Eagle Rock Energy Partners L P (EROC) 10-Q 2008 Q1 Quarterly report

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, 2008

OR

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

Commission File No. 001-33016

EAGLE ROCK ENERGY PARTNERS, L.P.

(Exact Name of Registrant as Specified in Its Charter)

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

16701 Greenspoint Park Drive, Suite 200

Houston, Texas 77060

(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  ¨

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  ¨	Accelerated filer  x
Non-accelerated filer  ¨	Smaller Reporting Company  ¨
(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  ¨    No  x

The issuer had 51,207,741 common units outstanding as of May 5, 2008.

EAGLE ROCK ENERGY PARTNERS, L.P.

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements	1
	Condensed Consolidated Balance Sheets as of March 31, 2008 and December 31, 2007 (unaudited)	1
	Condensed Consolidated Statements of Operations for the three months ended March 31, 2008 and 2007 (unaudited)	2
	Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2008 and 2007 (unaudited)	3
	Condensed Consolidated Statements of Members’ Equity for the three months ended March 31, 2008 (unaudited)	4
	Notes to the Condensed Consolidated Financial Statements (unaudited)	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
	Cautionary Note Regarding Forward-Looking Statements	18
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32
Item 4.	Controls and Procedures	33
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	35
Item 1A.	Risk Factors	35
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	35
Item 3.	Defaults Upon Senior Securities	35
Item 4.	Submission of Matters to a Vote of Security Holders	35
Item 5.	Other Information	35
Item 6.	Exhibits	35

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

EAGLE ROCK ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

($ in thousands)	March 31, 2008			December 31, 2007
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	51,793		$	68,552
Accounts receivable(1)		164,003			135,633
Risk management assets		6,834			—
Prepayments and other current assets		5,836			3,992
Total current assets		228,466			208,177
PROPERTY, PLANT AND EQUIPMENT — Net		1,196,695			1,207,130
INTANGIBLE ASSETS — Net		150,105			153,948
RISK MANAGEMENT ASSETS		19			—
GOODWILL		30,513			29,527
OTHER ASSETS		13,148			11,145
TOTAL	$	1,618,946		$	1,609,927
LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	155,471		$	132,485
Due to affiliate		16,767			16,964
Accrued liabilities		8,111			9,776
Taxes payable		862			723
Risk management liabilities		65,026			33,089
Total current liabilities		246,237			193,037
LONG-TERM DEBT		557,000			567,069
ASSET RETIREMENT OBLIGATIONS		11,625			11,337
DEFERRED TAX LIABILITY		17,165			17,516
RISK MANAGEMENT LIABILITIES		115,848			94,200
COMMITMENTS AND CONTINGENCIES (Note 11)
MEMBERS’ EQUITY:
Common Unitholders(2)		578,472			617,563
Subordinated Unitholders(3)		96,404			112,360
General Partner(4)		(3,805	)		(3,155	)
Total members’ equity		671,071			726,768
TOTAL	$	1,618,946		$	1,609,927

(1) Net of allowable for bad debt of $1,008 and $1,046 as of March 31, 2008 and December 31, 2007, respectively.

(2) 50,699,647 units were issued and outstanding as of March 31, 2008 and December 31, 2007, respectively.

(3) 20,691,495 units were issued and outstanding as of March 31, 2008 and December 31, 2007, respectively.

(4) 844,551 units were issued and outstanding as of March 31, 2008 and December 31, 2007, respectively.

See notes to unaudited condensed consolidated financial statements.

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EAGLE ROCK ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited)

	Three Months Ended March 31,
($ in thousands except per unit amounts)	2008			2007
REVENUE:
Natural gas, natural gas liquids, oil, condensate and sulfur	$	357,019		$	110,121
Gathering, compression, and processing fees		7,143			4,283
Mineral and royalty income		6,958			—
Loss on risk management instruments		(45,647	)		(7,642	)
Other revenue		60			—
Total revenue		325,533			106,762
COSTS AND EXPENSES:
Cost of natural gas and natural gas liquids		275,831			90,636
Operations and maintenance		15,566			7,923
Taxes other than income		4,347			703
Other operating		—			1,711
General and administrative		11,242			4,220
Depreciation, depletion and amortization		25,745			11,630
Total costs and expenses		332,731			116,823
OPERATING LOSS		(7,198	)		(10,061	)
OTHER INCOME (EXPENSE):
Interest income		301			124
Other income		1,547			—
Interest expense, net		(22,865	)		(9,170	)
Other expense		(215	)		(397	)
Total other (expense) income		(21,232	)		(9,443	)
(LOSS) INCOME BEFORE INCOME TAXES		(28,430	)		(19,504	)
INCOME TAX (BENEFIT) PROVISION		(102	)		164
NET LOSS	$	(28,328	)	$	(19,668	)
NET LOSS PER COMMON UNIT — BASIC AND DILUTED:
Basic:
Net income (loss)
Common units	$	(0.39	)	$	(0.28	)
Subordinated units		(0.39	)		(0.64	)
General partner units		(0.39	)		(0.64	)
Basic and Diluted Weighted Average Number Outstanding (units in thousands)
Common units		50,700			20,691
Subordinated units		20,691			20,691
General partner units		845			845

See notes to unaudited condensed consolidated financial statements.

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EAGLE ROCK ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

	Three Months Ended March 31,
($ in thousands)	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(28,328	)	$	(19,668	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		25,745			11,630
Amortization of debt issuance costs		217			416
Reclassifying financing derivative settlements		2,278			(100	)
Distribution from unconsolidated affiliates – return on investment		286			—
Equity in earnings of unconsolidated affiliates		(1,541	)		—
Equity-based compensation expense		1,159			173
Other		(46	)		120
Changes in assets and liabilities — net of acquisitions:
Accounts receivable		(28,370	)		(1,000	)
Prepayments and other current assets		(1,844	)		557
Risk management activities		46,732			12,254
Accounts payable		20,649			4,252
Due to affiliates		(197	)		—
Accrued liabilities		(2,761	)		5,623
Other assets and liabilities		(834	)		(76	)
Net cash provided by operating activities		33,145			14,181
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment		(8,221	)		(16,145	)
Purchase of intangible assets		(808	)		(513	)
Net cash used in investing activities		(9,029	)		(16,658	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of revolving credit facility		(10,069	)		(9,000	)
Proceeds from revolving credit facility		—			9,000
Payments for derivative contracts		(2,278	)		100
Distributions to members and affiliates		(28,528	)		(6,145	)
Net cash used in financing activities		(40,875	)		(6,045	)
NET CHANGE IN CASH AND CASH EQUIVALENTS		(16,759	)		(8,522	)
CASH AND CASH EQUIVALENTS — Beginning of period		68,552			10,581
CASH AND CASH EQUIVALENTS — End of period	$	51,793		$	2,059
Interest paid — net of amounts capitalized	$	9,515		$	7,925
Investments in property, plant and equipment not paid	$	4,631		$	6,943

See notes to unaudited condensed consolidated financial statements.

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EAGLE ROCK ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY

FOR THE THREE MONTH PERIOD ENDED MARCH 31, 2008

(Unaudited)

($ in thousands, except unit amounts)	General Partner			Number of Common Units	Common Units			Number of Subordinated Units	Subordinated Units			Total
BALANCE — December 31, 2007	$	(3,155	)	50,699,647	$	617,563		20,691,495	$	112,360		$	726,768
Net loss		(333	)	—		(19,830	)	—		(8,165	)		(28,328	)
Distributions		(331	)	—		(20,075	)	—		(8,122	)		(28,528	)
Restricted unit expense		14		—		814		—		331			1,159
BALANCE — March 31, 2008	$	(3,805	)	50,699,647	$	578,472		20,691,495	$	96,404		$	671,071

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

In May 2006, Eagle Rock Energy Partners, L.P., a Delaware limited partnership and an indirect wholly-owned subsidiary of Eagle Rock Holdings, L.P. (“Holdings”), was formed for the purpose of completing a public offering of common units. Holdings is a portfolio company of Irving, Texas based private equity capital firm Natural Gas Partners. On October 24, 2006, Eagle Rock Energy Partners, L.P. offered and sold 12,500,000 common units in its initial public offering. In connection with the initial public offering, Eagle Rock Pipeline, L.P. , which was the main operating subsidiary of Holdings, was merged with and into a newly formed subsidiary of Eagle Rock Energy Partners, L.P. (“Eagle Rock Energy” or the “Partnership”).

Basis of Presentation and Principles of Consolidation—The accompanying financial statements include assets, liabilities and the results of operations of the “Partnership.” These unaudited 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 twelve months ended December 31, 2007. That report contains a more comprehensive summary of the Partnership’s major accounting policies. In the opinion of management, the accompanying unaudited 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, 2008 are not necessarily indicative of the results that may be expected for the twelve months ending December 31, 2008.

Description of Business—We are a growth-oriented limited partnership engaged in the business of (i) gathering, compressing, treating, processing, transporting and selling natural gas, fractionating and transporting natural gas liquids, or NGLs, which we call our “Midstream” business, (ii) acquiring, developing and producing interests in oil and natural gas properties, which we call our “Upstream” segment and (iii) acquiring and managing fee minerals and royalty interest in producing oil and gas wells located in multiple producing trends across the United States, which we call our “Minerals” segment. See Note 12 for a further description of our three business and the six accounting segments in which we report.

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The accompanying condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. In addition to our Midstream, Upstream and Mineral businesses, Eagle Rock Energy is an 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 accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Significant estimates are required for proved oil and natural gas reserves, which can affect the carrying value of oil and natural gas properties. We evaluate our estimates and assumptions on a regular basis. We base our 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, 2007. Certain items from that discussion are updated below.

Oil and Natural Gas Accounting Policies

We utilize the successful efforts method of accounting for our oil and natural gas properties. Leasehold costs are capitalized when incurred. Costs incurred to drill and complete development wells, including dry holes, 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

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unsuccessful. We carry the costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well as long as we are making sufficient progress towards assessing the reserves and the economic and operating viability of the project.

Depletion of producing oil and natural gas properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for acquisition costs using all proved reserves. Statement of Financial Accounting Standards (“SFAS”) No. 19, Financial Accounting and Reporting for Oil and Gas Producing Companies 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.

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.

