended June 30, 2011:

Period	Total Number of Units Purchased	Average Price Paid Per Unit		Total Number of Units Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Units that May Yet Be Purchased Under the Plans or Programs
April 1, 2011 to April 30, 2011	—	—		—	—
May 1, 2011 to May 31, 2011	10,772	$	11.04	—	—
June 1, 2011 to June 30, 2011	—	—		—	—
Total	10,772	$	11.04	—	—

All of the units were surrendered by employees to pay tax withholding in connection with the vesting of restricted common units.  As a result, we are deeming the surrenders to be “repurchases.”  These repurchases were not part of a publicly announced program to repurchase our common units, nor do we have a publicly announced program to repurchase our common units.

Item 3.    Defaults Upon Senior Securities.

None.

Item 4.    [Removed and Reserved]

Item 5.    Other Information.

None.

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Item 6.    Exhibit

Exhibit Number	Description
2.1***	Membership Interest Contribution Agreement, by and among (i) CC Energy II L.L.C., Crow Creek Energy II L.L.C. and Crow Creek Operating Company II L.L.C., (ii) Natural Gas Partners VIII, L.P. and the other contributors party thereto and (iii) Eagle Rock Energy Partners, L.P., dated as of April 12, 2011 (incorporated by reference to Exhibit 2.1 to the Partnership's Current Report on From 8-K filed on April 13, 2011).
3.1	Certificate of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Partnership's Registration Statement on Form S-1 (File No. 333-134750)).
3.2	Second Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Partnership's Current Report on Form 8-K filed on May 25, 2010).
3.3	Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 4.1 to the Partnership's Current Report on Form 8-K filed on July 30, 2010).
3.4	Certificate of Limited Partnership of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.3 to the Partnership's Registration Statement on Form S-1 (File No. 333-134750)).
3.5	Limited Partnership Agreement of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.4 to the Partnership's Registration Statement on Form S-1 (File No. 333-134750)).
3.6	Certificate of Formation of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 3.5 to the Partnership's Registration Statement on Form S-1 (File No. 333-134750)).
3.7	Third Amended and Restated Limited Liability Company Agreement of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 4.2 to the Partnership's Current Report on Form 8-K filed with the Commission on July 30, 2010).
4.1	Indenture dated as of May 27, 2011 among Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Partnership's Current Report on Form 8-K filed with the Commission on May 27, 2011).
4.2	Registration Rights Agreement dated as of May 27, 2011 among Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.2 to the Partnership's Current Report on Form 8-K filed with the Commission on May 27, 2011).
4.3*	First Supplemental Indenture dated as of June 28, 2011, among Eagle Rock Gas Services, LLC, a subsidiary of Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and U.S. Bank National Association, as trustee.
10.1	Registration Rights Agreement dated May 3, 2011 by and between Eagle Rock Energy Partners, L.P. and Natural Gas Partners VIII, L.P. (incorporated by reference to Exhibit 10.1 to the Partnership's Current Report on Form 8-K filed with the Commission on May 3, 2011).
10.2	Voting Agreement dated May 3, 2011 by and between Eagle Rock Energy Partners, L.P. and Natural Gas Partners VIII, L.P. (incorporated by reference to Exhibit 10.2 to the Partnership's Current Report on Form 8-K filed with the Commission on May 3, 2011).
10.3	Amendments to certain company performance goals under the Eagle Rock Energy G&P, LLC 2011 Short Term Incentive Bonus Plan (incorporated by reference to Exhibit 10.3 to the Partnership's Current Report on Form 8-K filed with the Commission on May 3, 2011).
10.4	Purchase Agreement dated as of May 24, 2011 among Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 10.1 to the Partnership's Current Report on Form 8-K filed with the Commission on May 27, 2011).
10.5	Amended and Restated Credit Agreement, dated as of June 22, 2011, among Eagle Rock Energy Partners, L.P., as borrower, Wells Fargo Bank, National Association, as administrative agent and swingline lender, Bank of America, N.A. and The Royal Bank of Scotland plc, as co-syndication agents, and BNP Paribas, as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Partnership's Current Report on Form 8-K filed with the Commission on June 22, 2011).
31.1*	Certification of Periodic Financial Reports by Joseph A. Mills in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Periodic Financial Reports by Jeffrey P. Wood in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of Periodic Financial Reports by Joseph A. Mills in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of Periodic Financial Reports by Jeffrey P. Wood in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.

_______________________________

*    Filed herewith.

