Eagle Rock Energy Partners L P 10Q/A 2007 Q2 Quarterly report (amended)

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q/A

(Amendment No. 1)


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

For the quarterly period ended June 30, 2007


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

Commission File No. 001-33016

EAGLE ROCK ENERGY PARTNERS, L.P.

(Exact Name of Registrant as Specified in Its Charter)


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

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

Large accelerated filero Accelerated Filero Non-accelerated Filerþ

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

The issuer had 50,663,510 common units outstanding as of October 29, 2007.

EXPLANATORY NOTE

Eagle Rock Energy Partners, L.P. (the “Partnership”) is filing this Amendment No. 1 (“Amendment”) to our Quarterly Report on Form 10-Q for the three-month period ended June 30, 2007 filed with the Securities and Exchange Commission (“SEC”) on August 14, 2007 (“the Original Report”) to restate our unaudited condensed consolidated financial statements for the quarter then ended under Item 1 and to amend Items 2 and 4 of Part I of the Original Report. This Amendment does not affect any other items or sections in the Original Filing, and no attempt has been made in this Form 10-Q/A to update other disclosures presented in the Original Filing, except as required to reflect the effects of the restatement. In addition, Exhibits 31.1, 31.2, 32.1 and 32.2 of the Original Filing have been re-filed to contain currently dated certifications from our Chief Executive Officer and Chief Financial Officer. We are republishing the entire Original Filing, as amended by this Amendment, so that all of our information regarding the quarter ended June 30, 2007 is in one report.

Management of Eagle Rock Energy G&P, LLC (“G&P”), the general partner of Eagle Rock Energy GP, L.P., which is the general partner of the Partnership, is correcting certain accounting errors discovered in the second quarter 2007 financial statement information of subsidiaries of the Partnership, acquired from Laser Midstream Energy, L.P. (“Laser”) during the second quarter of 2007 (see the Partnership’s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 4, 2007). Management has determined that the previous accounting treatment resulted in an overstatement of the Partnership’s gross revenues and cost of goods sold for the second quarter of 2007 by approximately $25.6 million, but because costs were overstated by the same amount as revenue, there was no resulting impact on second quarter 2007 margins, net income/loss, cash flows, members’ equity, Adjusted EBITDA, segment profit, or balance sheet.

The accounting errors impact the Partnership’s South Texas Segment and relate to two items: (i) marketing service agency agreements and (ii) intra-segment transactions. Certain of the Partnership’s subsidiaries accounted for marketing service agency agreements (“agency agreements”) on a “gross” revenue basis – recording gross revenues and gross expenses related to natural gas transactions covered by the agency agreements, as if title and/or credit risk had effectively passed to the Partnership, rather than on a “net” revenue basis – recording only the agency fee as revenue, properly reflecting the fact that neither title nor credit risk actually passed to the Partnership. The subsidiaries also recorded a number of intra-segment transactions related to the South Texas Segment, that were not properly eliminated as part of the consolidation in the second quarter of 2007, resulting in an overstatement of revenues and costs by an equal amount.

As previously disclosed in our Current Report on Form 8-K filed October 25, 2007, after discussions between management and the Audit Committee of the Board of Directors of G&P, on October 24, 2007, management, at the direction of the Audit Committee, concluded that the previously issued unaudited condensed consolidated financial statements included in the Original Filing should no longer be relied upon because of errors in the accounting treatment of the agency agreements and the intra-segment transactions recorded in the Original Filing. The effects of the restatement on the Partnership’s unaudited condensed consolidated financial statements as of and for the period presented herein are described in Note 16 to the unaudited condensed consolidated financial statements included in this Form 10-Q/A and are also reflected in Items 2 and 4 of Part I of this Form 10-Q/A.

As a result of the restatement of the unaudited condensed consolidated financial statements, our management, including Chief Executive Officer and Chief Financial Officer, has re-evaluated our disclosure controls and our internal controls over financial reporting as of the September 30, 2007 and has found our disclosure controls and our internal controls over financial reporting to have been and continue to be effective. See Item 4 of Part I of this Form 10-Q/A for a further discussion.