Significant Accounting Policies

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

The Partnership acquired goodwill as part of its acquisition of Redman Energy Holdings, L.P., and Redman Energy Holdings II, L.P. on July 31, 2007. During the three months ended March 31, 2008, goodwill increased by $1.0 million due to adjustments made to the Redman purchase price allocation. The Partnership will perform an impairment test for goodwill assets annually or earlier if indicators of potential impairment exist. The Partnership’s goodwill impairment test involves a comparison of the fair value of each of its reporting units with their carrying value. The fair value is determined using discounted cash flows and other market-related valuation models. Certain estimates and judgments are required in the application of the fair value models. Since the date of the acquisition, no event occurred or circumstances changed that would more likely than not reduce the fair value of a reporting unit below its carrying value. If for any reason the fair value of the goodwill or that of any of the Partnership’s reporting units declines below the carrying value in the future, the Partnership may incur charges for the impairment.

Transportation and Exchange Imbalances—In the course of transporting natural gas and natural gas liquids for others, the Partnership’s midstream business 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 and upstream businesses, as of March 31, 2008, the Partnership had imbalance receivables totaling $0.3 million and imbalance payables totaling $3.0 million, respectively. For the midstream business, as of December 31, 2007, the Partnership had imbalance receivables totaling $0.2 million and imbalance payables totaling $2.7 million, respectively. Changes in market value and the settlement of any such imbalance at a price greater than or less than the recorded imbalance results in either an upward or downward adjustment, as appropriate, to the cost of natural gas sold.

Other Operating Expenses—The Partnership did not incur any other operating expenses during the three months ended March 31, 2008. Other operating expenses for the three months ended March 31, 2007 consisted of the settlement of an arbitration for $1.4 million and a severance payment to a former executive of $0.3 million.

Derivatives—Statement of Financial Accounting Statements (“SFAS”) No. 133,Accounting for Derivative Instruments and Hedging Activities,as amended (“SFAS No. 133”), establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. SFAS No. 133 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 Partnership uses financial instruments such as puts, swaps and other derivatives to mitigate the risks to cash flows resulting from changes in commodity prices and

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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 10 for a description of the Partnership’s risk management activities.

Reclassifications—Prior periods have been reclassified to conform to current period presentation to reflect taxes other than income as a separate financial statement line item on the Statement of Operations.

NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS

In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157,Fair Value Measurements. This statement defines fair value, establishes a framework for measuring fair value, and expands disclosure about fair value measurements. The statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. SFAS No. 157, as it relates to financial assets and financial liabilities, was effective for us on January 1, 2008 and had no impact on our consolidated results of operation and financial position.

In February 2008, the FASB issued FASB Staff Position (“FSP”) No. FAS 157-2, “Effective Date of FASB Statement No. 157” (“FSP FAS 157-2”), which delays the effective date of SFAS 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on at least an annual basis, until fiscal years beginning after November 15, 2008. The Partnership is currently evaluating the potential impact of adopting FSP FAS 157-2, if any, on its consolidated financial statements.

In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities(“SFAS No. 159”), which permits entities to choose to measure many financial instruments and certain other items at fair value. SFAS No. 159 was effective for us as of January 1, 2008 and had no impact, as we have elected not to measure additional financial assets and liabilities at fair value.

In December 2007, the FASB issued SFAS No. 141 (revised 2007),Business Combinations (“SFAS 141R”), which replaces SFAS 141. SFAS 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired in connection with a business combination. The Statement also establishes disclosure requirements that will enable users to evaluate the nature and financial effect of the business combination. SFAS 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of an entity’s first fiscal year that begins after December 15, 2008. The Partnership is currently evaluating the potential impact, if any, of the adoption of SFAS 141R on the Partnership’s financial statements.

In December 2007, the FASB issued SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements—an amendment of APB No. 51 (“SFAS No. 160”). SFAS No.160 requires that accounting and reporting for minority interests will be recharacterized as noncontrolling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. This Statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008. The Partnership has not yet determined the impact, if any, that SFAS No. 160 will have on its financial statements.

In March 2008, the FASB issued SFAS No. 161,Disclosures About Derivative Instruments and Hedging Activities(“SFAS No. 161”). SFAS No. 161 requires enhanced disclosures to help investors better understand the effect of an entity’s derivative instruments and related hedging activities on its financial position, financial performance, and cash flows. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. The Partnership has not yet determined the impact, if any, that SFAS No. 161 will have on its financial statements.

In March 2008 the FASB approved EITF Issue No. 07-4,Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships, which requires that master limited partnerships use the two-class method of allocating earnings to calculate earnings per unit. EITF Issue No. 07-4 is effective for fiscal years and interim periods beginning after December 15, 2008. The Partnership is evaluating the effect that EITF Issue No. 07-4 will have on its earnings per unit calculation and financial statements.

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NOTE 4. FIXED ASSETS AND ASSET RETIREMENT OBLIGATIONS

Fixed assets consisted of the following:

($ in thousands)	March 31, 2008			December 31, 2007
Land	$	1,153		$	1,153
Plant		184,179			181,689
Gathering and pipeline		541,607			541,247
Equipment and machinery		14,398			14,081
Vehicles and transportation equipment		3,681			3,657
Office equipment, furniture, and fixtures		1,023			1,023
Computer equipment		4,669			4,636
Corporate		126			126
Linefill		4,157			4,157
Proved properties		463,856			461,884
Unproved properties		66,023			66,023
Construction in progress		26,337			20,884
		1,311,209			1,300,560
Less: accumulated depreciation and amortization		(114,514	)		(93,430	)
Net fixed assets	$	1,196,695		$	1,207,130

Depreciation expense for the three months ended March 31, 2008 and the three months ended March 31, 2007 was approximately $10.8 million and $7.5 million, respectively. Depletion expense for three months ended March 31, 2008 was approximately $10.3 million. The Partnership did not own oil and natural gas properties during the three months ended March 31, 2007 and, therefore, did not incur depletion expense during these periods.

The Partnership capitalizes interest costs on major projects during extended construction time periods. Such interest costs are allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. During the three months ended March 31, 2008 and 2007, the Partnership capitalized interest costs of approximately $0.3 million and $0.4 million, respectively.

Asset Retirement Obligations—The Partnership recognizes asset retirement obligations for its oil and gas working interests in accordance with FASB Statement No. 143,Accounting for Asset Retirement Obligations (“SFAS 143”). SFAS 143 applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. SFAS 143 requires that we record 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 FASB Interpretation No. 47,Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143(“FIN 47”). FIN 47 clarified that the term “conditional asset retirement obligation”, as used in SFAS No. 143,Accounting for Asset Retirement Obligations,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 our 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, we are required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated.

A reconciliation of our liability for asset retirement obligations is as follows (in thousands):

Asset retirement obligations—December 31, 2007	$	11,337
Additional liability on newly constructed assets		94
Accretion expense		194
Asset retirement obligations—March 31, 2008	$	11,625

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NOTE 5. INTANGIBLE ASSETS

Intangible Assets—Intangible assets consist of right-of-ways and easements and acquired customer contracts, which the Partnership amortizes over the term of the agreement or estimated useful life. Amortization expense was approximately $4.6 million and $4.1 million for the three months ended March 31, 2008 and 2007, respectively. Estimated aggregate amortization expense for each of the five succeeding years is as follows: 2008—$18.0 million; 2009—$18.0 million; 2010—$17.1 million; 2011—$6.3 million; and 2012—$6.3 million. Intangible assets consisted of the following:

($ in thousands)	March 31, 2008			December 31, 2007
Rights-of-way and easements—at cost	$	80,877		$	80,069
Less: accumulated amortization		(8,282	)		(7,274	)
Contracts		108,772			108,772
Less: accumulated amortization		(31,262	)		(27,619	)
Net intangible assets	$	150,105		$	153,948

The amortization period for our 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, 2008.

NOTE 6. LONG-TERM DEBT

As of March 31, 2008 and December 31, 2007, the Partnership had $557.0 million and $567.1 million, respectively, outstanding under its $800 million secured revolving credit facility (“Revolving Credit Facility”). As of March 31, 2008, the Partnership was in compliance with the financial covenants under its Revolving Credit Facility.

NOTE 7. MEMBERS’ EQUITY

At March 31, 2008, there were 50,699,647 common units, 20,691,495 subordinated units (all subordinated units owned by Holdings) and 844,551 general partner units outstanding. In addition, there were 507,694 unvested restricted common units outstanding.

Subordinated units represent limited liability interests in the Partnership, and holders of subordinated units exercise the rights and privileges available to unitholders under the limited liability company agreement. Subordinated units, during the subordination period, will generally receive quarterly cash distributions only when the common units have received a minimum quarterly distribution of $0.3625 per unit. Subordinated units will convert into common units on a one-for-one basis when the subordination period ends. Pursuant to the Partnership’s agreement of limited partnership, the subordination period will extend to the earliest date following March 31, 2009 for which there does not exist any cumulative common unit arrearage.

On February 6, 2008, the Partnership declared its 2007 fourth quarter cash distribution to its unitholders of record as of February 11, 2008. The distribution amount per common unit was $0.3925. The distribution was made on February 15, 2008.

On April 30, 2008, the Partnership declared a cash distribution of $0.40 per unit for the first quarter ending March 31, 2008. The distribution will be paid May 15, 2008, for common unitholders of record as of May 9, 2008.

NOTE 8. RELATED PARTY TRANSACTIONS

On July 1, 2006, the Partnership entered into a month-to-month contract for the sale of natural gas with an affiliate of Natural Gas Partners, under which the Partnership sells a portion of its gas supply. The Partnership recorded revenues of $16.0 million and $5.7 million for the three months ended March 31, 2008 and March 31, 2007, respectively, from the agreement, of which there was a receivable of $5.2 and $5.5 million outstanding at March 31, 2008 and December 31, 2007, respectively. In addition, during the three months ended March 31, 2008 and March 31, 2007, the Partnership incurred $1.3 million and $1.5 million 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, 2008 and December 31, 2007, respectively. Related to its investments in unconsolidated subsidiaries, during the three months ended March 31, 2008, the Partnership recorded income of $1.5 million, of which there was an outstanding account receivable balance of $0 and $0 as of March 31, 2008 and December 31, 2007, respectively. The Partnership has received a Letter of Credit related to this agreement.

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As of March 31, 2008 and December 31, 2007, Eagle Rock Energy G&P, LLC had $16.8 million and $17.0 million, respectively, of outstanding checks paid on behalf of the Partnership. This amount was recorded as Due to Affiliate on the Partnership’s balance sheet in current liabilities. As the checks are drawn against Eagle Rock Energy G&P, LLC’s cash accounts, the Partnership reimburses Eagle Rock Energy G&P, LLC.

NOTE 9. FAIR VALUE OF FINANCIAL INSTRUMENTS

Effective January 1, 2008, the Partnership adopted SFAS No. 157, as discussed in Note 2, which, among other things, requires enhanced disclosures about assets and liabilities carried at fair value.

As defined in SFAS No. 157, 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. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy give the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurements).

