EAGLE ROCK ENERGY PARTNERS L P - FORM 10-Q

EAGLE ROCK ENERGY PARTNERS L P - FORM 10-Q - May 6, 2011

Attached files

Attached files

EAGLE ROCK ENERGY PARTNERS L P Reports

file	filename
EX-31.2 - EXHIBIT 31.2 CERTIFICATION - EAGLE ROCK ENERGY PARTNERS L P	exhibit3121.htm
EX-32.2 - EXHIBIT 32.2 CERTIFICATION - EAGLE ROCK ENERGY PARTNERS L P	exhibit3221.htm
EX-32.1 - EXHIBIT 32.1 CERTIFICATION - EAGLE ROCK ENERGY PARTNERS L P	exhibit3211.htm
EX-31.1 - EXHIBIT 31.1 CERTIFICATION - EAGLE ROCK ENERGY PARTNERS L P	exhibit3111.htm

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 March 31, 2011



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)

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 o 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 89,805,534 common units outstanding as of May 2, 2011.

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		Page
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements	2
	Unaudited Condensed Consolidated Balance Sheets as of March 31, 2011 and December 31, 2010	2
	Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2011 and 2010	3
	Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2011 and 2010	5
	Notes to the Unaudited Condensed Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	52
Item 4.	Controls and Procedures	53
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	54
Item 1A.	Risk Factors	54
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	55
Item 3.	Defaults Upon Senior Securities	55
Item 4.	[Removed and Reserved]	55
Item 5.	Other Information	55
Item 6.	Exhibits	56

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

($ in thousands)



	March 31, 2011		December 31, 2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	51	$	4,049
Accounts receivable(a)	94,872		75,695
Prepayments and other current assets	7,238		2,498
Assets held for sale	7,895		8,615
Total current assets	110,056		90,857
PROPERTY, PLANT AND EQUIPMENT — Net	1,130,326		1,137,239
INTANGIBLE ASSETS — Net	111,473		113,634
DEFERRED TAX ASSET	1,886		1,969
RISK MANAGEMENT ASSETS	—		1,075
OTHER ASSETS	4,281		4,623
TOTAL	$	1,358,022	$	1,349,397

LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	114,889	$	91,886
Due to affiliate	48		56
Accrued liabilities	7,177		10,940
Taxes payable	1,208		1,102
Risk management liabilities	67,510		39,350
Liabilities held for sale	1,184		1,705
Total current liabilities	192,016		145,039
LONG-TERM DEBT	507,745		530,000
ASSET RETIREMENT OBLIGATIONS	25,015		24,711
DEFERRED TAX LIABILITY	38,336		38,662
RISK MANAGEMENT LIABILITIES	53,203		31,005
OTHER LONG TERM LIABILITIES	867		867
COMMITMENTS AND CONTINGENCIES (Note 12)
MEMBERS' EQUITY (b)	540,840		579,113
TOTAL	$	1,358,022	$	1,349,397

________________________


(a)	Net of allowance for bad debt of $4,425 as of March 31, 2011 and $4,496 as of December 31, 2010.


(b)	87,977,385 and 83,425,378 common units were issued and outstanding as of March 31, 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 1,788,449 and 1,744,454 as of March 31, 2011 and December 31, 2010, respectively.

See notes to unaudited condensed consolidated financial statements.

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EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

($ in thousands)



	Three Months Ended March 31,
	2011			2010
REVENUE:
Natural gas, natural gas liquids, oil, condensate and sulfur sales	$	203,055		$	192,001
Gathering, compression, processing and treating fees	13,245			12,483
Commodity risk management (losses) gains	(60,445		)	10,795
Other revenue	1,509			36
Total revenue	157,364			215,315
COSTS AND EXPENSES:
Cost of natural gas, natural gas liquids, and condensate	147,319			137,902
Operations and maintenance	19,475			18,871
Taxes other than income	3,316			3,534
General and administrative	11,776			13,011
Impairment expense	324			—
Depreciation, depletion and amortization	23,698			27,444
Total costs and expenses	205,908			200,762
OPERATING (LOSS) INCOME	(48,544		)	14,553
OTHER INCOME (EXPENSE):
Interest income	3			2
Other income	—			99
Interest expense	(3,224		)	(4,414		)
Interest rate risk management losses	(2,662		)	(9,712		)
Other expense	(50		)	—
Total other (expense) income	(5,933		)	(14,025		)
(LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(54,477		)	528
INCOME TAX (BENEFIT) PROVISION	(42		)	699
LOSS FROM CONTINUING OPERATIONS	(54,435		)	(171		)
DISCONTINUED OPERATIONS, NET OF TAX	718			4,152
NET (LOSS) INCOME	$	(53,717	)	$	3,981

See notes to unaudited condensed consolidated financial statements.

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EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (continued)

(in thousands, except per unit amounts)



	Three Months Ended March 31,
	2011			2010
NET (LOSS) INCOME PER COMMON UNIT—BASIC AND DILUTED:
(Loss) Income from Continuing Operations
Common units	$	(0.65	)	$	0.01
Subordinated units	$	—		$	(0.02	)
General partner units	$	—		$	0.01
Discontinued Operations
Common units	$	0.01		$	0.05
Subordinated units	$	—		$	0.05
General partner units	$	—		$	0.05
Net Income (Loss)
Common units	$	(0.64	)	$	0.06
Subordinated units	$	—		$	0.03
General partner units	$	—		$	0.06
Basic Weighted Average Units Outstanding (in thousands)
Common units	84,235			54,203
Subordinated units	—			20,691
General partner units	—			845
Diluted Weighted Average Units Outstanding (in thousands)
Common units	84,235			54,420
Subordinated units	—			20,691
General partner units	—			845

See notes to unaudited condensed consolidated financial statements.

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EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE THREE MONTHS ENDED MARCH 31, 2011 AND 2010

($ in thousands)



	Three Months Ended March 31,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income	$	(53,717	)	$	3,981
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Discontinued Operations	(718		)	(4,152		)
Depreciation, depletion and amortization	23,698			27,444
Impairment	324			—
Amortization of debt issuance costs	240			269
Equity in earnings of unconsolidated affiliates	5			(12		)
Distribution from unconsolidated affiliates—return on investment	21			15
Reclassing financing derivative settlements	—			(305		)
Equity-based compensation	910			1,808
Loss (gain) of sale of assets	45			(19		)
Other	164			689
Changes in assets and liabilities—net of acquisitions:
Accounts receivable	(19,177		)	1,555
Prepayments and other current assets	(4,740		)	(723		)
Risk management activities	51,433			(8,656		)
Accounts payable	25,107			255
Due to affiliates	—			(27		)
Accrued liabilities	(3,919		)	(3,064		)
Other assets	—			(1,618		)
Other current liabilities	(42		)	(47		)
Net cash provided by operating activities	19,634			17,393
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(16,135		)	(8,258		)
Proceeds from sale of asset	—			33
Purchase of intangible assets	(691		)	(580		)
Net cash used in investing activities	(16,826		)	(8,805		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	32,745			18,000
Repayment of long-term debt	(55,000		)	(35,000		)
Proceeds from derivative contracts	—			305
Exercise of warrants	27,312			—
Distributions to members and affiliates	(12,778		)	(1,328		)
Net cash used in financing activities	(7,721		)	(18,023		)
CASH FLOWS FROM DISCONTINUED OPERATIONS:
Operating activities	915			6,980
Investing activities	—			(128		)
Net cash provided by discontinued operations	915			6,852
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	(3,998		)	(2,583		)
CASH AND CASH EQUIVALENTS—Beginning of period	4,049			2,732
CASH AND CASH EQUIVALENTS—End of period	$	51		$	149

Interest paid—net of amounts capitalized	$	2,988		$	4,254
Cash paid for taxes	$	106		$	419
Investments in property, plant and equipment, not paid	$	8,810		$	3,972
Deferred tranasaction fees, not paid	$	—		$	594

See notes to unaudited condensed consolidated financial statements.

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EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY

FOR THE THREE MONTH PERIOD ENDED MARCH 31, 2011

($ in thousands, except unit amounts)



	Number of Common Units	Common Units
BALANCE — January 1, 2011	83,425,378	$	579,113
Net loss	—	(53,717		)
Distributions	—	(12,778		)
Exercised warrants	4,552,007	27,312
Equity based compensation	—	910
BALANCE —March 31, 2011	87,977,385	$	540,840

See notes to unaudited condensed consolidated financial statements.

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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”).

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 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 month period ended March 31, 2011 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2011.

On May 24, 2010, the Partnership consummated the sale of all of its fee mineral and royalty interests as well as its equity investment in Ivory Working Interests, L.P. (collectively, the "Minerals Business"). During the three months ended March 31, 2011, the Partnership's Wildhorse Gathering System in its South Texas Segment was reclassified as assets and liabilities held for sale and the operations as discontinued. The assets and liabilities related to the Wildhorse Gathering System as of December 31, 2010 have been retrospectively adjusted to be reflected as held for sale, and the operations related to the Minerals Business and the Wildhorse Gathering System for the three months ended March 31, 2010 have been retrospectively adjusted to be reflected as discontinued operations (see Notes 13 and 17).

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.

Description of Business—Eagle Rock Energy is a growth-oriented limited partnership engaged in the business of gathering, compressing, treating, processing, transporting and selling natural gas, fractionating and transporting natural gas liquids, or NGLs (the “Midstream Business”), and the business of acquiring, developing and producing interests in oil and natural gas properties (the “Upstream Business”). The Partnership's natural gas pipelines gather natural gas from designated points near producing wells and transport these volumes to third-party pipelines, the Partnership's gas processing plants, utilities and industrial consumers. Natural gas transported to the Partnership's gas processing plants, either on the Partnership's pipelines or third party pipelines, is treated to remove contaminants and conditioned or processed into marketable natural gas and 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.

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. 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

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understanding these financial statements.

Oil and Natural Gas Accounting Policies

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

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

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

Impairment of Oil and Natural Gas Properties

The Partnership reviews its proved properties at the field level when management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future oil and natural gas reserves that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels. If the carrying amount of an asset exceeds the sum of the undiscounted estimated future net cash flows, the Partnership recognizes impairment expense equal to the difference between the carrying value and the fair value of the asset, which is estimated to be the expected present value of discounted future net cash flows from proved reserves utilizing the Partnership's weighted average cost of capital. During the three months ended March 31, 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. During the three months ended March 31, 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 the three months ended March 31, 2010, the Partnership did not incur any impairment charges related to unproved properties.

Other Significant Accounting Policies

Transportation and Exchange Imbalances—In the course of transporting natural gas and natural gas liquids for others, the Partnership may receive for redelivery different quantities of natural gas or natural gas liquids than the quantities actually delivered. These transactions result in transportation and exchange imbalance receivables or payables which are recovered or repaid through the receipt or delivery of natural gas or natural gas liquids in future periods, if not subject to cash out provisions. Imbalance receivables are included in accounts receivable and imbalance payables are included in accounts payable on the consolidated balance sheets and marked-to-market using current market prices in effect for the reporting period of the outstanding imbalances. For the Midstream Business, as of March 31, 2011, the Partnership had imbalance receivables totaling $0.7 million and imbalance payables totaling $1.5 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 March 31, 2011 and December 31, 2010, the Partnership had $3.9 million and $0.5 million, respectively, of crude oil finished goods inventory which is recorded as part of Other Current Assets within the Consolidated Balance Sheet.