**    Furnished herewith 

***    The schedules to this agreement have been omitted from this filing pursuant to Item 601(b)(2) of Regulation S-K. The Partnership will furnish copies of such schedules to the Securities and Exchange Commission upon request.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Date: August 4, 2011	EAGLE ROCK ENERGY PARTNERS, L.P.
	By:	Eagle Rock Energy GP, L.P., its general partner
	By:	Eagle Rock Energy G&P, LLC, its general partner
	By:	/s/    Jeffrey P. Wood
	Name:	Jeffrey P. Wood
	Title:	Senior Vice President, Chief Financial Officer and Treasurer of Eagle Rock Energy G&P, LLC, General Partner of Eagle Rock Energy GP, L.P., General Partner of Eagle Rock Energy Partners, L.P.

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Index to Exhibits

Exhibit Number	Description
2.1***	Membership Interest Contribution Agreement, by and among (i) CC Energy II L.L.C., Crow Creek Energy II L.L.C. and Crow Creek Operating Company II L.L.C., (ii) Natural Gas Partners VIII, L.P. and the other contributors party thereto and (iii) Eagle Rock Energy Partners, L.P., dated as of April 12, 2011 (incorporated by reference to Exhibit 2.1 to the Partnership's Current Report on From 8-K filed on April 13, 2011).
3.1	Certificate of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Partnership's Registration Statement on Form S-1 (File No. 333-134750)).
3.2	Second Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Partnership's Current Report on Form 8-K filed on May 25, 2010).
3.3	Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 4.1 to the Partnership's Current Report on Form 8-K filed on July 30, 2010).
3.4	Certificate of Limited Partnership of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.3 to the Partnership's Registration Statement on Form S-1 (File No. 333-134750)).
3.5	Limited Partnership Agreement of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.4 to the Partnership's Registration Statement on Form S-1 (File No. 333-134750)).
3.6	Certificate of Formation of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 3.5 to the Partnership's Registration Statement on Form S-1 (File No. 333-134750)).
3.7	Third Amended and Restated Limited Liability Company Agreement of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 4.2 to the Partnership's Current Report on Form 8-K filed with the Commission on July 30, 2010).
4.1	Indenture dated as of May 27, 2011 among Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Partnership's Current Report on Form 8-K filed with the Commission on May 27, 2011).
4.2	Registration Rights Agreement dated as of May 27, 2011 among Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.2 to the Partnership's Current Report on Form 8-K filed with the Commission on May 27, 2011).
4.3*	First Supplemental Indenture dated as of June 28, 2011, among Eagle Rock Gas Services, LLC, a subsidiary of Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and U.S. Bank National Association, as trustee.
10.1	Registration Rights Agreement dated May 3, 2011 by and between Eagle Rock Energy Partners, L.P. and Natural Gas Partners VIII, L.P. (incorporated by reference to Exhibit 10.1 to the Partnership's Current Report on Form 8-K filed with the Commission on May 3, 2011).
10.2	Voting Agreement dated May 3, 2011 by and between Eagle Rock Energy Partners, L.P. and Natural Gas Partners VIII, L.P. (incorporated by reference to Exhibit 10.2 to the Partnership's Current Report on Form 8-K filed with the Commission on May 3, 2011).
10.3	Amendments to certain company performance goals under the Eagle Rock Energy G&P, LLC 2011 Short Term Incentive Bonus Plan (incorporated by reference to Exhibit 10.3 to the Partnership's Current Report on Form 8-K filed with the Commission on May 3, 2011).
10.4	Purchase Agreement dated as of May 24, 2011 among Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 10.1 to the Partnership's Current Report on Form 8-K filed with the Commission on May 27, 2011).
10.5	Amended and Restated Credit Agreement, dated as of June 22, 2011, among Eagle Rock Energy Partners, L.P., as borrower, Wells Fargo Bank, National Association, as administrative agent and swingline lender, Bank of America, N.A. and The Royal Bank of Scotland plc, as co-syndication agents, and BNP Paribas, as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Partnership's Current Report on Form 8-K filed with the Commission on June 22, 2011).
31.1*	Certification of Periodic Financial Reports by Joseph A. Mills in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Periodic Financial Reports by Jeffrey P. Wood in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of Periodic Financial Reports by Joseph A. Mills in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of Periodic Financial Reports by Jeffrey P. Wood in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.

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*    Filed herewith.

**    Furnished herewith 

***    The schedules to this agreement have been omitted from this filing pursuant to Item 601(b)(2) of Regulation S-K. The Partnership will furnish copies of such schedules to the Securities and Exchange Commission upon request.