The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:

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

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

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

As of March 31, 2008, the Partnership has fair valued its interest rate swaps and commodity derivative instruments (see Note 10), which includes crude, natural gas and natural gas liquids (“NGLs”). The Partnership has classified the inputs to measure the fair value of its interest rate swap, crude derivatives and natural gas derivatives as Level 2. For its NGL derivatives, the Partnership has classified the inputs related to its NGL derivatives that mature in less than one year as Level 2, but it has classified the inputs for the NGL derivatives that mature beyond one year as Level 3 as the NGL market is considered to be less liquid beyond one year’s time. The following table discloses the fair value of the Partnership’s derivative instruments as of March 31, 2008 (in thousands).

	Fair Value as of March 31, 2008
	Level 1		Level 2		Level 3		Level 4
Assets:
Crude derivatives	$	—	$	6,787	$	—	$	6,787
Natural gas derivatives		—		66		—		66
Total	$	—	$	6,853	$	—	$	6,853
Liabilities:
Crude derivatives	$	—	$	103,507	$	—	$	103,507
Natural gas derivatives		—		7,576		—		7,576
NGL derivatives		—		16,449		27,454		43,903
Interest rate swaps		—		25,888		—		25,888
Total	$	—	$	153,420	$	27,454	$	180,874

As of March 31, 2008, Risk management current assets in the Condensed Consolidated Balance Sheet include an investment premium of $6.8 million, net of amortization.

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The following table sets forth a reconciliation primarily of changes in the fair value of the NGL derivatives classified as Level 3 in the fair value hierarchy (in thousands):

Balances as of January 1, 2008	$	36,695
Transfers from Level 3 to Level 2		(5,729	)
Unrealized gains		(3,512	)
Net liability balances as of March 31, 2008	$	27,454

Unrealized gains for Level 3 recurring items are included in Loss on risk management instruments in the Condensed Consolidated Statement of Operations. The Partnership believes an analysis of instruments classified as Level 3 should be undertaken with the understanding that these items are generally economically hedged as a portfolio with instruments classified in Level 2. Accordingly, gains and losses associated with Level 3 balances may not necessarily reflect trends occurring in the underlying business. Further, unrealized gains and losses for the period from Level 3 items are often offset by unrealized gains and losses on positions classified in Level 2, as well as positions that have been realized during the period.

Transfers out of Level 3 represents existing liabilities that were previously categorized as Level 3 for which the inputs are now considered observable due to the maturity of the instruments now being less than one year.

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 carrying amount of cash equivalents is believed to approximate their fair values because of the short maturities of these instruments. As of March 31, 2008, the debt associated with the revolving credit agreement bore interest at floating rates. As such, carrying amounts of this debt instrument approximates fair value.

NOTE 10. RISK MANAGEMENT ACTIVITIES

Interest Rate Derivative Instruments—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 this swap is to eliminate interest rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments through the end of 2010.

Commodity Derivative Instruments—The prices of natural gas, crude oil and NGLs are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors which are beyond the Partnership’s control. In order to manage the risks associated with the future prices of natural gas, crude oil and NGLs, the Partnership engages in risk management activities that take the form of commodity derivative instruments. Currently these activities are governed by the general partner, which today typically prohibits speculative transactions and limits the type, maturity and notional amounts of derivative transactions. The Partnership has implemented a Risk Management Policy which will allow management to execute crude oil, natural gas liquids and natural gas hedging instruments in order to reduce exposure to substantial adverse changes in the prices of these commodities. We continuously monitor and ensure compliance with this Risk Management Policy through senior level executives in our operations, finance and legal departments.

The counterparties used for all of these transactions have investment grade ratings.

The Partnership has not designated these derivative instruments as hedges and as a result is marking these derivative contracts to market with changes in fair values recorded as an adjustment to the mark-to-market gains (losses) on risk management transactions within revenue.

NOTE 11. COMMITMENTS AND CONTINGENT LIABILITIES

Litigation—The Partnership is subject to several lawsuits which arise from time to time in the ordinary course of business, primarily related to the payments of liquids and natural gas proceeds in accordance with contractual terms. The Partnership had accruals of approximately $1.5 million as of March 31, 2008 and December 31, 2007, respectively, related to these matters. The Partnership has been indemnified up to a certain dollar amount for two of these lawsuits. For the indemnified lawsuits, the Partnership has not established any accruals as the likelihood of these suits being successful against them is considered remote. If there ultimately is a finding against the Partnership in the indemnified cases, 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.

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Insurance—The Partnership carries insurance coverage which includes the assets and operations, which management believes is consistent with companies engaged in similar commercial operations with similar type properties. These insurance coverages include (1) commercial general liability insurance for liabilities arising to third parties for bodily injury, property damage and pollution resulting from Eagle Rock Energy field operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage, (4) property insurance covering the replacement value of real and personal property damage, including damages arising from boiler and machinery breakdowns, earthquake, flood damage and business interruption/extra expense, (5) property and reservoir damage insurance for operated and non operated wells in the upstream segment, and (6) corporate liability policies including Directors and Officers coverage and Employment Practice liability coverage. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operation.

The Partnership also maintains excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits, terms, conditions and deductibles are comparable to those carried by other energy companies of similar size.

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, 2008 and December 31, 2007, the Partnership had accrued approximately $2.4 million and $2.4 million, respectively, for environmental matters.

Retained Revenue Interests—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, thus, our historical production volumes and proved reserves volumes are accurate as presented herein. The Partnership’s reported revenues are reduced to account for the payment of the retained revenue interests on a monthly basis.

With respect to the Flomaton and Fanny Church fields in Escambia County, Alabama, the Partnership is currently making payments in satisfaction of the retained revenue interests, and it expects these payments to continue through the end of 2009. With respect to the Partnership’s Big Escambia Creek field, these payments are to begin in 2010 and continue through the end of 2019.

Other Commitments—The Partnership utilizes assets under operating leases for its corporate office, certain rights-of way and facilities locations, vehicles and in several areas of its operation. Rental expense, including leases with no continuing commitment, amounted to approximately $1.3 million and $0.2 million for the three months ended March 31, 2008 and March 31, 2007, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term.

NOTE 12. SEGMENTS

Based on our approach to managing our assets, we believe our operations consist of three geographic segments in its midstream business, one upstream segment, one mineral segment and one functional (corporate) segment:

(i) Midstream—Texas Panhandle Segment:

gathering, processing, transportation and marketing of natural gas in the Texas Panhandle;

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(ii) Midstream—South Texas Segment:

gathering, processing, transportation and marketing of natural gas in South Texas;

(iii) Midstream—East Texas/Louisiana Segment:

gathering, processing and marketing of natural gas and related NGL transportation in East Texas and Louisiana;

(iv) Upstream Segment:

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

(v) Minerals Segment:

fee minerals, royalties and non-operated working interest ownership, lease bonus and rental income and equity in earnings of unconsolidated non-affiliate; and

(vi) Corporate Segment:

risk management and other corporate activities.

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

Midstream Segments Three Months Ended March 31, 2008	Texas Panhandle Segment		South Texas Segment		East Texas / Louisiana Segment		Total Midstream Segments
($ in millions)
Sales to external customers	$	156.3	$	98.5	$	70.4	$	325.2
Cost of natural gas and natural gas liquids		120.1		95.7		60.0		275.8
Operating costs and other expenses		7.7		0.7		3.5		11.9
Depreciation, depletion, amortization and impairment		10.7		0.9		2.9		14.5
Operating income	$	17.8	$	1.2	$	4.0	$	23.0
Capital Expenditures	$	4.2	$	0.4	$	4.8	$	9.4
Segment Assets		585.9		98.1		257.7		941.7

Three Months Ended March 31, 2008	Total Midstream Segments		Upstream Segment		Minerals Segment		Corporate Segment			Total Segments
($ in millions)
Sales to external customers	$	325.2	$	39.0	$	7.0	$	(45.7	)(a)	$	325.5
Cost of natural gas and natural gas liquids		275.8		—		—		—			275.8
Operating costs and other expenses		11.9		7.6		0.4		11.3			31.2
Depreciation, depletion, amortization and impairment		14.5		8.4		2.6		0.2			25.7
Operating income (loss)	$	23.0	$	23.0	$	4.0	$	(57.2	)	$	(7.2	)
Capital Expenditures	$	9.4	$	2.9	$	—	$	0.1		$	12.4
Segment Assets		941.7		469.1		142.7		65.4			1,618.9

Midstream Segments Three Months Ended March 31, 2007	Texas Panhandle Segment		South Texas Segment		East Texas / Louisiana Segment		Total Midstream Segments
($ in millions)
Sales to external customers	$	94.9	$	—	$	19.5	$	114.4
Cost of natural gas and natural gas liquids		75.7		—		15.0		90.7
Operating costs and other expenses		7.3		—		1.3		8.6
Depreciation, depletion, and amortization		9.8		—		1.7		11.5
Operating income	$	2.1	$	—	$	1.5	$	3.6
Capital Expenditures	$	8.8	$	—	$	13.6	$	22.4
Segment Assets		574.0		—		160.4		734.4

Three Months Ended March 31, 2007	Total Midstream Segments		Upstream Segment		Minerals Segment		Corporate Segment			Total Segments
($ in millions)
Sales to external customers	$	114.4	$	—	$	—	$	(7.6	)(a)	$	106.8
Cost of natural gas and natural gas liquids		90.7		—		—		—			90.7
Operating costs and other expenses		8.6		—		—		5.9			14.5
Depreciation, depletion, and amortization		11.5		—		—		0.2			11.7
Operating income (loss)	$	3.6	$	—	$	—	$	(13.7	)	$	(10.1	)
Capital Expenditures	$	22.4	$	—	$	—	$	1.1		$	23.5
Segment Assets		734.4		—		—		38.4			772.8

(a) Represents results of the Partnership’s derivative activities.

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NOTE 13. INCOME TAXES

Provision for Income Taxes –The Partnership’s provision for income relates to federal and state taxes for the Partnership and Federal Taxes for Eagle Rock Energy Acquisition Co., Inc. and Eagle Rock Upstream Development Company, Inc., its wholly owned corporations which are subject to federal income taxes.

As a result of the taxable income from the underlying partnership described above, net operating losses of $0.1 million were used during the three months ended March 31, 2008, which resulted in a partial release of the valuation allowances established for net operating losses at December 31, 2007.

Effective Rate – The provision for the first three months of 2008 reflects an estimated annual effective rate of 100%. The Partnership is organized as a pass through entity for income taxes. As a result, the overall effective rate for federal taxes is zero. However, the result of state based income taxes applied against book losses is a 100% effective rate for the first quarter of 2008.