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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 and condensate are recognized when title passes to the customer, which is when the risk of ownership passes to the customer and physical delivery occurs. Revenues associated with transportation and processing fees are recognized 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 revenue for services such as transportation, compression and processing.

The Partnership's Upstream Segment recognizes revenues based on 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 each of March 31, 2011 and December 31, 2010, the Partnership's Upstream Segment had an imbalance receivable balance of $0.5 million.

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 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 a specifies a hierarchy of valuation techniques based on the inputs used to measure fair value. See Note 10 for additional information regarding the Partnership's assets and liabilities carried at fair value.

NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS

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

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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 10).

NOTE 4. PROPERTY PLANT AND EQUIPMENT

Fixed assets consisted of the following:



	March 31, 2011			December 31, 2010
	($ in thousands)
Land	$	2,630		$	2,629
Plant	276,570			251,436
Gathering and pipeline	673,298			666,163
Equipment and machinery	27,402			26,408
Vehicles and transportation equipment	4,256			4,251
Office equipment, furniture, and fixtures	1,120			1,120
Computer equipment	8,472			8,486
Corporate	126			126
Linefill	4,269			4,269
Proved properties	477,383			471,781
Unproved properties	1,054			1,304
Construction in progress	17,553			42,416
	1,494,133			1,480,389
Less: accumulated depreciation, depletion and amortization	(363,807		)	(343,150		)
Net property plant and equipment	$	1,130,326		$	1,137,239

Depreciation expense for the three months ended March 31, 2011 and 2010 was approximately $13.6 million and $13.5 million, respectively. Depletion expense for the three months ended March 31, 2011 and 2010 was approximately $7.2 million and $8.2 million, respectively. During the three months ended March 31, 2011, the Partnership recorded impairment charges of $0.3 million related to unproved properties. During the three months ended March 31, 2010, the Partnership did not incur any impairment charges. 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 both the three months ended March 31, 2011 and 2010, the Partnership capitalized interest costs of less than $0.1 million.

NOTE 5. ASSET RETIREMENT OBLIGATIONS

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

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

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	Three Months Ended March 31,
	2011			2010
	($ in thousands)
Asset retirement obligations—January 1	$	24,711		$	19,829
Liabilities settled	(148		)	(43		)
Additional liability related to acquisitions	45			—
Accretion expense	407			340
Asset retirement obligations—March 31	$	25,015		$	20,126

NOTE 6. 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. Amortization expense was approximately $2.9 million and $5.8 million for the three months ended March 31, 2011 and 2010, respectively. Estimated aggregate amortization expense for 2011 and each of the four succeeding years is as follows: 2011—$9.1 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 March 31, 2011 and December 31, 2010):



	March 31, 2011			December 31, 2010
	($ in thousands)
Rights-of-way and easements—at cost	$	92,243		$	91,490
Less: accumulated amortization	(21,824		)	(20,552		)
Contracts	122,601			122,601
Less: accumulated amortization	(81,547		)	(79,905		)
Net intangible assets	$	111,473		$	113,634

The amortization period for the Partnership's rights-of-way and easements is 20 years. The amortization period for contracts range from 5 to 20 years, and are approximately 8 years on average as of March 31, 2011.

NOTE 7. LONG-TERM DEBT

As of March 31, 2011 and December 31, 2010, the Partnership had $507.7 million and $530.0 million outstanding, respectively, under its revolving credit facility. The Partnership had approximately $375.3 million of unused capacity under the revolving credit facility (before taking into account covenant-based capacity limitations and the approximately $9.1 million of unfunded commitments from Lehman Brothers that is no longer available after Lehman Brothers' bankruptcy filing) as of March 31, 2011, on which the Partnership pays a 0.3% commitment fee per year.

As of March 31, 2011, the Partnership was in compliance with the financial covenants under its revolving credit facility.

See Note 19 - Subsequent Events for further discussion of the borrowing base redetermination and the additional amounts outstanding under the revolving credit facility as a result of the acquisition of CC Energy II L.L.C on May 3, 2011.

NOTE 8. MEMBERS’ EQUITY

At March 31, 2011, there were 87,977,385 common units outstanding. In addition, there were 1,788,449 restricted unvested common units outstanding.

During the three months ended March 31, 2011, 4,552,007 warrants were exercised for a total of 4,552,007 newly issued common units. As of March 31, 2011 and December 31, 2010, 16,113,238 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.

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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 19). The distribution will be paid on May 13, 2011.

NOTE 9. RELATED PARTY TRANSACTIONS

During the three months ended March 31, 2011 and 2010, the Partnership incurred $1.5 million and $2.3 million, respectively, in expenses with related parties, of which there was an outstanding accounts payable balance of $0.4 million and $0.5 million as of March 31, 2011 and December 31, 2010, respectively.

The Partnership receives services from Stanolind Field Services ("SFS"), which was an entity controlled by Natural Gas Partners ("NGP"). On August 2, 2010, SFS ceased being a related party of the Partnership as NGP sold all of its interests in SFS. During the three months ended March 31, 2010, the Partnership incurred approximately $0.7 million for services performed by SFS. As of March 31, 2011 and December 31, 2010, there were no outstanding accounts payable balances to SFS.

NOTE 10. 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 March 31, 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 March 31, 2011 and December 31, 2010:



	As of March 31, 2011
	Level 1		Level 2			Level 3			Netting (a)			Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	—		$	—		$	—		$	—
Natural gas derivatives	—		14,117			—			(14,117		)	—
NGL derivatives	—		—			—			—			—
Total	$	—	$	14,117		$	—		$	(14,117	)	$	—

Liabilities:
Crude oil derivatives	$	—	$	(90,438	)	$	—		$	—		$	(90,438	)
Natural gas derivatives	—		(114		)	—			14,117			14,003
NGL derivatives	—		—			(12,264		)	—			(12,264		)
Interest rate swaps	—		(32,014		)	—			—			(32,014		)
Total	$	—	$	(122,566	)	$	(12,264	)	$	14,117		$	(120,713	)

____________________________


(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 months ended March 31, 2011 and 2010 (in thousands):



	Three Months Ended March 31,
	2011			2010
Net liability balance as of January 1	$	(5,733	)	$	(14,784	)
Settlements	3,737			4,129
Total gains or losses (realized and unrealized)	(10,268		)	2,997
Net liability balance as of March 31	$	(12,264	)	$	(7,658	)

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 $(9.0) million and $2.7 million in the three months ended March 31, 2011 and 2010, respectively, that are attributable to the change in unrealized gains or losses related to those assets and liabilities still held at March 31, 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 Consolidated Statements of Operations. Realized and unrealized gains and losses and premium amortization related to the Partnership's commodity derivatives are recorded as a component of revenue in the Consolidated Statements of Operations.

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

The Partnership believes that the fair value of its revolving credit facility does not approximate its carrying value as of March 31, 2011 because the applicable floating rate margin on the revolving credit facility was a below-market rate. The fair value of the revolving credit facility has been estimated based on similar transactions that occurred during the twelve months ended December 31, 2010 and the three months ended March 31, 2011. The Partnership estimates that the fair value of the borrowings under its revolving credit facility as of March 31, 2011 was $499.7 million versus a carrying value of $507.7 million. The Partnership estimates that the fair value of the borrowings under its revolving credit facility as of December 31, 2010 was $518.0 million versus a carrying value of $530.0 million.

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.

The following table, as of March 31, 2011, sets forth certain information regarding the Partnership's various interest rate swaps:



Effective Date	Expiration Date	Notional Amount		Fixed Rate
12/31/2008	12/31/2012	$	150,000,000	2.56	%
9/30/2008	12/31/2012	150,000,000		4.295	%
10/3/2008	12/31/2012	300,000,000		4.095	%

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

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Commodity Derivative Instruments

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

The Partnership uses put options, costless collars and fixed-price swaps to achieve its hedging objectives, and often hedges its expected future volumes of one commodity with derivatives of the same commodity. In some cases, however, the Partnership believes it is better to hedge future changes in the price of one commodity with a derivative of another commodity, which it refers to as “cross-commodity” hedging. The Partnership will often hedge the changes in future NGL prices 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 any of its commodity derivative instruments as hedges and therefore is marking these derivative contracts to fair value (see Note 10). 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. The Partnership's counterparties are all participants or affiliates of participants within its revolving credit facility (see Note 7), which is secured by substantially all of the assets of the Partnership. Therefore, the Partnership is not required to post any collateral, nor does it require collateral from its counterparties. The Partnership minimizes the credit risk in derivative instruments by limiting its exposure to any single counterparty and monitoring the creditworthiness of its counterparties on an ongoing basis. In addition, the Partnership's derivative contracts, for certain counterparties, are subject to counterparty netting agreements governing such derivatives.

The Partnership's commodity derivative counterparties include BNP Paribas, Wells Fargo Bank, N.A, Comerica Bank, Barclays Bank PLC, Bank of Nova Scotia, The Royal Bank of Scotland plc, Bank of America N.A., J Aron and Company (an

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affiliate of Goldman Sachs), BBVA Compass Bank and Credit Suisse Energy LLC (an affiliate of Credit Suisse Group AG).

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

Underlying

Period

Notional

Volumes

(units)

Type

Floor

Strike

Price

($/unit)

Cap

Strike

Price

($/unit)

Natural Gas:

NYMEX Henry Hub

Apr-Dec 2011

900,000 mmbtu

Costless Collar

7.50

8.85

NYMEX Henry Hub

Apr-Dec 2011

540,000 mmbtu

Swap

7.085

NYMEX Henry Hub

Apr-Dec 2011

1,710,000 mmbtu

Swap

6.57

NYMEX Henry Hub

Apr-Dec 2011

(306,000) mmbtu

Swap

4.45

Crude Oil:

NYMEX WTI

Apr-Dec 2011

104,364 bbls

Costless Collar

75.00

85.70

NYMEX WTI

Apr-Dec 2011

270,000 bbls

Costless Collar

80.00

92.40

NYMEX WTI

Apr-Dec 2011

108,000 bbls

Costless Collar

75.00

89.85

NYMEX WTI

Apr-Dec 2011

93,942 bbls

Swap

80.00

NYMEX WTI

Apr-Dec 2011

90,000 bbls

Swap

65.10

NYMEX WTI

Apr-Dec 2011

45,000 bbls

Swap

75.00

NYMEX WTI

Apr-Dec 2011

270,000 bbls

Swap

65.60

NYMEX WTI

Apr-Dec 2011

153,000 bbls

Swap

83.30

NYMEX WTI

Apr-Jun 2011

18,000 bbls

Swap

86.20

Natural Gas Liquids:

OPIS NButane Mt. Belv non TET

Apr-Dec 2011

8,694,000 gallons

Swap

1.50

OPIS IsoButane Mt. Belv non TET

Apr-Dec 2011

4,158,000 gallons

Swap

1.5425

OPIS Natural Gasoline Mt. Belv non TET

Apr-Dec 2011

3,402,000 gallons

Swap

1.8525

OPIS Propane Mt. Belv non TET

Apr-Dec 2011

15,120,000 gallons

Swap

1.1165

OPIS Propane Mt. Belv non TET

Apr-Dec 2011

2,268,000 gallons

Swap

1.11

OPIS Ethane Mt. Belv non TET

Apr-Dec 2011

12,852,000 gallons

Swap

0.545

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The following table, as of March 31, 2011, sets forth certain information regarding the Partnership's commodity derivatives that will mature during the year ended December 31, 2012:

Underlying

Period

Notional

Volumes

(units)

Type

Floor

Strike

Price

($/unit)

Cap

Strike

Price

($/unit)

Natural Gas:

NYMEX Henry Hub

Jan-Dec 2012

1,080,000 mmbtu

Costless Collar

7.35

8.65

NYMEX Henry Hub

Jan-Dec 2012

3,120,000 mmbtu

Swap

6.77

Crude Oil:

NYMEX WTI

Jan-Dec 2012

135,576 bbls

Costless Collar

75.30

86.30

NYMEX WTI

Jan-Dec 2012

360,000 bbls

Costless Collar

80.00

98.50

NYMEX WTI

Jan-Dec 2012

192,000 bbls

Costless Collar

75.00

94.75

NYMEX WTI

Jan-Dec 2012

108,468 bbls

Swap

80.30

NYMEX WTI

Jan-Dec 2012

240,000 bbls

Swap

68.30

NYMEX WTI

Jan-Dec 2012

240,000 bbls

Swap

76.50

NYMEX WTI

Jan-Dec 2012

240,000 bbls

Swap

82.02

NYMEX WTI

Jan-Dec 2012

420,000 bbls

Swap

90.65

The following table, as of March 31, 2011, sets forth certain information regarding the Partnership's commodity derivatives that will mature during the year ended December 31, 2013:

Underlying

Period

Notional

Volumes

(units)

Type

Floor

Strike

Price

($/unit)

Cap

Strike

Price

($/unit)

Natural Gas:

NYMEX Henry Hub

Jan-Dec 2013

600,000 mmbtu

Swap

5.65

NYMEX Henry Hub

Jan-Dec 2013

600,000 mmbtu

Swap

5.30

NYMEX Henry Hub

Jan-Dec 2013

600,000 mmbtu

Swap

5.305

Crude Oil:

NYMEX WTI

Jan-Dec 2013

240,000 bbls

Swap

90.20

NYMEX WTI

Jan-Dec 2013

720,000 bbls

Swap

89.85

NYMEX WTI

Jan-Dec 2013

384,000 bbls

Swap

90.75

NYMEX WTI

Jan-Dec 2013

120,000 bbls

Swap

88.20

See Note 19 - Subsequent Events for a discussion of the hedging transactions entered into by the Partnership subsequent to March 31, 2011 and acquired in connection with the acquisition of CC Energy II L.L.C. on May 3, 2011.

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Fair Value of Interest Rate and Commodity Derivatives

Fair values of interest rate and commodity derivative instruments not designated as hedging instruments in the consolidated balance sheet as of March 31, 2011 and 2010:



	As of March 31, 2011
	Derivative Assets				Derivative Liabilities
	Balance Sheet Classification	Fair Value			Balance Sheet Classification	Fair Value
	($ in thousands)
Interest rate derivatives - liabilities		$	—		Current liabilities	$	(20,610	)
Interest rate derivatives - liabilities		—			Long-term liabilities	(11,404		)
Commodity derivatives - liabilities		—			Current liabilities	(46,900		)
Commodity derivatives - liabilities		—			Long-term liabilities	(41,799		)
Total derivatives		$	—			$	(120,713	)

	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 Consolidated Statement of Operations (in thousands):



Amount of Gain (Loss) Recognized in Income on Derivatives		Three Months Ended March 31,
		2011			2010
Interest rate derivatives	Interest rate risk management losses	$	(2,662	)	$	(9,712	)
Commodity derivatives	Commodity risk management (losses) gains	(60,445		)	10,795
Total		$	(63,107	)	$	1,083

NOTE 12. 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 March 31, 2011 and December 31, 2010 related to these matters. The Partnership has been indemnified up to a certain dollar amount for two of these lawsuits. If there ultimately is a finding against the Partnership in the indemnified cases, the Partnership would expect to make a claim against the indemnification up to limits of the indemnification. These matters are not expected to have a material adverse effect on our financial position, results of operations or cash flows.

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

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arising out of the operation of all owned, hired and non-owned vehicles by its employees on company business; (4) property insurance covering the replacement cost of all owned real and personal property, including coverage for losses due to boiler and machinery breakdown, earthquake, flood and consequent business interruption/extra expense; (5) control of well/operator's extra expense insurance for operated and non-operated wells in the Upstream Segment; and (6) corporate liability insurance including coverage for Directors and Officers and Employment Practices liabilities. In addition, the Partnership maintains excess liability insurance providing limits in excess of the established primary limits for commercial general liability and automobile liability insurance.

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

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

Environmental—The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, the Partnership must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership's combined results of operations, financial position or cash flows. At March 31, 2011 and December 31, 2010, the Partnership had accrued approximately $4.1 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 $2.4 million and $1.8 million for the three months ended March 31, 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 13. SEGMENTS

On May 24, 2010, the Partnership completed the sale of its Minerals Business and in February 2011, the Partnership classified its Wildhorse Gathering System, which was reported under the South Texas Segment, as assets and liabilities held for sale. 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 months ended March 31, 2010 and operating results for the the Wildhorse Gathering System for each of the three months ended March 31, 2011 and 2010, have been excluded from the Partnership’s segment presentation below. See Note 17 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;


(ii)	Midstream—South Texas Segment:

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


(iii)	Midstream—East Texas/Louisiana Segment:

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


(iv)	Midstream—Gulf of Mexico Segment:

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


(v)	Upstream Segment:

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


(vi)	Corporate and Other Segment:

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

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



Midstream Business Three Months Ended March 31, 2011	Texas Panhandle Segment		South Texas Segment			East Texas / Louisiana Segment		Gulf of Mexico Segment			Total Midstream Business
($ in thousands)
Sales to external customers	$	124,864	$	10,707		$	55,173	$	8,098		$	198,842
Cost of natural gas and natural gas liquids	88,839		9,920			41,668		6,892			147,319
Intersegment cost of oil and condensate	7,089		—			—		—			7,089
Operating costs and other expenses	9,401		377			4,552		455			14,785
Depreciation, depletion, amortization and impairment	9,121		738			4,556		1,666			16,081
Operating income (loss) from continuing operations	$	10,414	$	(328	)	$	4,397	$	(915	)	$	13,568
Capital Expenditures	$	7,390	$	73		$	920	$	35		$	8,418
Segment Assets	$	590,676	$	49,038		$	270,868	$	79,422		$	990,004



Total Segments Three Months Ended March 31, 2011	Total Midstream Business		Upstream Segment			Corporate and Other Segment				Total Segments
($ in thousands)
Sales to external customers	$	198,842	$	18,967	(c)	$	(60,445	)	(a)	$	157,364
Intersegment sales	—		9,503			(9,503		)		—
Cost of natural gas and natural gas liquids	147,319		—			—				147,319
Intersegment cost of oil and condensate	7,089		—			(7,089		)		—
Operating costs and other (income) expenses	14,785		8,006		(b)	11,776				34,567
Intersegment operations and maintenance	—		42			(42		)		—
Depreciation, depletion, amortization and impairment	16,081		7,554			387				24,022
Operating income (loss) from continuing operations	$	13,568	$	12,868		$	(74,980	)		$	(48,544	)
Capital Expenditures	$	8,418	$	5,662		$	102			$	14,182
Segment Assets	$	990,004	$	361,981		$	6,037		(d)	$	1,358,022



Midstream Business Three Months Ended March 31, 2010	Texas Panhandle Segment		South Texas Segment			East Texas / Louisiana Segment		Gulf of Mexico Segment			Total Midstream Business
($ in thousands)
Sales to external customers	$	93,675	$	18,938		$	60,363	$	8,859		$	181,835
Cost of natural gas and natural gas liquids	66,970		17,262			46,205		7,465			137,902
Operating costs and other expenses	8,098		486			4,209		505			13,298
Depreciation, depletion, amortization and impairment	11,590		905			4,428		1,603			18,526
Operating income (loss) from continuing operations	$	7,017	$	285		$	5,521	$	(714	)	$	12,109
Capital Expenditures	$	2,204	$	(24	)	$	1,541	$	13		$	3,734
Segment Assets	$	530,462	$	92,445		$	285,194	$	83,952		$	992,053



Total Segments Three Months Ended March 31, 2010	Total Midstream Business		Upstream Segment			Corporate and Other Segment				Total Segments
($ in thousands)
Sales to external customers	$	181,835	$	22,685		$	10,795		(a)	$	215,315
Cost of natural gas and natural gas liquids	137,902		—			—				137,902
Operating costs and other expenses	13,298		9,107		(b)	13,011				35,416
Depreciation, depletion, amortization and impairment	18,526		8,565			353				27,444
Operating income (loss) from continuing operations	$	12,109	$	5,013		$	(2,569	)		$	14,553
Capital Expenditures	$	3,734	$	4,979		$	634			$	9,347
Segment Assets	$	992,053	$	359,356		$	167,812			$	1,519,221

_________________________________


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


(b)	Includes costs to dispose of sulfur in the Upstream Segment of $(0.2) million for the three months ended March 31, 2010.


(c)	Sales to external customers for the three months ended March 31, 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 in Other revenue on the Consolidated Statement of Operations.


(d)	Includes elimination of intersegment transactions.

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NOTE 14. 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 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 and $1.0 million were used during the three months ended March 31, 2011 and 2010, respectively.

Effective Rate - The effective rate for the three months ended March 31, 2011 was 0.1% compared to 137.5% for the three months ended March 31, 2010. Due to the fact that the effective rate is a ratio of total tax expense compared to pre-tax book income, the change is due primarily to the fact that the Partnership was in a loss position during the three months ended March 31, 2011 versus income in the three months ended March 31, 2010.

Deferred Taxes - As of March 31, 2011, the net deferred tax liability was $36.5 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 March 31, 2011	$	(569	)

NOTE 15. 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 three months ended March 31, 2011 and 2010 were $9.63 and $5.74, 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.

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A summary of the restricted common units’ activity for the three months ended March 31, 2011 is provided below:



	Number of Restricted Units		Weighted Average Fair Value
Outstanding at December 31, 2010	1,744,454		$	6.27
Granted	103,800		$	9.63
Forfeited	(59,805	)	$	6.43
Outstanding at March 31, 2011	1,788,449		$	6.46

For the three months ended March 31, 2011 and 2010, non-cash compensation expense of approximately $0.9 million and $1.8 million, respectively, was recorded related to the granted restricted units.

As of March 31, 2011, unrecognized compensation costs related to the outstanding restricted units under the LTIP totaled approximately $8.8 million. The remaining expense is to be recognized over a weighted average of 2.39 years.