Deferred taxes – As of March 31, 2008, the net deferred tax liability was $17.2 million compared to $17.5 million as of December 31, 2007 and is primarily attributable to book and tax basis differences of a partnership investment of Eagle Rock Upstream Development Company, Inc. These book/tax differences are expected to be reduced as allocation of depletion in proportion to the assets contributed brings the book and tax basis closer together over time.

Accounting for Uncertainty in Income Taxes –In accordance with FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes, the Partnership must recognize the tax effects of any uncertain tax positions it may adopt, if the position taken by the Partnership is more likely than not sustainable. If a tax position meets such criteria, the tax effect to be recognized by the Partnership would be the largest amount of benefit with more than a 50% chance of realized upon settlement. This guidance was effective January 1, 2007, and the Partnership’s adoption of this guidance had and continues to have no material impact on its financial position, results of operations or cash flows.

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

Although the bill states that the Revised Texas Franchise Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses.

NOTE 14. EQUITY-BASED COMPENSATION

On October 24, 2006, the general partner of the general partner for Eagle Rock Energy Partners, L.P., approved a long-term incentive plan (LTIP) for its employees, directors and consultants who provide services to the Partnership covering an aggregate of 1,000,000 common units to be granted either as options, restricted units or phantom units. During the restriction period, distributions associated with the granted awards will be distributed to the awardees. No options or phantom units have been issued to date.

A summary of the restricted common units’ activity for the quarter ended March 31, 2008, is provided below:

	Number of Restricted Units		Weighted Average Fair Value
Outstanding at December 31, 2007	467,062		$	23.01
Granted	55,100		$	15.98
Forfeitures	(14,468	)	$	22.66
Outstanding at March 31, 2008	507,694		$	22.26

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No restricted units vested during the three months ended March 31, 2008.

For the three months ended March 31, 2008 and March 31, 2007, non-cash compensation expense of approximately $1.2 million and $0.2 million, respectively, was recorded related to the granted restricted units.

As of March 31, 2008, unrecognized compensation costs related to the outstanding restricted units under our LTIP totalled approximately $9.5 million. The remaining expense is to be recognized over a weighted average of 2.5 years.

NOTE 15. EARNINGS PER UNIT

Basic earnings per unit is computed by dividing the net income, or loss, by the weighted average number of units outstanding during a period. To determine net income, or loss, allocated to each class of ownership (common, subordinated and general partner), we first allocated net income, or loss, by the amount of distributions made for the quarter by each class, if any. The remaining net income, or loss, after the deduction for the related quarterly distribution was 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.

We issued restricted, unvested common units at the time of the initial public offering, October 24, 2006 and subsequent award dates. These units will be considered in the diluted common unit weighted average number in periods of net income. In periods of net losses, the units are excluded from the diluted earnings per unit calculation due to their antidilutive effect.

The following table presents our calculation of basic and diluted earnings per unit for the periods indicated:

	Three Months Ended March 31,
($ in thousands, except per unit amounts)	2008			2007
Net (loss) income:	$	(28,328	)	$	(19,668	)
Net (loss) income allocated:
Common units		(19,410	)		(5,790	)
Subordinated units		(7,994	)		(13,334	)
General partner units		(326	)		(544	)
Weighted average unit outstanding during period:
Common units		50,700			20,691
Subordinated units		20,691			20,691
General partner units		845			845
Earnings Per Unit—continuing operations:
Common units	$	(0.39	)	$	(0.28	)
Subordinated units	$	(0.39	)	$	(0.64	)
General partner units	$	(0.39	)	$	(0.64	)

NOTE 16. SUBSEQUENT EVENTS

On April 30, 2008, the Partnership completed the acquisition of all of the outstanding capital stock of Stanolind Oil and Gas Corp. (the “Stanolind”), for an aggregate purchase price of $81.2 million, subject to working capital and other purchase price adjustments (the “Acquisition”). Eagle Rock funded the transaction from existing cash from operations as well as with borrowings under its existing Revolving Credit Facility. Stanolind Oil and Gas Corp. operates crude oil and natural gas producing properties in the Permian Basin, primarily in Ward, Crane and Pecos Counties, Texas.

One or more Natural Gas Partners’ private equity funds (“NGP”), which directly or indirectly owns a majority of the equity interests in Stanolind, is an affiliate of the Partnership and is the majority owner of the sole owner of Eagle Rock Energy G&P, LLC (the “Company”), which is the general partner of Eagle Rock Energy GP, L.P., which is the general partner of the Partnership. Because of the potential for conflict between the interests of the Company and the non-affiliated unitholders of the Partnership, the Board of Directors of the Company (the “Board”) authorized the Company’s Conflicts Committee to review, evaluate, and, if the Conflicts Committee deemed appropriate, approve the Acquisition. The Conflicts Committee, which consists of independent directors of the Board, determined that the Acquisition was fair and reasonable to Eagle Rock and its non-affiliated unitholders and recommended to the Board that the transaction be approved and authorized, and the Board subsequently approved and authorized the transaction.

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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, 2007, filed with the Securities and Exchange Commission. For a description of oil and natural gas terms, see such Annual Report.

Overview

We are a growth-oriented publicly traded Delaware limited partnership engaged in the following three businesses:

• Midstream Business—gathering, compressing, treating, processing, transporting and selling natural gas, fractionating and transporting natural gas liquids, or NGLs;

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

• Minerals Business—acquiring and managing fee minerals and royalty interests.

We report on our businesses in six accounting segments (see Note 12).

We conduct, evaluate and report on our Midstream Business within three distinct segments—the Texas Panhandle Segment, the East Texas/Louisiana Segment (formerly referred to by us in prior filings before our annual report on Form 10-K for the year ended December 31, 2007 and records as our Southeast Texas and North Louisiana Segment), and South Texas 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/Louisiana. Our South Texas Segment consists of gathering systems and related compression and processing facilities in South Texas.

We conduct, evaluate and report on our Upstream Business as one segment. Our Upstream Segment includes operated wells in Escambia County, Alabama and two treating facilities, one natural gas processing plant and related gathering systems that are inextricably intertwined with ownership and operation of the wells. The Upstream Segment also includes operated and non-operated wells that are primarily located in East and South Texas in Rains, Van Zandt, Henderson and Atascosa Counties, Texas.

We conduct, evaluate and report on our Minerals Business as one segment. Our Minerals Segment consists of certain fee minerals, royalties, overriding royalties and non-operated working interest properties, located in multiple producing trends across the United States, and interests in mineral acres and oil and gas wells.

The final segment that we report on is our Corporate Segment, in which we account for our commodity derivative/hedging activity and our general and administrative expenses.

We have an experienced management team dedicated to growing, operating and maximizing the profitability of our assets. Our management team is experienced in gathering and processing natural gas, operation of oil and natural gas properties and assets, and management of royalties and minerals.

Acquisitions

Historically, we have grown through acquisitions. With the Montierra Acquisition, described below, completed during the second quarter of 2007, we expanded our business from solely a midstream company to an upstream minerals company as well. With our Redman and EAC Acquisitions, described below, we further expanded our presence in the upstream business by adding operated working interests as well as other oil and natural gas interests and properties.

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

Below is a summary of our important acquisition transactions completed during the year ended December 31, 2007.

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Montierra Acquisition—On April 30, 2007, we completed the acquisition of (by direct acquisition or acquisition of certain entities) certain fee minerals, royalties and working interest properties from Montierra Minerals & Production, L.P. and NGP-VII Income Co-Investment Opportunities, L.P. (the “Montierra Acquisition”).

Laser Acquisition—On May 3, 2007, we acquired all of the non-corporate interests of Laser Midstream Energy, LP and certain subsidiaries (the “Laser Acquisition”).

MacLondon Acquisition—On June 18, 2007, we completed the acquisition of certain fee mineral and royalties owned by MacLondon Energy, L.P.

EAC Acquisition—On July 31, 2007, we completed the acquisition of Escambia Asset Co., LLC and Escambia Operating Company, LLC (the “EAC Acquisition”).

Redman Acquisition—On July 31, 2007, Eagle Rock Energy completed the acquisition of Redman Energy Holdings, L.P. and Redman Energy Holdings II, L.P. (Natural Gas Partners VII, L.P. and Natural Gas Partners VIII, L.P. portfolio companies, respectively) and certain assets owned by NGP Income Co-Investment Opportunities Fund II, L.P. (a Natural Gas Partners affiliate) (the “Redman Acquisition”).

Recent Acquisitions

On April 30, 2008, we completed the acquisition of all of the outstanding capital stock of Stanolind Oil and Gas Corp. (the “Stanolind”), for an aggregate purchase price of $81.2 million, subject to working capital and other purchase price adjustments (the “Acquisition”). We funded the transaction from existing cash from operations as well as with borrowings under our existing secured revolving credit facility. Stanolind Oil and Gas Corp. operates crude oil and natural gas producing properties in the Permian Basin, primarily in Ward, Crane and Pecos Counties, Texas.

Presentation of Financial Information

For a description of the presentation of our financial information in this report, please see Note 1 to the unaudited condensed consolidated financial statements.

How We Evaluate Our Operations

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

General Trends and Outlook

We expect our business to continue to be affected by the key trends as discussed in our annual report on Form 10-K for the year ended December 31, 2007. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

• Natural Gas Supply and Demand

• Petroleum Supply, Demand and Outlook

• Impact of Interest Rates and Inflation

Cautionary Note Regarding Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, include certain “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “continue,” “estimate,” “forecast,” “may,” “will,” or similar expressions help identify forward-looking statements. Although we believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that these objectives will be reached. Actual results may differ materially from any results projected, forecasted, estimated or expressed in forward-looking statements because many of the factors which determine these results are subject to uncertainties and risks, difficult to predict,

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and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see our annual report on Form 10-K for the year ended December 31, 2007, filed with the Securities and Exchange Commission on April 1, 2008.

Summary of Consolidated Operating Results

Below is a summary table of our consolidated operating results for the three months ended March 31, 2008 and March 31, 2007, respectively. Operating results for our individual operating segments are presented in tables in this Item 2.

	Three Months Ended March 31,
($ in thousands)	2008			2007
Revenues:
Sales of natural gas, NGLs, oil, condensate and sulfur	$	357,019		$	110,121
Gathering and treating services		7,143			4,283
Minerals and royalty income		6,958			—
Commodity derivatives		(45,647	)		(7,642	)
Other		60			—
Total revenues		325,533			106,762
Cost of natural gas and natural gas liquids		275,831			90,636
Expenses:
Operating		19,913			8,626
General and administrative		11,242			4,220
Other expense		—			1,711
Depreciation, depletion, and amortization		25,745			11,630
Total costs and expenses		56,900			26,187
Total operating loss		(7,198	)		(10,061	)
Other income (expense):
Interest income		301			124
Other income		1,547			—
Interest expense		(9,205	)		(7,559	)
Unrealized interest rate derivatives		(13,660	)		(1,611	)
Other expense		(215	)		(397	)
Total other income (expense)		(21,232	)		(9,443	)
Loss before taxes		(28,430	)		(19,504	)
Income tax (benefit) provision		(102	)		164
Net loss	$	(28,328	)	$	(19,668	)
Adjusted EBITDA(a)	$	52,778		$	14,093

(a) See Non-GAAP Financial Measures within Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations for a definition and reconciliation to GAAP.

For the three months ended March 31, 2008, based on operating income of our non-Corporate segments, our midstream business comprised approximately 46.1% of our business (with the Texas Panhandle Segment accounting for 35.6% of our business, the South Texas Segment accounting for 2.4% of our business, and the East Texas/Louisiana Segment accounting for 8.1% of our business), our upstream business comprised approximately 46.1% of our business, and our minerals business comprised approximately 7.8% of our business. We intend to acquire and construct additional assets in both our midstream and upstream businesses, and we intend to be opportunistic with potential acquisitions for our minerals business.

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Midstream Business (Three Segments)

Texas Panhandle Segment

	Three Months Ended March 31,
($ in thousands)	2008		2007
Revenues:
Sales of natural gas, NGLs, oil and condensate	$	153,855	$	92,780
Gathering and treating services		2,469		2,136
Total revenues		156,324		94,916
Cost of natural gas and natural gas liquids		120,118		75,647
Operating costs and expenses:
Operating		7,748		7,344
Depreciation and amortization		10,709		9,782
Total operating costs and expenses		18,457		17,126
Operating income	$	17,749	$	2,143

Revenues and Cost of natural gas and natural gas liquids.For the three months ended March 31, 2008, the revenues minus cost of natural gas and natural gas liquids for our Texas Panhandle Segment operations totaled $36.2 million compared to $19.3 million for the three months ended March 31, 2007. There were two primary contributors to this increase: (i) higher NGL and condensate pricing, as compared to pricing in 2007, and (ii) higher natural gas liquids production as compared to production in 2007.

For the three months ended March 31, 2008, this Segment gathered an average of 154.6 MMcf/d of natural gas on its pipelines and processed an average of 128 MMcf/d of natural gas as compared to gathering an average of 140 MMcf/d of natural gas on its pipelines and processing an average of 111.4 MMcf/d of natural gas during the three months ended March 31, 2007. During the three months ended March 31, 2008, we recovered an average of 12.027 Bbls/d of NGLs of which our equity share was 3,547 Bbls/d compared to an average of 10,471 Bbls/d of NGLs recovered during the three months ended March 31, 2007, of which our equity share was 3,206 Bbls/d. During the three months ended March 31, 2008 we recovered an average of 2,114 Bbls/d of condensate from our gathering systems of which our equity share was 2,080 Bbls/d as compared to 2,184 Bbls/d of condensate from our gathering systems of which our equity share was 2,100 Bbls/d.

The higher 2008 throughput volumes compared to 2007 was primarily due to the colder than normal weather in that area which reduced production during the three months ended March 31, 2007 and the start-up of the Red Deer Plant in June 2007.

The drilling activity in the West Panhandle System is not sufficient to offset the natural declines experienced on the System. While our contract mix in the West Panhandle System provides us with a higher equity share of the production, the overall decline will continue and we expect to recover smaller equity production in the future on the West Panhandle System. The East Panhandle System continues to experience strong growth in volumes and equity production due to the active Granite Wash drilling play located in Roberts and Hemphill Counties, Texas. The liquids content of the natural gas is lower in the East Texas Panhandle System and our contract mix provides us with a smaller share of equity production as compared to the West Panhandle System. Due to this difference in contract mix and liquid content between our West and East Panhandle Systems, while we have grown aggregate volumes during the three months ended March 31, 2008 as compared to the three months ended March 31, 2007, our equity share of liquids production would have been less through the three months ended March 31, 2007 if 2007 had been a normal winter. Our current goal is to grow volumes aggressively in the East Panhandle System to offset the decline in volumes and our share of equity production in the West Panhandle System. The start-up of the Red Deer Plant in June 2007 provided an additional 20 MMcf/d of processing capacity in our East Panhandle System that was immediately utilized by our customers.

Operating Expenses.Operating expenses, including taxes other than income, for three months ended March 31, 2008 were $7.7 million compared to $7.3 million for the three months ended March 31, 2007. The major items impacting the $0.4 million increase in operating expense were primarily the operations of the Red Deer Plant, which was brought on line in June 2007.

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Depreciation and Amortization. Depreciation and amortization expenses for three months ended March 31, 2008 were $10.7 million compared to $9.8 million for the three months ended March 31, 2007. The major items impacting the $0.9 million increase was placing the Red Deer Plant into service and beginning the depreciation expense associated with the capital expenditure.

Capital Expenditures.Capital expenditures for three months ended March 31, 2008 were $4.2 million compared to $8.8 million for the three months ended March 31, 2007. We classify capital expenditures as either maintenance capital which represents routine well connects and capitalized maintenance activities or as growth capital which represents organic growth projects. In the three months ended March 31, 2008, growth capital represented 74% of our capital expenditures as compared to 76% in the three months ended March 31, 2007. Our decrease in capital of $3.4 million was driven by delayed drilling by a key producer ($0.5 million), lower overhaul costs of equipment ($0.4 million) and less growth capital due to expenditures in 2007 on the new Red Deer Plant ($2.5 million).

East Texas/Louisiana Segment

	Three Months Ended March 31,
($ in thousands)	2008		2007
Revenues:
Sales of natural gas, NGLs, oil and condensate	$	66,959	$	17,341
Gathering and treating services		3,448		2,147
Total revenues		70,407		19,488
Cost of natural gas and natural gas liquids		60,019		14,989
Operating costs and expenses:
Operating		3,480		1,282
Depreciation and amortization		2,869		1,675
Total operating costs and expenses		6,349		2,957
Operating income	$	4,039	$	1,542

Revenues and Cost of natural gas and natural gas liquids. For the three months ended March 31, 2008, revenues minus cost of natural gas and natural gas liquids for our East Texas/Louisiana Segment totaled $10.4 million compared to $4.5 million for the three months ended March 31, 2007. During the three months ended March 31, 2008, this segment gathered an average of 163.7 MMcf/d of natural gas on its pipelines and processed an average of 152.2 MMcf/d of natural gas as compared to gathering an average of 89.6 MMcf/d of natural gas on its pipelines and processing an average of 84.2 MMcf/d of natural gas during the three months ended March 31, 2007. During the three months ended March 31, 2008, we produced an average of 6,297 Bbls/d of NGLs of which our equity share was 1,295 Bbls/d compared to 4,201 Bbls/d of NGLs of which our equity share was 707 Bbls/d during the three months ended March 31, 2007. We recovered during the three months ended March 31, 2008 an average of 110 Bbls/d of condensate from our gathering systems of which our equity share was 92 Bbls/d compared to an average of 137 Bbls/d of condensate from our gathering systems of which our equity share was 87 Bbls/d during the three months ended March 31, 2007.

The Laser Acquisition positively impacted the East Texas/Louisiana Segment by $3.3 million during the three months ended March 31, 2008. The assets acquired in the Laser Acquisition added 50.7 MMcf/d average volume and 250 Bbls/d of NGL production.

We were positively impacted from higher NGL and condensate pricing during the three months ended March 31, 2008 as compared to the three months ended March 31, 2007. We were positively impacted by an 83% gathering volume growth during the three months ended March 31, 2008 compared to the three months ended March 31, 2007. Volumes increased due to both the Laser Acquisition and continued drilling in the Austin Chalk play in Tyler and Jasper Counties, Texas. Excluding the Laser Acquisition, our gathering volumes increased by 26%. The Tyler County Pipeline Extension completed in March 2007, connected the Tyler County Pipeline to our Brookeland gathering system providing an additional 50 MMcf/d of outlet capacity for the Tyler County Pipeline. The Austin Chalk’s production profile is characterized by steep initial declines in new wells requiring active drilling programs by producers to maintain or grow volumes. We have also constructed a new seven mile lateral from our Brookeland gathering system into an active Austin Chalk drilling area where we have a large dedicated acreage position under a life-of-lease contract with Anadarko Exploration and Production Company. Depending upon the success of Anadarko’s drilling activities on this acreage, this area may provide added volume growth to the segment during 2008.

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Operating Expenses.Operating expenses for the three months ended March 31, 2008 were $3.5 million compared to $1.3 million in for the three months ended March 31, 2007. The major items impacting the $2.2 million increase in operating expense were (i) $1.8 million for the three months that we have owned the assets in 2008 that were a part of the Laser Acquisition and (ii) $0.3 million expenses for operating compression due to increased natural gas volumes on the Tyler County Pipeline.

Depreciation and Amortization.Depreciation and amortization expenses for the three months ended March 31, 2008 were $2.9 million compared to $1.7 million in for the three months ended March 31, 2007. The major items impacting the $1.2 million increase were (i) the inclusion of three months of the Laser Acquisition, (ii) a full year and placing the Tyler County Pipeline Extension into service and beginning the depreciation expense associated with the capital expenditure.

Capital Expenditures.Capital expenditures for the three months ended March 31, 2008 were $4.8 million compared to $13.6 million in for the three months ended March 31, 2007. We classify capital expenditures as either maintenance capital which represents routine well connects and capitalized maintenance activities or as growth capital which represents organic growth projects. Our decrease in capital spending of $8.8 million is due primarily to the construction and start-up of the Tyler County Pipeline Extension in March 2007.

South Texas Segment

	Three Months Ended March 31,
($ in thousands)	2008		2007
Revenues:
Sales of natural gas, NGLs, oil and condensate	$	97,239	$	—
Gathering and treating services		1,226		—
Other		2		—
Total revenues		98,467		—
Cost of natural gas and natural gas liquids		95,694		—
Operating costs and expenses:
Operating		653		—
Depreciation and amortization		939		—
Total operating costs and expenses		1,592		—
Operating income	$	1,181	$	—

Revenues and Cost of natural gas and natural gas liquids.This segment was a new area of operations for us as we entered this segment as a result of the Laser Acquisition, effective May 2007. During the three months ended March 31, 2008 the South Texas Segment contributed $2.8 million in revenues minus cost of natural gas and natural gas liquids. There are two primary activities in this segment: (i) volumes of natural gas gathered on our own assets, which represented 90% of revenues minus cost of natural gas and natural gas liquids for this segment and (ii) producer services, providing marketing and pipeline connection services to small independent producers and to third party pipeline systems, which accounted for 10% of revenues minus cost of natural gas and natural gas liquids.