NOTE 16. 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 March 31, 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 consider to be dilutive securities. These outstanding warrants will be considered in the diluted weighted average common unit outstanding number in periods of net income, except if the exercise price of the outstanding warrants is greater than the average market price of the common units for such periods. In periods of net losses, the outstanding warrants are excluded from the diluted weighted average common unit outstanding number.

The restricted common units granted under the LTIP, as discussed in Note 15, contain non-forfeitable rights to the distributions declared by the Partnership and therefore meet the definition of participating securities. Participating securities are required to be included in the computation of earnings per unit pursuant to the two-class method. For the three months ended March 31, 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.

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 months ended March 31, 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.

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.

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



	Three Months Ended March 31,
	2011	2010
	(Unit amounts in thousands)
Basic weighted average unit outstanding during period:
Common units	84,235	54,203
Subordinated units	—	20,691
General partner units	—	845

Diluted weighted average unit outstanding during period:
Common units	84,235	54,420
Subordinated units	—	20,691
General partner units	—	845

The following table presents the Partnership's basic and diluted loss per unit for the three months ended March 31, 2011:



	Total			Common Units			Restricted Common Units
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(54,435	)
Distributions declared	12,852			$	12,635		$	217
Assumed loss from continuing operations after distribution to be allocated	(67,287		)	(67,287		)	—
Assumed allocation of loss from continuing operations	(54,435		)	(54,652		)	217
Discontinued operations	718			718			—
Assumed net loss to be allocated	$	(53,717	)	$	(53,934	)	$	217

Basic and diluted loss from continuing operations per unit				$	(0.65	)
Basic and diluted discontinued operations per unit				$	0.01
Basic and diluted loss per unit				$	(0.64	)

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



	Total			Common Units			Restricted Common Units		Subordinated Units			General Partner Units
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(171	)
Distributions declared	1,405			$	1,355		$	29	$	—		$	21
Assumed loss from continuing operations after distribution to be allocated	(1,576		)	(1,128		)	—		(430		)	(18		)
Assumed allocation of (loss) income from continuing operations	(171		)	227			29		(430		)	3
Discontinued operations, net of tax	4,152			2,939			46		1,121			46
Assumed net income to be allocated	$	3,981		$	3,166		$	75	$	691		$	49

Basic and diluted income from continuing operations per unit				$	0.01				$	(0.02	)	$	0.01
Basic and diluted discontinued operations per unit				$	0.05				$	0.05		$	0.05
Basic and diluted income per unit				$	0.06				$	0.03		$	0.06

NOTE 17. DISCONTINUED OPERATIONS

On April 1, 2009, the Partnership sold its producer services business (which was accounted for in its South Texas Segment) by assigning and novating the contracts under this business to a third-party purchaser. As part of the agreement, the Partnership received a monthly payment equivalent to $0.01 per MMbtu on the volume of gas that flows pursuant to the assigned contracts through March 31, 2011. During the three months ended March 31, 2011, this business generated revenues of less than $0.1 million and no cost of natural gas and NGLs. During the three months ended March 31, 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 months ended March 31, 2011, the Partnership received payments of $0.3 million related to pre-effective date operations and recorded this amount as part of discontinued operations for the period. For the three months ended March 31, 2010, the Partnership generated revenues of $5.6 million and income from operations of $3.7 million. During the three months ended March 31, 2011 and 2010, the Partnership recorded income from discontinued operations of $0.3 million and $3.8 million, respectively.

In February 2011, the Partnership classified its Wildhorse Gathering System (which was accounted for in its South Texas Segment) as assets and liabilities held for sale and classified the operations as discontinued. During the three months ended March 31, 2011, this system generated revenues of $5.1 million and income from operations of $0.4 million. During the three months ended March 31, 2010, this system generated revenues of $7.6 million and income from operations of $0.3 million. During each of the three months ended March 31, 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 March 31, 2011, liabilities held for sale consisted of accounts payable, and assets held for sale consisted of the following: (i) $1.5 million of accounts receivable, (ii) $6.2 million of pipelines and equipment and (iii) $0.3 million of intangible assets. 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 18. SUBSIDIARY GUARANTORS

In the future, the Partnership may issue registered debt securities guaranteed by its subsidiaries. The Partnership expects that all guarantors would be wholly-owned or available to be pledged and that such guarantees would be joint and several and full and unconditional. In accordance with practices accepted by the SEC, the Partnership has prepared Condensed Consolidating Financial Statements as supplemental information. The following Condensed Consolidating Balance Sheets at March 31, 2011 and December 31, 2010, and Condensed Consolidating Statements of Operations and Condensed

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Consolidating Statements of Cash Flows for the three months ended March 31, 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.



Unaudited Condensed Consolidating Balance Sheet
March 31, 2011
(in thousands)	Parent Issuer		Subsidiary Guarantors		Non-guarantor investments		Consolidating Entries			Total
ASSETS:
Accounts receivable – related parties	$	31,340	$	—	$	—	$	(31,340	)	$	—
Assets held for sale	—		7,895		—		—			7,895
Other current assets	3,514		98,647		—		—			102,161
Total property, plant and equipment, net	1,399		1,128,927		—		—			1,130,326
Investment in subsidiaries	1,118,319		—		1,090		(1,119,409		)	—
Total other long-term assets	2,313		115,327		—		—			117,640
Total assets	$	1,156,885	$	1,350,796	$	1,090	$	(1,150,749	)	$	1,358,022
LIABILITIES AND EQUITY:
Accounts payable – related parties	$	—	$	31,340	$	—	$	(31,340	)	$	—
Liabilities held for sale	—		1,184		—		—			1,184
Other current liabilities	58,556		132,276		—		—			190,832
Other long-term liabilities	49,744		67,677		—		—			117,421
Long-term debt	507,745		—		—		—			507,745
Equity	540,840		1,118,319		1,090		(1,119,409		)	540,840
Total liabilities and equity	$	1,156,885	$	1,350,796	$	1,090	$	(1,150,749	)	$	1,358,022



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

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Unaudited Condensed Consolidating Statement of Operations
For the Three Months Ended March 31, 2011
(in thousands)	Parent Issuer			Subsidiary Guarantors			Non-guarantor investments			Consolidating Entries			Total
Total revenues	$	(53,109	)	$	210,473		$	—		$	—		$	157,364
Cost of natural gas and natural gas liquids	—			147,319			—			—			147,319
Operations and maintenance	—			19,475			—			—			19,475
Taxes other than income	—			3,316			—			—			3,316
General and administrative	994			10,782			—			—			11,776
Depreciation, depletion, amortization and impairment	40			23,982			—			—			24,022
(Loss) income from operations	(54,143		)	5,599			—			—			(48,544		)
Interest expense	(3,221		)	(3		)	—			—			(3,224		)
Other non-operating income	2,123			1,105			—			(3,225		)	3
Other non-operating expense	(2,772		)	(3,160		)	(5		)	3,225			(2,712		)
(Loss) income before income taxes	(58,013		)	3,541			(5		)	—			(54,477		)
Income tax provision (benefit)	420			(462		)	—			—			(42		)
Equity in earnings of subsidiaries	4,716			—			—			(4,716		)	—
(Loss) income from continuing operations	(53,717		)	4,003			(5		)	(4,716		)	(54,435		)
Discontinued operations, net of tax	—			718			—			—			718
Net (loss) income	$	(53,717	)	$	4,721		$	(5	)	$	(4,716	)	$	(53,717	)



Unaudited Condensed Consolidating Statement of Operations
For the Three Months Ended March 31, 2010
(in thousands)	Parent Issuer			Subsidiary Guarantors			Non-guarantor investments		Consolidating Entries			Total
Total revenues	$	1,522		$	213,793		$	—	$	—		$	215,315
Cost of natural gas and natural gas liquids	—			137,902			—		—			137,902
Operations and maintenance	—			18,871			—		—			18,871
Taxes other than income	1			3,533			—		—			3,534
General and administrative	2,736			10,275			—		—			13,011
Other operating income	—			—			—		—			—
Depreciation, depletion, amortization and impairment	4			27,440			—		—			27,444
(Loss) income from operations	(1,219		)	15,772			—		—			14,553
Interest expense	(4,414		)	—			—		—			(4,414		)
Other non-operating income	1,998			577			6		(2,480		)	101
Other non-operating expense	(3,760		)	(8,432		)	—		2,480			(9,712		)
(Loss) income before income taxes	(7,395		)	7,917			6		—			528
Income tax provision (benefit)	827			(128		)	—		—			699
Equity in earnings of subsidiaries	12,203			—			—		(12,203		)	—
Income (loss) from continuing operations	3,981			8,045			6		(12,203		)	(171		)
Discontinued operations, net of tax	—			4,152			—		—			4,152
Net income (loss)	$	3,981		$	12,197		$	6	$	(12,203	)	$	3,981

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Unaudited Condensed Consolidating Statement of Cash Flows
For the Three Months Ended March 31, 2011
(in thousands)	Parent Issuer			Subsidiary Guarantors			Non-guarantor investments		Consolidating Entries		Total
Net cash flows provided by operating activities	$	4,202		$	15,411		$	21	$	—	$	19,634
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(240		)	(15,895		)	—		—		(16,135		)
Purchase of intangible assets	—			(691		)	—		—		(691		)
Net cash flows used in investing activities	(240		)	(16,586		)	—		—		(16,826		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	32,745			—			—		—		32,745
Repayment of long-term debt	(55,000		)	—			—		—		(55,000		)
Exercise of Warrants	27,312			—			—		—		27,312
Distributions to members and affiliates	(12,778		)	—			—		—		(12,778		)
Net cash flows used in financing activities	(7,721		)	—			—		—		(7,721		)
Net cash flows provided by discontinued operations	—			915			—		—		915
Net decrease in cash and cash equivalents	(3,759		)	(260		)	21		—		(3,998		)
Cash and cash equivalents at beginning of year	4,890			(884		)	43		—		4,049
Cash and cash equivalents at end of year	$	1,131		$	(1,144	)	$	64	$	—	$	51



Unaudited Condensed Consolidating Statement of Cash Flows
For the Three Months Ended March 31, 2010
(in thousands)	Parent Issuer			Subsidiary Guarantors			Non-guarantor Investments			Consolidating Entries		Total
Net cash flows provided by (used in) operating activities	$	14,951		$	2,448		$	(6	)	$	—	$	17,393
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(316		)	(7,942		)	—			—		(8,258		)
Purchase of intangible assets	—			(580		)	—			—		(580		)
Proceeds from sale of asset	—			33			—			—		33
Net cash flows used in investing activities	(316		)	(8,489		)	—			—		(8,805		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	18,000			—			—			—		18,000
Repayment of long-term debt	(35,000		)	—			—			—		(35,000		)
Proceeds from derivative contracts	—			305			—			—		305
Distributions to members and affiliates	(1,328		)	—			—			—		(1,328		)
Net cash flows (used in) provided by financing activities	(18,328		)	305			—			—		(18,023		)
Net cash flows provided by discontinued operations	—			6,852			—			—		6,852
Net (decrease) increase in cash and cash equivalents	(3,693		)	1,116			(6		)	—		(2,583		)
Cash and cash equivalents at beginning of year	4,922			(2,179		)	(11		)	—		2,732
Cash and cash equivalents at end of year	$	1,229		$	(1,063	)	$	(17	)	$	—	$	149

NOTE 19. SUBSEQUENT EVENTS

Borrowing Base Redetermination

On April 7, 2011, the Partnership announced that the borrowing base under its senior secured credit facility has been increased to $160 million from $140 million by its lenders as a part of the Partnership’s regularly scheduled semi-annual borrowing base redetermination. The redetermined borrowing base was effective as of April 1, 2011. See further discussion regarding increase on May 3, 2011 in regards to the Acquisition of CC Energy II L.L.C. below.