Two significant items that will continue to add value to this area are (i) a pipeline extension to connect Chesapeake Energy Corporation’s and other operator’s production to our Phase 1 20” Pipeline and (ii) the construction of the Kelsey Compressor Station on our Phase 1 20” Pipeline which will provide access to Exxon’s King Ranch processing facility, resulting in an incremental 24 MMcf/d of capacity. The construction of this station will enable us to continue to increase volumes on our Phase 1 20” Pipeline provided that drilling activity and our commercial success to contract for the natural gas continues in 2008.

Operating Expenses.Operating expenses for the three months ended March 31, 2008 were $0.7 million.

Depreciation and Amortization.Depreciation and amortization expenses for the three months ended March 31, 2008 were $0.9 million.

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Capital Expenditures.Capital expenditures for the three months ended March 31, 2008 were $0.4 million.

Upstream Segment

	Three Months Ended March 31,
($ in thousands)	2008		2007
Revenues:
Oil and condensate	$	18,333	$	—
Natural gas		7,126		—
NGLs		8,140		—
Sulfur		5,367		—
Other		58		—
Total revenues		39,024		—
Operating Costs and expenses:
Operating		7,589		—
Depletion, depreciation and amortization		8,425		—
Total operating costs and expenses		16,014		—
Operating income	$	23,010	$	—

Revenues.The Upstream Segment became a new line of business for the Partnership during 2007. The assets were acquired on July 31, 2007. During the three months ended March 31, 2008, the Upstream Segment contributed $39.0 million of revenues. Production averaged 30.9 MMcfe/d during the period and was negatively impacted by curtailed production at Big Escambia Creek, Flomaton and Fanny Church fields during a portion of the quarter. Production at Big Escambia Creek field was partially curtailed for 31 days due to sulfur recovery limitations ahead of a planned April 2008 turnaround at the Big Escambia Creek treating facility. Gas production from Flomaton and Fanny Church fields was restricted from sales for 25 days during the quarter associated with a third party’s gas quality issue at the point of sales. Oil sales from both Flomaton and Fanny Church fields continued during this period of curtailment. The Upstream segment benefited from higher commodity prices received for its oil, condensate, natural gas and sulfur products as compared to 2007.

Operating Expenses. Operating expenses, including severance and ad valorem taxes, totaled $7.6 million for the Upstream Segment during the three months ended March 31, 2008. Excluding severance and ad valorem taxes, the most significant portion of operating expenses were associated with operating the Big Escambia Creek and Flomaton treating and processing facilities. These facilities are required to extract the H2S and CO2 to achieve pipeline sales quality specifications, as well as beneficially extracting natural gas liquids and sulfur for sale. The remaining operating expenses are attributed to base lease operating expenses and well workovers.

Depletion, Depreciation and Amortization.Depletion, depreciation and amortization expense for the three months ended March 31, 2008 was $8.4 million.

Capital Expenditures.All Upstream Segment capital expenditures during the period, totaling $2.9 million, were categorized as maintenance capital. The capital expenditures were associated with the completion of one operated well in the Big Escambia Creek field, two operated recompletions in the Jourdanton field, and an operated capital workover in the Wesson field. In addition, certain capital facility projects were conducted in each of the new asset areas. The Partnership participated in small non-operated working interest projects consisting of four drilling wells and two recompletions.

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Minerals Segment

	Three Months Ended March 31,
($ in thousands)	2008		2007
Revenues:
Oil and condensate	$	3,367	$	—
Natural gas		2,209		—
NGLs		235		—
Lease bonus, rentals and other		1,147		—
Total revenues		6,958		—
Operating Costs and expenses:
Operating		443		—
Depreciation and depletion		2,611		—
Total operating costs and expenses		3,054		—
Operating Income	$	3,904	$	—

Revenues.The Minerals Segment became a new line of business for the Partnership during 2007. The assets were acquired on April 30, 2007. Our net average production associated with our Minerals Segment the three months ended March 31, 2008 was approximately 411 barrels of oil, 3.5 MMcf of natural gas, and 46 bbls of natural gas liquids per day. The production rate during the period remained essentially flat due to drilling, recompletion and workover operations conducted by the various operators of the properties.

Our realized average prices during the three months ended March 31, 2008 in the Minerals Segment (excluding the effect of hedging) were $89.00/Bbl of oil, $6.99/Mcf of natural gas, and $55.98/Bbl of natural gas liquids. Prices for these commodities rose during the period.

We received approximately $1.1 million in bonus and delay rental payments during the three months ended March 31, 2008. Substantially all of this was derived from our ownership in the Pure Minerals. The amount of revenue we receive from bonus and rental payments varies significantly from month to month. Therefore, we do not believe a meaningful set of conclusions can be drawn by observing changes in leasing activity over small time periods. Nevertheless, due to high commodity prices, we expect leasing activity to remain robust and expect to see similar levels of bonus income in future periods.

Operating Expenses. Operating expenses of $0.4 million during the three months ended March 31, 2008 are predominately production and ad valorem taxes. These taxes are levied by various state and local taxing entities, and were approximately 6.4% of our production revenue.

Depletion, depreciation and amortization. Under the Successful Efforts method of accounting, we calculate depletion, depreciation and amortization using the units of production method. In the case of our Minerals Segment, we only claim proved, producing reserves because, as a mineral interest owner, we lack sufficient engineering and geological data to estimate the proved undeveloped and non-producing reserve quantities, and because we cannot control the occurrence or the timing of the activities that would cause such reserves to become productive. Since our units of production depletion and amortization rate is a function of our proved reserves, we experience a higher depletion and amortization rate than we would if we claimed undeveloped or non-producing reserves. Our depletion, depreciation and amortization rate during the three months ended March 31, 2008 was $4.60/Mcfe, and our depletion, depreciation and amortization expenses were approximately $2.6 million.

One of the distinctive characteristics of our large, diversified mineral position is that operators are continually conducting exploration and development drilling, recompletion, and workover operations on our interests. We do not pay for these operations, but we do receive a share of the production they generate. This mode of operation has resulted in relatively constant production rates from our mineral interests in the last several years, and we expect that this will continue. We refer to this phenomenon as “regeneration”. The new sources of production that we expect to materialize due to regeneration will also be the source of future extensions and discoveries, and positive revisions to our reserve estimates, which may effect out future depletion and amortization rates. During the three months ended March 31, 2008, we received an initial royalty payment for 59 new wells.

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Corporate Segment

	Three Months Ended March 31,
($ in thousands)	2008			2007
Revenues:
Unrealized commodity derivative losses	$	(33,072	)	$	(10,641	)
Realized commodity derivative (losses) gains		(12,575	)		2,999
Total revenues		(45,647	)		(7,642	)
General and administrative		11,242			4,220
Depreciation and amortization		192			173
Other expense		—			1,711
Total costs and expenses		11,434			6,104
Operating loss		(57,081	)		(13,746	)
Other income (expense):
Interest income		301			124
Other income		1,547			—
Interest expense, net		(9,205	)		(7,559	)
Unrealized interest rate derivatives		(13,660	)		(1,611	)
Other expense		(215	)		(397	)
Total other income (expense)		(21,232	)		(9,443	)
Loss before taxes		(78,313	)		(23,189	)
Income tax (benefit) provision		(102	)		164
Segment loss	$	(78,211	)	$	(23,353	)

Revenues. As a master limited partnership, we distribute Available Cash (as defined in our partnership agreement) every quarter to our unitholders. The volatility inherent in commodity prices generates uncertainty around achieving a steady flow of available cash. We counter this by entering into certain derivative transactions to reduce our exposure to commodity price risk and reduce uncertainty surrounding our cash flows.

Our Corporate Segment’s revenues, which solely include our commodity derivatives activity, decreased to a loss of $45.6 million for the three months ended March 31, 2008, from a loss of $7.6 million for the three months ended March 31, 2007. As a result of our commodity hedging activities, revenues include a total realized loss of $12.6 million on risk management activity that was settled during the three months ended March 31, 2008, and an unrealized mark-to-market loss of $33.1 million for three months ended March 31, 2008, as compared to a realized gain of $3.0 million on risk management activity that was settled for the three months ended March 31, 2007 and an unrealized mark-to-market net loss of $10.6 million for the three months ended March 31, 2007.

As the forward price curves for our hedged commodities shift in relation to the caps, floors, swap and strike prices at which we have executed our derivative instruments, the fair market value of such instruments changes through time. The unrealized, non-cash mark-to-market net loss in the first quarter of 2008 and the first quarter of 2007 reflects overall favorable forward curve price movements as they relate to our physical volumes sales during the three month period for commodities underlying the derivative instruments. The unrealized mark-to-market loss for the three months ended March 31, 2008 of $33.1 million reflects $30.8 million in losses related to our crude oil, NGL and natural gas positions as the forward curve prices in these commodities increased during the year, as well as a $2.3 million loss related to amortization of put premiums during the term of the underlying options. The unrealized mark-to-market net loss for the three months ended March 31, 2007 of $10.6 million NGL position and crude oil as the forward curve prices in these commodities decreased during the year, is comprised of a $8.5 million loss related to our natural gas position as the forward curve price increased during the year and a $2.1 million loss related to amortization of put premiums during the term of the underlying options. Neither the unrealized mark-to-market net loss of $10.6 million for the three months ended March 31, 2007 nor the unrealized mark-to-market loss of $33.1 million for the three months ended March 31, 2008 had an impact on cash activities for those periods, as applicable, and as such are excluded from our calculation of Adjusted EBITDA.

Given the uncertainty surrounding future commodity prices, and the general inability to predict these as they relate to the caps, floors, swaps and strike prices at which we have hedged our exposure, it is difficult to predict the

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

General and Administrative Expenses. General and administrative expenses increased by $7.0 million from $4.2 million for the three months ended March 31, 2007 to $11.2 million for the three months ended March 31, 2008. This growth in general and administrative expenses was mostly driven by increased head-count in our corporate office as a result of our 2007 acquisitions, our expansion into the minerals and upstream businesses related to the Montierra, Redman and EAC acquisitions, and to recruiting efforts in accounting, back-office, engineering, land and operations-related corporate personnel associated with being a public partnership. Corporate-office payroll expenses increased by $3.5 million as a result. Also, our public partnership expenses related to audit, tax, Sarbanes-Oxley compliance and others increased by $0.4 million. In addition, expenses related to outside professional service, impacted our general and administrative expenses expense by $1.4 million and insurance costs increased by $0.2 million as we insured our acquired assets. Further, IT infrastructure increased by $0.3 million and we recorded other miscellaneous expenses of $1.2 million.