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Acquisition of CC Energy II L.L.C.

On May 3, 2011, the Partnership completed the acquisition 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"). Crow Creek Energy has oil and natural gas reserves located in multiple basins across Oklahoma, Texas and Arkansas.

Subject to the customary adjustments, the Partnership acquired Crow Creek Energy for total consideration of approximately $529.5 million consisting of (i) approximately $15 million in cash, (ii) approximately $301.9 million aggregate amount of common units (28.8 million common units to the existing equity holders of Crow Creek Energy) representing limited partnership interests in the Partnership and (iii) the Partnership's assumption of approximately $212.6 million of indebtedness. The cash portion of the acquisition consideration and the repayment of Crow Creek Energy's outstanding debt, which combined totaled approximately $227.6 million, was funded through the Partnership's revolving credit facility. Effective upon closing, the Partnership's borrowing base increased from $160 million to $405 million. The substantial majority of the common units were issued to NGP VIII, the private equity sponsor of Crow Creek Energy. The newly-issued Eagle Rock Energy units were issued at a negotiated price of $10.50 per unit, the ceiling price of the negotiated collar in the contribution agreement. The common units issued for this acquisition are not eligible to receive a distribution with respect to the first quarter of 2011 but will be eligible for future distributions beginning with the Partnership's second quarter distribution to be paid in August 2011.

With respect to the common units issued to it in the Acquisition, NGP VIII is subject to certain voting restrictions set forth in a Voting Agreement (the "Voting Agreement") that was executed at the closing of the acquisition of Crow Creek Energy. The Voting Agreement requires, among other things, that all common units acquired by NGP VIII be voted in the same manner as all other outstanding common units of the Partnership, subject to certain exceptions. At the closing of the acquisition of Crow Creek Energy, the Partnership and NGP VIII also entered into a Registration Rights Agreement (the "Registration Rights Agreement"). The Registration Rights Agreement grants customary demand and piggyback registration rights to NGP VIII and certain of its affiliates.

Organic Growth Projects

On April 27, 2011, the Partnership announced its intention to expand its high efficiency cryogenic Phoenix processing plant, located in Hemphill County, Texas by an incremental 30 MMcf/d. Once the expansion is completed, the plant capacity will total 80 MMcf/d. The expansion of the Phoenix Plant, coupled with additional expansions of related gathering systems, will increase Eagle Rock Energy's total processing and gathering capacity and accommodate volume growth from the Granite Wash play. The expansion of the Phoenix Plant and certain gathering systems is a direct complement to the Partnership's recent acquisition of the CenterPoint Energy assets which extended the Partnership's reach into Hemphill and Wheeler Counties in its East Panhandle System.

The expansion of the Phoenix Plant and related gathering systems is expected to be completed in the fourth quarter of 2011 at a cost of approximately $20 million. Eagle Rock Energy does not anticipate downtime or reduced throughput volumes across its 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, the Partnership does not intend to shut down and re-direct gas volumes from its Canadian Plant in Hemphill County, Texas as previously announced. The Partnership's Canadian Plant will remain operating, with total processing capacity of 25 MMcf/d.

Risk Management Activities

On April 7, 2011, the Partnership entered into the following hedging transactions: (i) 20,000 barrel per month NYMEX WTI crude oil swap at $104.85 per barrel for its 2013 calendar year, (ii) 45,000 barrel per month NYMEX WTI crude oil swap at $102.45 per barrel for its 2014 calendar year, (iii) 105,000 MMbtu per month Henry Hub natural gas swap at $5.30 per MMbtu for its 2013 calendar year, and (iv) 80,000 MMbtu per month Henry Hub natural gas swap at $4.87 per MMbtu for its 2012 calendar year.

As part of the acquisition of Crow Creek (as discussed above), the Partnership acquired the following commodity derivative contracts:

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

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


•	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; 2,000 barrels per month at a strike price of $81.50 for the last six months of 2012; and 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 addition, as part of the acquisition, the Partnership acquired interest rate swaps with a notional amount of $150 million and an average fixed rate of 0.86%. Subsequent to the closing of the acquisition, the Partnership terminated these interest rate swaps for $0.9 million.

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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. 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 months ended March 31, 2011, our Midstream Business generated operating income from continuing operations of $13.6 million, compared to operating income from continuing operations of $12.1 million generated during the three months ended March 31, 2010, an increase of $1.5 million.

We conduct, evaluate and report on our Upstream Business as one segment. Our Upstream Segment includes operated wells in Escambia County, Alabama as well as two treating facilities, one natural gas processing plant and related gathering systems. The Upstream Segment also includes operated and non-operated wells that are primarily located in West, East and South Texas in Ward, Crane, Pecos, Henderson, Rains, Van Zandt, Limestone, Freestone and Atascosa Counties. During the three months ended March 31, 2011, our Upstream Business generated operating income of $12.9 million compared to operating income of $5.0 million generated during the three months ended March 31, 2010. Of important note, our Upstream Business generated net revenue of $3.0 million from the sale of sulfur during the three months ended March 31, 2011, compared to net revenue of $1.3 million during the three months ended March 31, 2010.

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 months ended March 31, 2011, our Corporate Segment generated an operating loss of $72.6 million compared to an operating loss of $2.6 million generated during the three months ended March 31, 2010. Results reflected net losses, realized and unrealized, on our commodity derivatives of $60.4 million during the three months ended March 31, 2011 compared to a net gain, realized and unrealized, on our commodity derivatives of $10.8 million during the three months ended March 31, 2010. See "Summary of Consolidated Operating Results - Corporate and Other Segment" for a further discussion of the impact of our commodity derivatives.

Subsequent Events

Borrowing Base Redetermination

On April 7, 2011, we announced that the borrowing base under our senior secured credit facility increased to $160 million from $140 million by our lenders as a part of the Partnership’s regularly scheduled semi-annual borrowing base redetermination. The redetermined borrowing base is effective as of April 1, 2011. See further discussion below regarding the increase to our borrowing base on May 3, 2011 in connection with the acquisition of CC Energy II L.L.C.

Acquisition of CC Energy II L.L.C.

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On May 3, 2011, we completed the acquisition 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"). Crow Creek Energy has oil and natural gas reserves located in multiple basins across Oklahoma, Texas and Arkansas.

Subject to the customary adjustments, we acquired Crow Creek Energy for total consideration of approximately $529.5 million consisting of (i) approximately $15 million in cash, (ii) approximately $301.9 million aggregate amount of common units (28.8 million common units to the existing equity holders of Crow Creek Energy) representing limited partnership interests in us and (iii) our assumption of approximately $212.6 million of indebtedness. The cash portion of the acquisition consideration and the repayment of Crow Creek Energy's outstanding debt, estimated to be approximately $227.6 million, was funded through our revolving credit facility. Effective upon closing, our borrowing base increased from $160 million to $405 million. The substantial majority of these common units were issued to NGP VIII, the private equity sponsor of Crow Creek Energy. The newly-issued Eagle Rock Energy units were issued at a price of $10.50 per unit, the ceiling price of the agreed upon collar in the contribution agreement. The common units issued for this acquisition are not eligible to receive a distribution with respect to the first quarter of 2011 but will be eligible for future distributions beginning with our second quarter distribution to be paid in August 2011.

The properties acquired in this acquisition contain approximately 286 Bcfe of proved reserves, of which approximately 80% is natural gas and approximately 66% is proved developed. The core operating areas include 327 gross operated wells and 1,040 gross non-operated wells on approximately 115,500 net acres across the Golden Trend Field, Verden Field and the Cana Shale Play, all located in the Anadarko Basin in Oklahoma, the Mansfield Field and other various fields in Arkansas and the Barnett Shale in Texas.

We have identified 182 proved drilling locations on these properties. In addition to the current cash flow and low-risk development opportunities provided by the proved reserve base, the acquired assets include approximately 12,700 net acres with 434 identified drilling locations in the emerging Cana Shale play in Oklahoma. 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. This area has recently experienced a high level of horizontal drilling activity, with an estimated 54 rigs currently active across the trend.

Organic Growth Projects

On April 27, 2011, we announced our intention to expand our high efficiency cryogenic Phoenix processing plant ("Phoenix Plant"), located in Hemphill County, Texas by an incremental 30 MMcf/d. Once the expansion is completed, the plant capacity will total 80 MMcf/d. The expansion of the Phoenix Plant, coupled with additional expansions of related gathering systems, will increase our total processing and gathering capacity and accommodate volume growth from the Granite Wash play. The expansion of the Phoenix Plant and certain gathering systems is a direct complement to our recent acquisition of the CenterPoint Energy assets which extended our reach into Hemphill and Wheeler Counties in its East Panhandle System.

The expansion of the 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 Phoenix Plant as previously announced. The Canadian Plant will remain operating, with total processing capacity of 25 MMcf/d.

Risk Management Activities

On April 7, 2011, we entered into the following hedging transactions: (i) 20,000 barrel per month NYMEX WTI crude oil swap at $104.85 per barrel for its 2013 calendar year, (ii) 45,000 barrel per month NYMEX WTI crude oil swap at $102.45

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per barrel for its 2014 calendar year, (iii) 105,000 MMbtu per month Henry Hub natural gas swap at $5.30 per MMbtu for its 2013 calendar year, and (iv) 80,000 MMbtu per month Henry Hub natural gas swap at $4.87 per MMbtu for its 2012 calendar year.

As part of the acquisition of Crow Creek (as discussed above), we acquired the following commodity derivative contracts:

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.


•	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.

•

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; 2,000 barrels per month at a strike price of $81.50 for the last six months of 2012; and 3,000 barrels per month at a strike price of $81.95 for the last nine months of 2013.

•

In addition, as part of the acquisition, we acquired interest rate swaps with a notional amount of $150 million and an average fixed rate of 0.86%. Subsequent to the closing of the acquisition, we terminated these interest rate swaps for $0.9 million.

Impairment

We incurred impairment charges during the three months ended March 31, 2011 of $0.3 million in our Upstream Business 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 March 31, 2010, we did not incur any such impairment charges.

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.

Other Matters

Unscheduled Shut-Down of Third-Party Owned and Operated Eustace Processing Facility - On August 11, 2010, the Eustace processing facility, which processes substantially all of our East Texas oil and gas production, was shut-down due to events stemming from an electrical failure. As a result, we were unable to produce from our East Texas upstream properties from that date through March 11, 2011, the date the facility was brought back into service. We estimate 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 three months ended March 31, 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

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maximum recovery under our business interruption insurance policy is $5.0 million for each claimed event.

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;


•	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.

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RESULTS OF OPERATIONS

Summary of Consolidated Operating Results

Below is a table of a summary of our consolidated operating results for the three months ended March 31, 2011 and 2010.