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

Total other income (expense). Which includes both realized and unrealized gains/losses from our interest rate swaps, increased to $21.2 million for the three months ended March 31, 2008, as compared to $9.4 million for the three months ended March 31, 2007. This increase is a result of an increase in our debt outstanding from $405.7 million as of March 31, 2007, to $557.0 million as of March 31, 2008. This increase in funded debt results from our debt financing of several acquisitions and organic projects during 2007, including the Tyler County Pipeline Expansion, Red Deer processing plant project and the acquisitions of Redman and EAC, partially financed by a $106 million draw from our credit facility. In addition, increased base interest rate and a higher interest rate margin also increased our interest expense. We entered into a new senior revolving credit facility on December 13, 2007, which carries a lower interest rate margin than our previous credit facility. This lower interest rate margin favourably impacted our interest expense during the three months ended March 31, 2008.

Total other income (expense) for the three months ended March 31, 2008, includes a realized interest rate swap realized loss of $0.1 million. We also recorded an unrealized mark-to-market loss of $13.7 million related to our interest rate risk management position. The unrealized loss relates to our future period interest swaps and from changes during the quarter in the underlying interest rate associated with the derivatives. The unrealized mark-to-market loss did not have any impact on cash activities for the period, and is excluded by definition from our calculation of Adjusted EBITDA.

Adjusted EBITDA. Adjusted EBITDA as defined, increased by $38.7 million from $14.1 million for the three months ended March 31, 2007 to $52.8 million for the three months ended March 31, 2008.

As described above, revenues minus cost of natural gas and natural gas liquids for the Midstream Segment (including the Texas Panhandle, East Texas / Louisiana and the newly created South Texas Segment) grew by $25.6 million as compared to the three months ended March 31, 2007. The acquisitions leading to our entry into our Upstream and Mineral Segments contributed $39.0 million and $7.0 million, respectively, to revenues while our Corporate Segment’s realized commodity derivatives loss increased by $15.6 million as compared to the three months ended March 31, 2007. This resulted in $56.0 million of total incremental revenues minus cost of natural gas and natural gas liquids, adjusted to exclude the impact of un-realized commodity derivatives not included in the calculation of Adjusted EBITDA, with respect to the three months ended March 31, 2007.

Operating expenses (including taxes other than income), increased by $3.3 million for our Midstream Segment with respect to the three months ended March 31, 2007, while the acquisitions which created the Upstream and Minerals Segments contributed incremental Operating Expenses (including taxes other than income) of $7.6 million and $0.4 million, respectively. This resulted in total incremental operating expenses of $11.3 million, as compared to the three months ended March 31, 2007.

General and administrative expense, captured in the Corporate Segment, increased by $6.0 million adjusted to exclude non-cash compensation charges related to our LTIP program, while other operating expense decreased by $1.7 million, with respect to the three months ended March 31, 2007.

As a result, revenues (excluding the impact of unrealized commodity derivative activity) minus cost of natural

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gas and natural gas liquids increased by $56.0 million, operating expenses increased by $11.3 million, general and administrative expenses increased by $6.0 million and other expense decreased by $1.7 million, resulting in an increase to Adjusted EBITDA of $38.7 million from the three months ended March 31, 2007 to the three months ended March 31, 2008.

Income Tax (Benefit) Provision. Income tax benefit recorded during the three months ended March 31, 2008 reflects the Texas Margin Tax recorded during the current year offset by the reduction of the deferred tax liability created by the book/tax differences as a result of the acquisition of Redman Energy Corporation on July 31, 2007.

Liquidity and Capital Resources

Historically, our sources of liquidity have included cash generated from operations, equity investments by our owners and borrowings under our existing credit facilities. More recently, we have successfully raised significant resources through the private placement of our common units among institutional investors.

We believe that the cash generated from these sources will continue to be sufficient to meet our minimum quarterly cash distributions and our requirements for short-term working capital and long-term capital expenditures for at least the next twelve months.

In the event that we acquire additional midstream assets or natural gas or oil properties that exceed our existing capital resources, we expect that we will finance those acquisitions with a combination of expanded or new debt facilities and, if necessary, new equity issuances. The ratio of debt and equity issued will be determined by our management and our board of directors as deemed appropriate.

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, 2008, working capital was $(17.8) million as compared to a $15.1 million balance as of December 31, 2007.

The net decrease in working capital of $32.9 million from December 31, 2007 to March 31, 2008, resulted primarily from the following factors:

• cash balances and marketable securities, net of due to affiliates, decreased overall by $16.6 million and was impacted primarily by the distributions paid on February 15, 2008 with respect to the fourth quarter of 2007 financial results, the results of operations, timing of capital expenditures payments, and financing activities including our debt activities;

• the due to affiliate liability of $16.8 million as of March 31, 2007 is owed to Eagle Rock Energy G&P, LLC;

• trade accounts receivable increased by $28.4 million primarily from the impact of higher commodity prices on our consolidated revenue;

• risk management net working capital balance decreased by a net $25.1 million as a result of the changes in current portion of the mark-to-market unrealized positions and amortization of the option premiums;

• accounts payable increased by $23.0 million from December 31, 2007 primarily as a result of activities and timing of payments, including capital expenditures activities; and

• accrued liabilities decreased by $1.7 million primarily reflecting unbilled expenditures related primarily to capital expenditures and activities from the acquisitions during the year.

Cash Flows Three Months Ended March 31, 2008 Compared to Three Months Ended March 31, 2007

Cash Flow from Operating Activities. Increase of $19.0 million during the three months ended March 31, 2008 with respect to the three months ended March 31, 2007 is the result of increased income from both the acquired assets and the growth capital expenditure projects, as well as higher commodity prices.

Cash Flows From Investing Activities. Cash flows used for investing activities for the three months ended March 31, 2008, as compared to the three months ended March 31, 2007, decreased by $7.6 million. The investing activities for the current period reflect a lower capital expenditure level of $8.2 million versus $16.1 million for the prior year period. In addition, cost for acquiring intangibles, primarily pipeline rights-of-way increased by $0.3 million.

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Cash Flows From Financing Activities. Cash flows used for financing activities during the three months ended March 31, 2008, increased by $34.8 million, over the three months ended March 31, 2007. Key differences between periods include repayments of our revolving credit facility of $10.1 million. Distributions to members represented a cash outflow of $28.5 million during the three months ended March 31, 2008, as compared to $6.1 million during the three months ended March 31, 2007.

Revolving Credit Facility

On December 13, 2007, we entered into a credit agreement with Wachovia Bank, National Association, as administrative agent and swingline lender, Bank of America, N.A., as syndication agent, HSH Nordbank AG, New York Branch, the Royal Bank of Scotland, plc, and BNP Paribas, as co-documentation agents, and the other lenders who are parties to the agreement with aggregate commitments up to $800 million. Concurrently with and at the effectiveness of the new credit agreement, all of our commitments under our previous $600 million Amended and Restated Credit and Guaranty Agreement among the Partnership, as borrower, Goldman Sachs Credit Partners L.P., as administrative agent and the several lenders who are parties to the prior credit agreement were cancelled and terminated. The new credit agreement provided terms and pricing options more favorable than the prior credit agreement. Initial availability under the new credit agreement, based on financial covenants, was $725 million. The maximum amount of the credit facility may, at our request and subject to the terms and conditions of the credit facility, be increased up to $1 billion. The credit agreement is scheduled to expire on December 13, 2012. We did not initially increase the amount of debt outstanding over what was outstanding under the prior credit agreement other than to pay accrued interests.

Capital Requirements

As we continue to expand our Midstream Business (all three segments), our Upstream Segment, and our Mineral Segment through acquisitions and organic projects, our need for capital, both as growth capital and as maintenance capital, continues to increase. We anticipate that we will have sufficient access to capital to grow, maintain and commercially exploit the Midstream Business (all three segments), Upstream Segment, and Mineral Segment assets.

As an operator of upstream assets and as a working interest owner, our capital requirements have increased to maintain those properties and to replace depleting resources. We anticipate that we will meet these requirements through cash generated from operations, equity issuances, or debt incurrence; however, we cannot provide assurances that we will be able to obtain the necessary capital under terms acceptable to us.

Our 2008 capital budget anticipated that we would spend approximately $10.9 million in the three months ended March 31, 2008 on our existing assets. We actually spent approximately $12.4 million in total during that period, primarily in the drilling of the St Regis 9-11 #1 well in the Big Escambia Creek Field, Escambia County, AL, the Stinnett Shutdown and relocation to Arrington project in the Texas Panhandle, the Anadarko SAG pipeline project located in Jasper County, Texas and Cargray Residue pipeline project located in the Texas Panhandle and various well connections and maintenance capital (in both our Upstream and Midstream Segments).

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 additional assets to increase our business, to expand and upgrade existing systems and facilities or to construct or acquire similar systems or facilities, or grow our production in our upstream business; or

• maintenance capital expenditures, which are made to replace partially or fully depreciated assets, to meet regulatory requirements, to maintain the existing operating capacity of our assets and extend their useful lives, or to connect wells to maintain existing system volumes and related cash flows; in our upstream business, maintenance capital is defined as capital which is expended to maintain our production and cash flow levels in the near future.

Since our inception in 2002, we have made substantial growth capital expenditures. We anticipate we will continue to make significant growth capital expenditures and acquisitions. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives.

We continually review opportunities for both organic growth projects and acquisitions which will enhance our financial performance. Because we will distribute most of our available cash to our unitholders, we will depend on borrowings under our Revolving Credit Facility and the issuance of debt and equity securities to finance any future growth capital expenditures or acquisitions.

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Our 2008 capital budget anticipates that we will spend approximately $54.3 million in total for the year on our existing assets. This budget includes capital expenditures for growth, maintenance and well connect projects in both our Midstream and Upstream Segments. We intend to finance our maintenance capital expenditures (including well connect costs) with internally generated cash flow, and our growth capital expenditures with draws from our Revolving Credit Facility.

Off-Balance Sheet Obligations.

We have no off-balance sheet transactions or obligations.

Debt Covenants.

At March 31, 2008, we were in compliance with the covenants of our credit facilities.

Recent Accounting Pronouncements

In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements. This statement defines fair value, establishes a framework for measuring fair value, and expands disclosure about fair value measurements. The statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. SFAS No. 157, as it relates to financial assets and liabilities, was effective for us on January 1, 2008 and had no impact on our consolidated results of operations and financial position.

In February 2008, the FASB issued FASB Staff Position (“FSP”) No. FAS 157-2, “Effective Date of FASB Statement No. 157” (“FSP FAS 157-2”), which delays the effective date of SFAS 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on at least an annual basis, until fiscal years beginning after November 15, 2008. The Partnership is currently evaluating the potential impact of adopting FSP FAS 157-2, if any, on its consolidated financial statements.