	Three Months Ended March 31,
	2011			2010
	($ in thousands)
Revenues:
Sales of natural gas, NGLs, oil, condensate and sulfur	$	203,055		$	192,001
Gathering, compression, processing and treating fees	13,245			12,483
Realized commodity derivative losses	(6,447		)	(2,683		)
Unrealized commodity derivative (losses) gains	(53,998		)	13,478
Other	1,509			36
Total revenues	157,364			215,315
Cost of natural gas, natural gas liquids, and condensate	147,319			137,902
Costs and expenses:
Operating and maintenance	19,475			18,871
Taxes other than income	3,316			3,534
General and administrative	11,776			13,011
Impairment expense	324			—
Depreciation, depletion and amortization	23,698			27,444
Total costs and expenses	58,589			62,860
Total operating (loss) income	(48,544		)	14,553
Other income (expense):
Interest income	3			2
Other income	—			99
Interest expense	(3,224		)	(4,414		)
Unrealized interest rate derivatives gains (losses)	2,565			(4,822		)
Realized interest rate derivative losses	(5,227		)	(4,890		)
Other expense	(50		)	—
Total other income (expense)	(5,933		)	(14,025		)
(Loss) income from continuing operations before income taxes	(54,477		)	528
Income tax (benefit) provision	(42		)	699
Loss from continuing operations	(54,435		)	(171		)
Discontinued operations, net of tax	718			4,152
Net (loss) income	$	(53,717	)	$	3,981
Adjusted EBITDA(a)	$	30,294		$	30,793

________________________


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

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Midstream Business (Four Segments)

Texas Panhandle Segment



	Three Months Ended March 31,
	2011			2010
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Sales of natural gas, NGLs, oil and condensate	$	121,078		$	90,733
Gathering and treating services	3,786			2,942
Total revenues	124,864			93,675
Cost of natural gas, NGLs, and condensate (a)	95,928			66,970
Operating costs and expenses:
Operations and maintenance	9,401			8,098
Depreciation and amortization	9,121			11,590
Total operating costs and expenses	18,522			19,688
Operating income	$	10,414		$	7,017

Capital expenditures	$	7,390		$	2,204

Realized prices:
Oil and condensate (per Bbl)	$	79.84		$	68.50
Natural gas (per Mcf)	$	3.99		$	5.20
NGLs (per Bbl)	$	54.54		$	48.22
Production volumes:
Gathering volumes (Mcf/d)(b)	144,284			128,493
NGLs (net equity gallons)	8,229,714			9,555,983
Condensate (net equity gallons)	9,466,558			8,719,633
Natural gas short position (MMbtu/d)(b)	(8,788		)	(4,301		)

________________________


(a)	Includes purchase of oil and condensate of $7,089 from the Upstream Segment for the three months ended March 31, 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. For the three months ended March 31, 2011, revenues minus cost of natural gas, NGLs and condensate for our Texas Panhandle Segment operations totaled $28.9 million compared to $26.7 million for the three months ended March 31, 2010. The increase was primarily driven by higher product prices and increased volumes associated with the recent CenterPoint Energy acquisition ("East Hemphill") where we acquired certain natural gas gathering systems and related facilities located primarily in Wheeler and Hemphill Counties; however, these benefits were substantially offset by a reduction in existing volumes of natural gas, NGLs and condensate due to severe winter weather in the Texas Panhandle Segment. The severe weather that occurred in January and February 2011, impacted revenues minus cost of natural gas by $2.1 million across the Texas Panhandle Segment during the three months ended March 31, 2011. This event also caused damage to our Cargray processing facility, resulting in reduced recoveries of NGLs. The Cargray processing facility is expected to be back to its previous operating conditions by mid 2011. Also, Eagle Rock Marketing, LLC, which began operations during the fourth quarter of 2010, contributed $0.5 million of revenues minus cost of natural gas, NGLs and condensate during the three months ended March 31, 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 share of the production, the overall decline will continue. We have seen a resurgence of drilling activity in the East Panhandle

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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 expected it would continue in the first quarter 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 months ended March 31, 2011 increased $1.3 million as compared to the three months ended March 31, 2010. The increase was primarily driven by approximately $0.8 million related to inclement weather as well as increased costs related to the newly-acquired East Hemphill gathering system and increased condensate hauling costs due to higher condensate volumes.

Depreciation and Amortization. Depreciation and amortization expenses for the three months ended March 31, 2011 decreased $2.5 million from the three months ended March 31, 2010. The major item impacting the decrease was a reduction in amortization expense due to the completion of the amortization of certain intangible assets. This decrease was offset by depreciation expense associated with the capital expenditures placed into service during the period.

Capital Expenditures. Capital expenditures for the three months ended March 31, 2011 increased $5.2 million compared to the three months ended March 31, 2010. The increase was primarily driven by spending related to the construction of our Phoenix Plant in 2010, including an interconnect between our System 97 gathering system and the Phoenix Plant and spending related to improvements to the Cargray Stabilizer and Goad Treater as well as providing the interconnects between our newly acquired assets from CenterPoint Energy and our Phoenix Plant.

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East Texas/Louisiana Segment



	Three Months Ended March 31,
	2011		2010
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Sales of natural gas, NGLs, oil and condensate	$	46,592	$	51,841
Gathering and treating services	8,581		8,522
Total revenues	55,173		60,363
Cost of natural gas and NGLs	41,668		46,205
Operating costs and expenses:
Operations and maintenance	4,552		4,209
Depreciation and amortization	4,556		4,428
Total operating costs and expenses	9,108		8,637
Operating income	$	4,397	$	5,521

Capital expenditures	$	920	$	1,541

Realized prices:
Oil and condensate (per Bbl)	$	90.29	$	68.45
Natural gas (per Mcf)	$	4.61	$	5.89
NGLs (per Bbl)	$	40.05	$	39.02
Production volumes:
Gathering volumes (Mcf/d)(a)	200,284		212,907
NGLs (net equity gallons)	4,410,125		4,679,582
Condensate (net equity gallons)	685,748		471,293
Natural gas short position (MMbtu/d)(a)	1,155		1,828

________________________


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

Revenue and Cost of Natural Gas and NGLs. For the three months ended March 31, 2011, revenues minus cost of natural gas and NGLs for our East Texas/Louisiana Segment totaled $13.5 million compared to $14.2 million for the three months ended March 31, 2010. During the three months ended March 31, 2011 and 2010, we recorded revenues associated with deficiency payments of $1.3 million and $1.6 million, respectively. We receive deficiency payments under certain of our gathering contracts as capital reimbursements 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 months ended March 31, 2011 and 2010 would have been $12.2 million and $12.5 million, respectively. The decrease for the three months ended March 31, 2011 compared to the three months ended March 31, 2010, excluding the impact of the deficiency payments, is primarily due to a decrease in gathering and equity volumes and lower natural gas prices, partially offset by higher condensate and NGL prices.

Our gathering volumes on our East Texas Mainline ("ETML") system and certain other East Texas/Louisiana systems for the three months ended March 31, 2011 decreased as compared to the three months ended March 31, 2010, due to natural declines in the production of the existing wells and to reduced drilling activity. Our Brookeland and associated systems continue to see a modest rebound in gathered volumes which began in the fourth quarter of 2010. This increase has been driven by our producers' focus on the liquid-rich gas streams of the Austin Chalk play.

Operating Expenses. Operating expenses for the three months ended March 31, 2011 increased $0.3 million compared to the three months ended March 31, 2010 as a result of higher costs at the Indian Springs Plant (which is operated by a third

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party), compressor repairs and labor & benefits, offset by lower compressor rental costs and chemicals.

Depreciation and Amortization. Depreciation and amortization expenses for the three months ended March 31, 2011 increased $0.1 million compared to the three months ended March 31, 2010. The increase was due to depreciation expense associated with the capital expenditures placed into service during the period.

Capital Expenditures. Capital expenditures for the three months ended March 31, 2011 decreased $0.6 million compared to the three months ended March 31, 2010. During the three months ended March 31, 2011, we spent approximately $3.4 million to connect new wells. These capital expenditures were offset by the sale of $2.5 million of excess pipe inventory during the three months ended March 31, 2011 related to the ETML expansion project which was cancelled in 2010.

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South Texas Segment



	Three Months Ended March 31,
	2011			2010
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Sales of natural gas, NGLs, oil and condensate	$	9,993		$	18,354
Gathering and treating services	714			584
Total revenues	10,707			18,938
Cost of natural gas and NGLs	9,920			17,262
Operating costs and expenses:
Operations and maintenance	377			486
Depreciation and amortization	738			905
Total operating costs and expenses	1,115			1,391
Operating (loss) income from continuing operations	(328		)	285
Discontinued operations (a)	452			348
Operating income	$	124		$	633

Capital expenditures	$	73		$	(24	)

Realized prices:
Oil and condensate (per Bbl)	$	82.40		$	78.36
Natural gas (per Mcf)	$	4.02		$	5.44
NGLs (per Bbl)	$	49.70		$	49.98
Production volumes:
Gathering volumes (Mcf/d)(b)	35,995			63,144
NGLs (net equity gallons)	45,182			94,265
Condensate (net equity gallons)	37,359			184,548
Natural gas short position (MMbtu/d)(b)	1,121			1,063

________________________


(a)	Includes sales of natural gas of $42 to the Upstream Segment for the three months ended March 31, 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 months ended March 31, 2011, the South Texas Segment contributed revenues minus cost of natural gas and NGLs of $0.8 million, as compared to $1.7 million for the three months ended March 31, 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 months ended March 31, 2011 remained consistent as compared to the three months ended March 31, 2010.

Depreciation and Amortization. Depreciation and amortization expenses for the three months ended March 31, 2011 as compared to the three months ended March 31, 2010 decreased $0.2 million.

Capital Expenditures. Capital expenditures for the three months ended remained consistent as compared to the three months ended March 31, 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 each of the three months ended March 31, 2011

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and 2010, this business generated revenues of less than $0.1 million and no cost of natural gas and NGLs.

In February 2011, we classified our Wildhorse Gathering System as assets held for sale and classified the operations as discontinued. During the three months ended March 31, 2011, this system generated revenues of $5.1 million and income from operations of $0.4 million. During the three months ended March 31, 2010, this system generated revenues of $7.6 million and income from operations of $0.3 million.

Gulf of Mexico Segment



	Three Months Ended March 31,
	2011			2010
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Sales of natural gas, NGLs, oil and condensate	$	7,934		$	8,424
Gathering and treating services	164			435
Total revenues	8,098			8,859
Cost of natural gas and NGLs	6,892			7,465
Operating costs and expenses:
Operations and maintenance	455			505
Depreciation and amortization	1,666			1,603
Total operating costs and expenses	2,121			2,108
Operating loss	$	(915	)	$	(714	)

Capital Expenditures	$	35		$	13

Realized average prices:
NGLs (per Bbl)	$	52.64		$	48.50
Production volumes:
Gathering volumes (Mcf/d)(a)	110,471			102,291
NGLs and condensate (net equity gallons)	1,062,858			1,087,316

________________________


(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 months ended March 31, 2011, the Gulf of Mexico Segment contributed $1.2 million in revenues minus cost of natural gas and NGLs compared to $1.4 million in the three months ended March 31, 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 months ended March 31, 2011 compared to the three months ended March 31, 2010 remained consistent.