In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities(“SFAS No. 159”), which permits entities to choose to measure many financial instruments and certain other items at fair value. SFAS No. 159 was effective for us as of January 1, 2008 and had no impact as we have elected not to measure additional financial assets and liabilities at fair value.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS No. 141R”), which replaces SFAS No. 141. SFAS No. 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired in connection with a business combination. The Statement also establishes disclosure requirements that will enable users to evaluate the nature and financial effect of the business combination. SFAS No. 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of an entity’s first fiscal year that begins after December 15, 2008. We are currently evaluating the potential impact, if any, of the adoption of SFAS No. 141R on the Partnership’s financial statements.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 requires that accounting and reporting for minority interests will be recharacterized as noncontrolling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. This Statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008. We have not yet determined the impact, if any, that SFAS No. 160 will have on its financial statements.

In March 2008, the FASB issued Statement No. 161,Disclosures About Derivative Instruments and Hedging Activities(“SFAS No. 161”). SFAS No. 161 requires enhanced disclosures to help investors better understand the effect of an entity’s derivative instruments and related hedging activities on its financial position, financial performance, and cash flows. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. We have not yet determined the impact, if any, that SFAS No. 161 will have on its financial statements.

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In March 2008 the FASB approved EITF Issue No. 07-4,Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships, which requires that master limited partnerships use the two-class method of allocating earnings to calculate earnings per unit. EITF Issue No. 07-4 is effective for fiscal years and interim periods beginning after December 15, 2008. We are evaluating the effect that EITF Issue No. 07-4 will have on our earnings per unit calculation and financial statements.

Non-GAAP Financial Measures

We include in this filing the following non-GAAP financial measure, Adjusted EBITDA. We provide reconciliations of this non-GAAP financial measure to its most directly comparable financial measures as calculated and presented in accordance with GAAP.

We define Adjusted EBITDA as net income (loss) plus income tax provision, interest-net (including both realized and unrealized interest rate risk management activities), depreciation, depletion, and amortization expense, other operating expense, other non-cash operating and general and administrative expenses (including non-cash compensation related to our equity-based compensation program) less non-realized revenues risk management instrument gain (loss) activities and other income/expense. Adjusted EBITDA is useful in determining our ability to sustain or increase distributions. By excluding unrealized derivative gains (losses), a non-cash 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.

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

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 earnings determined under GAAP, as well as Adjusted EBITDA, to evaluate our liquidity. Our Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

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	Three Months Ended March 31,
($ in thousands)	2008			2007
Reconciliation of “Adjusted EBITDA” to net cash flows provided by operating activities and net loss
Net cash flows provided by operating activities	$	33,145		$	14,181
Add (deduct):
Depreciation, depletion and amortization		(25,745	)		(11,630	)
Amortization of debt issuance costs		(217	)		(416	)
Risk management portfolio value changes		(46,732	)		(12,254	)
Net realized (loss) gain on derivatives		(2,278	)		100
Other		142			(293	)
Accounts receivables and other current assets		30,214			443
Accounts payable, due to affiliates and accrued liabilities		(17,691	)		(9,875	)
Other assets and liabilities		834			76
Net loss		(28,328	)		(19,668	)
Add (deduct):
Interest (income) expense, net		9,119			7,832
Depreciation, depletion and amortization		25,745			11,630
Income tax (benefit) provision		(102	)		164
EBITDA		6,434			(42	)
Add (deduct):
Unrealized risk management losses		46,732			12,252
Restricted unit compensation expense		1,159			172
Other income		(1,547	)		—
Other operating expenses		—			1,711
ADJUSTED EBITDA	$	52,778		$	14,093

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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 puts, calls, 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. The Risk Management Committee 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 Risk Management Committee 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 crude oil, NGLs and natural gas. Both our profitability and our cash flow are affected by volatility in prevailing prices for 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, such as natural gasoline, have generally correlated with changes in the price of crude oil.

We have not designated our contracts as accounting hedges under Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities. 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, 2008, the Partnership recorded a loss on risk management instruments of $45.6 million, representing a fair value (unrealized) loss of $30.8 million, amortization of put premiums of $2.3 million and net (realized) settlement losses of $12.6 million. As of March 31, 2008, the fair value liability of these contracts, including put premiums, totaled approximately, $148.1 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 existing credit agreement. To mitigate its interest rate risk, the Partnership has entered into various interest rate swaps. These swaps convert the variable-rate term loan into a fixed-rate obligation. The purpose of entering into this swap is to eliminate interest rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments through the end of 2010. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense.

We have not designated our contracts as accounting hedges under Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities. 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, 2008, the Partnership recorded a fair value loss within interest expense of $13.7 million and a realized loss of $0.1 million. As of March 31, 2008, the fair value of these contracts totaled approximately $25.9 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. In the sale of our NGLs and condensates, our principle customers are large natural gas liquids purchasers, fractionators and marketers and large condensate aggregators that also in turn typically sell to large multi-national petrochemical and refining companies. We also sell a small amount of propane to medium sized, local distributors.

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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.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Management has conducted an evaluation of the effectiveness 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, as of the end of the period covered by this report. Disclosure controls and procedures are designed to ensure that information required to be disclosed in reports filed or submitted under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and that such information is accumulated and communicated to management, including our principal executive officer and principal financial officer, to ensure timely decisions regarding required disclosures. During the evaluation of disclosure controls and procedures as of December 31, 2007 conducted during the preparation of our financial statements, which were included in our Annul Report on Form 10-K for the year ended December 31, 2007, material weaknesses in internal control over financial reporting were identified relating to our Internal Control Environment, Period End Financial Reporting, and Midstream Cost of Natural Gas and Natural Gas Liquids. As a result, our principal executive officer and principal financial officer concluded that, as of December 31, 2007, our disclosure controls and procedures were ineffective. Upon identification of the material weaknesses and under the directions of our principal executive officer and principal financial officer, we developed a comprehensive plan to remediate the material weaknesses.

As of March 31, 2008, and as described under Status of Remediation of Material Weakness in Internal Control Over Financial Reporting below, the material weaknesses were not fully remediated. As a result, our principal executive officer and principal financial officer concluded that, as of March 31, 2008, our disclosure controls and procedures were ineffective. Notwithstanding the aforementioned material weaknesses and failure of disclosure controls, our management has taken additional steps, described below, to assure there is appropriate disclosure in this report and has concluded that the financial statements included in this report fairly present, in all material respects, our financial condition for the periods presented in conformity with generally accepted accounting principles.

Status of Remediation of Material Weakness in Internal Control Over Financial Reporting

We are actively engaged in the implementation of remediation efforts to address the material weaknesses in our internal control over financial reporting as of December 31, 2007 and any other subsequently identified significant deficiencies or material weaknesses. These remediation efforts outlined below are specifically designed to address the material weaknesses identified by our management relating to our Control Environment, Period End Financial Reporting Process and Midstream Cost of Natural Gas and Natural Gas Liquids. To address the material weaknesses, management has established a remediation plan that will supplement our existing controls. The results from executing our remediation plan during the first quarter of 2008 include the following:

(i) We formalized the monthly account reconciliation and analysis process for significant balance sheet accounts and are in the process of standardizing these controls across business segments (Corporate, Upstream, Minerals, and Midstream);

(ii) We have completed the design of new monitoring controls in the financial reporting process which will focus on identifying and explaining significant month to month account and budget variances. Similar to account reconciliations, these controls will be standardized across business segments;

(iii) We designed and implemented additional controls over validation of monthly hedge settlements and recording of unrealized and realized hedge gains/losses;

(iv) We continued to hire additional external reporting and experienced oil and gas staff that possess public company accounting and/or reporting technical expertise;

(v) We designed and implemented new monitoring controls to validate the accuracy of index prices uploaded into our Midstream system;

(vi) We began conducting an Enterprise-wide risk assessment which will include the establishment of an internal audit plan by June 30, 2008.

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We have devoted significant planning and execution efforts toward remediation of the material weaknesses. Nonetheless, the material weaknesses were not yet fully remediated as of March 31, 2008. Management continues to assign the highest priority to our remediation efforts, with the goal of remediating the material weaknesses by the end of fiscal year 2008. The remainder of our remediation plan, which we will continue to execute in Q2 2008 and beyond, includes:

(i) Evaluating and updating, as appropriate, the design of our internal controls related to the hedging, significant accruals and accounting close processes;

(ii) Testing the operating effectiveness of new and/or remediated controls related to the 2007 material weaknesses once the controls have operated for the appropriate period of time;

(iii) Hiring of experienced and talented oil and gas accounting personnel to improve our supervisory as well as technical accounting positions;

(iv) Delivering COSO and internal controls training company-wide;

(v) Executing the internal audit plan resulting from the Enterprise-wide risk assessment.

While management did implement new or remediate existing controls during Q1 2008 and will continue to do so for the remainder of the fiscal year, due to the nature of the remediation process and the need to allow adequate time after implementation to evaluate and test the effectiveness of the controls, no assurance can be given as to the timing of achievement of remediation. The material weaknesses will be fully remediated when, in the opinion of our management, the revised control processes have been operating for a sufficient period of time and independent validation has been completed to provide reasonable assurance as to their operating effectiveness. The remediation and ultimate resolution of the Partnership’s material weakness will be reviewed with the Audit Committee of the Partnership’s Board of Directors and the company’s external auditor.

Changes in Internal Control Over Financial Reporting

Changes in the Partnership’s internal control over financial reporting during the quarter ended March 31, 2008 that have been materially affected, or are reasonably likely to materially affect, our internal control over financial reporting have been described above.

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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 you 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.

There have not been any material changes from risk factors as previously disclosed in our annual report on Form 10-K for the year ended December 31, 2007.

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. Submission of Matters to a Vote of Security Holders.

None.

Item 5. Other Information.

We have reported on Form 8-K during the quarter covered by this report all information required to be reported on Form 8-K.

Item 6. Exhibits.

31.1	Certification by Joseph A. Mills pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification by Alfredo Garcia pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification by Joseph A. Mills pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350.
32.2	Certification by Alfredo Garcia pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350.

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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 9, 2008	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/ Alfredo Garcia
		Alfredo Garcia
		Senior Vice President, Corporate Development and
		Interim Chief Financial Officer 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.
		(Duly Authorized and Principal Financial Officer)

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EAGLE ROCK ENERGY PARTNERS, L.P.

EXHIBIT INDEX

31.1	Certification by Joseph A. Mills pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification by Alfredo Garcia pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification by Joseph A. Mills pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350.
32.2	Certification by Alfredo Garcia pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350.

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