Depreciation and Amortization. Depreciation and amortization expenses for in the three months ended March 31, 2011 compared to the three months ended March 31, 2010 remained consistent.

Capital Expenditures. Capital expenditures for the three months ended March 31, 2011 for the Gulf of Mexico Segment compared to the three months ended March 31, 2010 remained consistent.

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Upstream Segment



	Three Months Ended March 31,
	2011		2010
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Oil and condensate (a) (b)	$	14,861	$	10,985
Natural gas (c)	3,394		4,632
NGLs (d)	5,666		5,964
Sulfur (e)	3,040		1,068
Other	1,509		36
Total revenues	28,470		22,685
Operating Costs and expenses:
Operations and maintenance (f)	8,048		9,292
Sulfur disposal costs	—		(185		)
Depletion, depreciation and amortization	7,230		8,565
Impairment	324		—
Total operating costs and expenses	15,602		17,672
Operating income	$	12,868	$	5,013

Capital expenditures	$	5,662	$	4,979

Realized average prices (h):
Oil and condensate (per Bbl)	$	75.54	$	59.63
Natural gas (per Mcf)	$	4.07	$	5.28
NGLs (per Bbl)	$	56.22	$	50.78
Sulfur (per Long ton) (g)	$	163.75	44.04
Production volumes:
Oil and condensate (Bbl)	196,733		197,465
Natural gas (Mcf)	832,305		942,463
NGLs (Bbl)	99,358		120,418
Total (Mcfe)	2,608,851		2,849,761
Sulfur (Long ton) (g)	18,535		19,116

________________________


(a)	Includes sales of oil and condensate to the Texas Panhandle Segment of $9,503 for the three months ended March 31, 2011.


(b)	Revenues include a change in the value of product imbalances by $(181) for the three months ended March 31, 2010.


(c)	Revenues include a change in the value of product imbalances by $7 and $(285) for the three months ended March 31, 2011 and 2010, respectively.


(d)	Revenues include a change in the value of product imbalances by $80 for the three months ended March 31, 2011.


(e)	Revenues include a change in the value of product imbalances by $5 for the three months ended March 31, 2011.


(f)	Includes purchase of natural gas of $42 from the South Texas Segment for the three months ended March 31, 2011.


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


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

Revenue. For the three months ended March 31, 2011, Upstream Segment revenues increased by $5.8 million, as compared to the three months ended March 31, 2010. The increase in revenue was due to higher realized prices for oil, NGLs and sulfur during three months ended March 31, 2011 compared to the three months ended March 31, 2010. This increase was partially offset by the shut-in of our East Texas production beginning August 11, 2010.

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

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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. We estimate that the shut-in negatively impacted our net revenues for the three months ended March 31, 2011 by approximately $3.9 million (excluding recoveries). As of March 31, 2011, we have 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 for each claimed event.

During the three months ended March 31, 2011, sulfur revenue was $3.0 million as compared to $1.1 million during the three months ended March 31, 2010. In addition, during the three months ended March 31, 2010, we recorded a credit to sulfur disposal costs of $0.2 million to adjust for an overaccrual of sulfur cost in a prior period. Historically, sulfur was viewed as a low value byproduct in the production of oil and natural gas. During the three months ended March 31, 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 May 2, 2011 at the Tampa, Florida market. Our net realized price will always be lower than the price set at the Tampa, Florida hub due to transportation and marketing deductions and charges. These charges vary depending on the distance our product is produced from the Tampa, Florida market.

Operating Expenses. Operating expenses, including severance and ad valorem taxes, decreased by $1.2 million for the three months ended March 31, 2011, as compared to the three months ended March 31, 2010. The decrease can be attributed to increased well workovers in our Alabama operations during the three months ended March 31, 2010. This decrease was offset by an increase in our severance taxes as a result of the increase in revenue during the three months ended March 31, 2011.

Depletion, Depreciation and Amortization. Depletion, depreciation and amortization expense decreased by $1.3 million for the three months ended March 31, 2011, as compared to the same period in the prior year. The decrease was 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 three months ended March 31, 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 March 31, 2010, we did not incur any impairment charges.

Capital Expenditures. Capital expenditures increased by $0.7 million for the three months ended March 31, 2011, as compared to the three months ended March 31, 2010. During the three months ended March 31, 2011, we spent $5.7 million of capital expenditures associated with (i) the drilling and completion of the St. Regis 9-5 #1 well in our Big Escambia Creek Field in Alabama, (ii) the drilling of the C.J. Pierce #1 well in our Edgewood Cotton Valley field in our East Texas operations, (iii) certain recompletions in our Permian operations, (iv) various workover operations in our Northeast Edgewood field in East Texas, and (v) other lesser plant, facilities and leasing capital expenditures.

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Corporate and Other Segment



	Three Months Ended March 31,
	2011			2010
	($ in thousands)
Revenues:
Realized commodity derivatives losses	$	(6,447	)	$	(2,683	)
Unrealized commodity derivatives (losses) gains	(53,998		)	13,478
Intersegment elimination - Sales of natural gas, oil and condensate	(9,503		)	—
Total revenues	(69,948		)	10,795
Intersegment elimination - Cost of oil and condensate	(7,089		)	—
General and administrative	11,776			13,011
Intersegment elimination - Operations and maintenance	(42		)	—
Depreciation and amortization	387			353
Operating loss	(74,980		)	(2,569		)
Other income (expense):
Interest income	3			2
Other income	—			99
Interest expense	(3,224		)	(4,414		)
Unrealized interest rate derivative gains (losses)	2,565			(4,822		)
Realized interest rate derivative losses	(5,227		)	(4,890		)
Other expense	(50		)	—
Total other income (expense)	(5,933		)	(14,025		)
Loss from continuing operations before taxes	(80,913		)	(16,594		)
Income tax (benefit) provision	(42		)	699
Loss from continuing operations	(80,871		)	(17,293		)
Discontinued operations, net of tax	266			3,804
Segment loss	$	(80,605	)	$	(13,489	)

Revenue. Our Corporate and Other Segment's revenue consists of our intersegment eliminations, see further discussion below and our commodity derivatives activity. Our commodity hedging activities impact our Corporate 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 months ended March 31, 2011, we experienced significant unrealized losses in our commodity derivative portfolio due to increases in the crude oil and NGL forward curves, partially offset by decreases in the natural gas forward curve. This compares to the three months ended March 31, 2010, during which we experienced an unrealized gain on our commodity derivative portfolio due to decreases in the crude oil and NGLs forward curves. Included with our unrealized commodity derivative gains (losses) are the amortization of put premiums and other derivative costs, including the costs of hedge resets, of $2.6 million for the three months ended March 31, 2010.

We recognized realized commodity derivative losses during both the three months ended March 31, 2011 and 2010. The increase in the realized loss for the three months ended March 31, 2011, as compared to the same period in the prior year, was due to the steeper increase in crude oil and NGL prices during the three months ended March 31, 2011, in relation to the strike prices of our settled contracts, as compared to the same period in the prior year.

Given the uncertainty surrounding future commodity prices, and the general inability to predict future commodity

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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 months ended March 31, 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 decreased by $1.2 million for the three months ended March 31, 2011 as compared to the same period in 2010. This decrease was partially due to a decrease in equity-based compensation expense of approximately $0.9 million during the three months ended March 31, 2011, as compared to the three months ended March 31, 2010 primarily as a result of natural run-off (through vesting) of restricted common units granted in prior periods at higher prices, offset by an increase in salaries and benefits of $0.8 million due to increased headcount over the last 12 months. In addition, included within our general and administrative expenses for the three months ended March 31, 2010 are non-capitalizable legal and other professional advisory fees of $1.0 million related to the recapitalization and related transactions and the related lawsuit.

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

Total Other Expense. Total other expense primarily consists of both realized and unrealized gains and losses from our interest rate swaps and interest expense related to our senior secured credit facility. During 2011, our realized settlements decreased by about $0.3 million, as compared to 2010, as a result of lower LIBOR rates in 2011. For the three months ended March 31, 2011, we recognized an unrealized gain of $2.6 million, as compared to an unrealized loss of $4.8 million during the same period in 2010, as a result of a decrease to the forward interest rate curves. These unrealized mark-to-market losses did not have any impact on cash activities for the period, and are excluded by definition from our calculation of Adjusted EBITDA.

Interest expense decreased by $1.2 million during the three months ended March 31, 2011, as compared to the same period in the prior year. Interest expense is shown before the impact of our interest rate derivatives, which convert a portion of our outstanding debt from variable-rate interest obligations to fixed-rate interest obligations. All of our outstanding debt consists of borrowings under our revolving credit facility, which bears interest primarily based on a LIBOR rate plus the applicable margin. The increase in interest expense is due to higher LIBOR rates during 2011, as compared to the same period in 2010, and lower outstanding debt balances as a result of our efforts to pay down debt over the past 24 months.

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 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 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 2011, our tax provision decreased by $0.7 million as compared to the same periods in the prior year, primarily due to the reduction of the deferred tax liabilities created by the book/tax differences as a result of the federal income taxes associated with the Redman and Stanolind Acquisitions, receipt of state tax refunds and true-ups related to our prior year provision.

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 months ended March 31, 2011, we received payments of $0.3 million related to pre-effective date operations and recorded this amount as part of discontinued operations. For the three months ended March 31, 2010, we generated revenues of $5.6 million and income from operations of $3.7 million. During the three months ended March 31, 2011 and 2010, we recorded income to discontinued operations of $0.3 million and $3.8 million, respectively.

Adjusted EBITDA

Adjusted EBITDA, as defined under "- Non-GAAP Financial Measures," decreased by $0.5 million from $30.8 million for the three months ended March 31, 2010 to $30.3 million for the three months ended March 31, 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 $0.5 million during the three months ended March 31, 2011, as compared to the comparable period in 2010. The Upstream Segment revenues increased $5.2

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million during the three months ended March 31, 2011, as compared to the comparable period in 2010. Intercompany eliminations revenues minus cost of natural gas and NGLs resulted in a $2.4 million decrease. Our Corporate and Other Segment's realized commodity derivatives loss increased by $3.8 million during the three months ended March 31, 2011 as compared to the comparable period in 2010. This resulted in total incremental revenues minus cost of natural gas and NGLs decreasing by $0.5 million during the three months ended March 31, 2011 as compared to the comparable period 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 $1.5 million for the three months ended March 31, 2011, as compared to the same period in 2010, while Operating Expenses (including taxes other than income) for the Upstream Segment decreased $1.1 million for the three months ended March 31, 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, decreased during the three months ended March 31, 2011 by $0.4 million, 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 months ended March 31, 2011, as compared to the same period in 2010 decreased by $0.5 million, operating expenses increased by $0.4 million and general and administrative expenses decreased by $0.4 million. The decreases in revenues minus the cost of natural gas and NGLs, the decreases in operating costs offset by the increase in general and administrative expenses resulted in a decrease to Adjusted EBITDA during the three months ended March 31, 2011, as compared to the three months ended March 31, 2010. Adjusted EBITDA excludes amortization of commodity hedge costs (including costs of hedge reset transactions) for the three months ended March 31, 2010 of $2.6 million. Including these amortization costs, our Adjusted EBITDA for the three months ended March 31, 2010 would have been $28.1 million.

LIQUIDITY AND CAPITAL RESOURCES

Historically, our sources of liquidity have included cash generated from operations, issuances of equity 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 revolving credit facility, 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 three months ended March 31, 2011, 4,552,007 warrants were exercised for which the Partnership received proceeds of $27.3 million. A total of approximately 16.1 million warrants remained outstanding as of March 31, 2011.

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 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

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maintain production in our Upstream Business.

Our 2011 capital budget anticipates that we will spend approximately $169 million in total in 2011 on capital expenditures, excluding acquisitions, which includes $20 million subsequent to March 31, 2011 due to the announced expansion of our Phoenix processing plant in April 2011 and $81 million related to Crow Creek properties during the remainder of 2011. Of the total planned capital expenditures, we estimate approximately $122 million will be classified as growth capital and over $45 million as maintenance capital. Our capital expenditures were approximately $14.2 million for the three months ended March 31, 2011.

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

As of March 31, 2011, our revolving credit facility was comprised of 19 banks with aggregate commitments of $880 million. Unused capacity available to us under our credit agreement, based on outstanding debt and total commitments as of that date, was approximately $375.3 million (before taking into account covenant-based capacity limitations and the approximately $9.1 million of unfunded commitments from Lehman Brothers that is no longer available after Lehman Brothers' bankruptcy filing), on which we pay a commitment fee of 0.3% annually. Historically, our available capacity has been further limited by compliance with the financial covenants in the credit agreement. The credit agreement is scheduled to mature on December 13, 2012.

Debt Covenants

Our revolving credit facility accommodates, through the use of a borrowing base for our Upstream Business and traditional cash-flow based covenants for our Midstream Business, the allocation of indebtedness to either our Upstream Business (to be measured against the borrowing base) or to our Midstream Business (to be measured against the cash-flow based covenant). At March 31, 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 3.8 as compared to a minimum interest coverage covenant of 2.5, and our leverage ratio, as defined in the credit agreement (i.e., Total Funded Indebtedness divided by Adjusted Consolidated EBITDA), was 4.3 as compared to a maximum leverage ratio of 5.0 (5.25 through June 30, 2011 due to the Centerpoint acquisition). 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,” both on a total Partnership basis and with respect to the definition of Total Leverage Ratio under our revolving credit facility (which is based on the outstanding borrowings allocated to, and the Adjusted EBITDA generated by, our Midstream Business), to approximately 3.0 to 3.5 on a sustained basis. We believe this leverage ratio range to be appropriate for our business.. 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 16.1 million warrants outstanding as of March 31, 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 $97 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

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growth or acquisition opportunities.

For a detailed description of our revolving credit facility, see Note 7 to our consolidated financial statements included in "Part II, Item 8. Financial Statements and Supplementary Data" included in our annual report on Form 10-K for the year ended December 31, 2010 and below under “- Revolving Credit Facility" and "- Debt Covenants.”

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, which are not eligible to receive the first quarter 2011 distribution (see further discussion within "- Overview - Subsequent Events"). This distribution will be paid on May 13, 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 March 31, 2011, working capital was a negative $82.0 million as compared to a negative $54.2 million as of December 31, 2010.

The net decrease in working capital of $27.8 million from December 31, 2010 to March 31, 2011 resulted primarily from the following factors:


•	cash balances and marketable securities decreased overall by $4.0 million;


•	trade accounts receivable increased by $19.2 million primarily from the impact of higher revenues due to higher commodity prices;


•	risk management net working capital balance decreased by a net $28.2 million as a result of changes in current portion of mark-to-market unrealized positions as a result of increases to the forward crude oil and NGL price curves;


•	accounts payable increased by $23.0 million from December 31, 2010 primarily as a result of activities and timing of payments, including capital expenditures activities; and


•	accrued liabilities decreased by $3.8 million primarily reflecting payment of employee benefit accruals, lower interest payments and the timing of payment of unbilled expenditures related primarily to capital expenditures.

Cash Flows for the For the Three Months Ended March 31, 2011 Compared to the Three Months Ended March 31, 2010

Cash Flow from Operating Activities. Cash flows from operating activities increased $2.2 million during the three months ended March 31, 2011 as compared to the three months ended March 31, 2010 as a result of higher commodity prices. These higher commodity prices resulted in higher cash flows from the sale of our equity crude oil, natural gas and NGLs volumes and higher cash flows from the sale of sulfur. Higher commodity prices also resulted in us realizing net settlement losses on our commodity derivatives during the three months ended March 31, 2011.

Cash Flows from Investing Activities. Cash flows used in investing activities for the three months ended March 31, 2011 were $16.8 million as compared to cash flows used in investing activities of $8.8 million for the three months ended March 31, 2010, primarily due to increased cash outlays for capital expenditures, in particular spending related to our Phoenix Plant.

Cash Flows from Financing Activities. Cash flows used in financing activities during the three months ended March 31, 2011 as compared to the three months ended March 31, 2010, increased by $10.3 million. Key differences between periods include net repayments to our revolving credit facility of $22.3 million during the three months ended March 31, 2011 as compared to net repayments of $17.0 million from our revolving credit facility during the three months ended March 31, 2010. Cash outflows related to our distributions increased to $12.8 million during the three months ended March 31, 2011 as

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compared to $1.3 million during the three months ended March 31, 2010 as a result of increasing our quarterly distribution from $0.025 for the payments made in the first quarter of 2010 (for the fourth quarter of 2009) to $0.15 paid in the first quarter of 2011 (for the fourth quarter of 2010). We also received $27.3 million due to the exercise of warrants during the first quarter of 2011.

Hedging Strategy

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

Off-Balance Sheet Obligations.

We have no off-balance sheet transactions or obligations.

Recent Accounting Pronouncements

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

In January 2010, the FASB issued additional guidance on fair value disclosures. The new guidance clarifies two existing disclosure requirements and requires new disclosures such as: (1) a “gross” presentation of activities (purchases, sales, and settlements) within the Level 3 rollforward reconciliation, which will replace the “net” presentation format; and (2) detailed disclosures about the transfers in and out of Level 1 and 2 measurements. This guidance is effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 rollforward information, which is required for annual reporting periods beginning after December 15, 2010, and for interim reporting periods within those years. We adopted the fair value disclosures guidance on January 1, 2010, except for the gross presentation of the Level 3 rollforward, which was adopted by us on January 1, 2011.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

On March 18, 2011, the Audit Committee of the Board of Directors of the general partner of our general partner approved the appointment of KPMG LLP (“KPMG”) as our independent registered public accounting firm for the fiscal year ending December 31, 2011 and approved the dismissal of Deloitte & Touche LLP (“Deloitte”) as our auditors. We notified Deloitte of its dismissal on March 18, 2011.

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Non-GAAP Financial Measures

We include in this filing 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.

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 March 31,
	2011			2010
Reconciliation of “Adjusted EBITDA” to net cash flows provided by (used in) operating activities and net income (loss):
Net cash flows provided by (used in) operating activities	$	19,634		$	17,393
Add (deduct):
Discontinued Operations	718			4,152
Depreciation, depletion, amortization and impairment	(24,022		)	(27,444		)
Amortization of debt issue cost	(240		)	(269		)
Risk management portfolio value changes	(51,433		)	8,656
Reclassing financing derivative settlements	—			305
Other	(1,145		)	(2,481		)
Accounts receivable and other current assets	23,917			(832		)
Accounts payable, due to affiliates and accrued liabilities	(21,188		)	2,836
Other assets and liabilities	42			1,665
Net (loss) income	(53,717		)	3,981
Add:
Interest (income) expense net	8,498			9,302
Depreciation, depletion, amortization and impairment	24,022			27,444
Income tax (benefit) provision	(42		)	699
EBITDA	(21,239		)	41,426
Add:
Risk management portfolio value changes	51,433			(8,656		)
Restricted unit compensation expense	910			1,808
Non-cash mark-to-market Upstream imbalances	(92		)	466
Discontinued operations	(718		)	(4,152		)
Other income	—			(99		)
ADJUSTED EBITDA(a)	$	30,294		$	30,793

________________________

(a) Adjusted EBITDA excludes amortization of commodity hedge costs (including costs of hedge reset transactions) for the three months ended March 31, 2010 of $2.6 million. Including these amortization costs, our Adjusted EBITDA for the three months ended March 31, 2010 would have been $28.1 million.

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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 months ended March 31, 2011, we recorded a loss on risk management instruments of $60.4 million representing a fair value (unrealized) loss of $54.0 million and net (realized) settlement loss of $6.4 million. For the three months ended March 31, 2010, we recorded a gain on risk management instruments of $10.8 million, representing a fair value (unrealized) loss of $13.5 million, amortization of put premiums and other derivative costs of $2.6 million and net (realized) settlement gains of $2.7 million. As of March 31, 2011, the fair value net liability of these commodity contracts, including put premiums and other derivative costs, totaled approximately $88.7 million.

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

Interest Rate Risk

We are exposed to variable interest rate risk as a result of borrowings under our revolving credit agreement. 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 March 31, 2011, the notional amount of our interest rate swaps was in excess of our outstanding borrowings by approximately $92.3 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.

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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 months ended March 31, 2011, we recorded a fair value (unrealized) gain of $2.6 million and a realized loss of $5.2 million. For the three months ended March 31, 2010, we recorded a fair value (unrealized) loss of $4.8 million and a realized loss of $4.9 million. As of March 31, 2011, the fair value liability of these interest rate contracts totaled approximately $32.0 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, N.A., Comerica Bank, Barclays Bank PLC, The Royal Bank of Scotland plc, Bank of America N.A., J Aron & Company (an affiliate of Goldman Sachs), BBVA Compass Bank and Credit Suisse Energy LLC (an affiliate of Credit Suisse Group AG).

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

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 the Partnership's 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, Crow Creek holds 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 the Crow Creek properties is expected to total approximately $81 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 Acquisition. 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.

Crow Creek's properties are located in North Texas, Oklahoma and Arkansas, all of which are areas where we have not historically conducted upstream operations. In addition, Crow Creek'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.

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

We did not sell our equity securities in unregistered transactions during the period covered by this report.

We did not repurchase any of our common units during the period covered by this report.

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

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).

10.1	Eagle Rock Energy G&P, LLC 2011 Short Term Incentive Bonus Plan (incorporated by reference to Exhibit 10.1 to the Partnership's Current Report on Form 8-K filed on February 14, 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

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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: May 6, 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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EAGLE ROCK ENERGY PARTNERS, L.P.

Index to Exhibits



Exhibit Number	Description

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).

10.1	Eagle Rock Energy G&P, LLC 2011 Short Term Incentive Bonus Plan (incorporated by reference to Exhibit 10.1 to the Partnership's Current Report on Form 8-K filed on February 14, 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

(State or Other Jurisdiction of
Incorporation or Organization)

(I.R.S. Employer
Identification Number)