EAGLE ROCK ENERGY PARTNERS, L.P.

TABLE OF CONTENTS


	Page
PART I. FINANCIAL INFORMATION		1

Item 1. Financial Statements		1
Condensed Consolidated Balance Sheets as of June 30, 2007 and December 31, 2006 (unaudited)		1
Condensed Consolidated Statements of Operations for the three months and six months ended June 30, 2007 (Restated) and 2006 (unaudited)		2
Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2007 and 2006 (unaudited)		3
Condensed Consolidated Statements of Members’ Equity for the six months ended June 30, 2007 (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		23
Cautionary Note Regarding Forward-Looking Statements		23

Item 3. Quantitative and Qualitative Disclosures About Market Risk		40

Item 4. Controls and Procedures		41

PART II. OTHER INFORMATION		42

Item 1. Legal Proceedings		42

Item 1A. Risk Factors		43

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		56

Item 3. Defaults Upon Senior Securities		56

Item 4. Submission of Matters to a Vote of Security Holders		56

Item 5. Other Information		56

Item 6. Exhibits		56
Certification Pursuant to Section 302
Certification Pursuant to Section 302
Certification Pursuant to Section 906
Certification Pursuant to Section 906

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

EAGLE ROCK ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)


	June 30,			December 31,
*($ in thousands)*	2007			2006
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2,296		$	10,581
Cash advances to affiliates		10,665			—
Accounts receivable		106,034			43,567
Risk management assets		—			13,837
Prepayments and other current assets		1,626			2,679

Total current assets		120,621			70,664

PROPERTY, PLANT AND EQUIPMENT — Net		832,857			554,063
INTANGIBLE ASSETS — Net		155,670			130,001
RISK MANAGEMENT ASSETS		20,700			17,373
OTHER ASSETS		12,076			7,800

TOTAL	$	1,141,924		$	779,901


LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	111,518		$	49,558
Accrued liabilities		15,099			7,996
Risk management liabilities		7,802			1,005

Total current liabilities		134,419			58,559

LONG-TERM DEBT		422,131			405,731
ASSET RETIREMENT OBLIGATIONS		1,947			1,819
DEFERRED STATE TAX LIABILITY		1,822			1,229
RISK MANAGEMENT LIABILITIES		38,526			20,576
OTHER		145			—
COMMITMENTS AND CONTINGENCIES (Note 11)
MEMBERS’ EQUITY (DEFICIT):
Common Unitholders(1)		395,981			116,283
Subordinated Unitholders(2)		148,624			176,248
General Partner(3)		(1,671	)		(544	)

Total members’ equity		542,934			291,987

TOTAL	$	1,141,924		$	779,901


(1)		36,284,759 units were issued and outstanding as of June 30, 2007 and 20,691,495 for December 31, 2006. These numbers do not include 450,021 units and 122,450, respectively, issued to employees as of June 30, 2007 and December 31, 2006, respectively, under the 2006 Long-Term Incentive Plan and which are subject to vesting requirements.

(2)		20,691,495 units were issued and outstanding as of June 30, 2007 and December 31, 2006.

(3)		844,551 units were issued and outstanding as of June 30, 2007 and December 31, 2006.

See notes to condensed consolidated financial statements.

EAGLE ROCK ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited)


	Three Months						Six Months
	Ended June 30,						Ended June 30,
	2007			2006			2007			2006
	As Restated						As Restated
*($ in thousands except per share data)*	(see Note 16)						(see Note 16)
REVENUE:
Natural gas liquids sales	$	72,616		$	65,213		$	124,311		$	111,917
Natural gas sales		107,220			45,905			155,492			99,186
Condensate		11,785			14,867			21,939			29,069
Gathering, compression and processing fees		6,883			3,925			11,166			5,946
Loss on risk management instruments		(27,255	)		(15,171	)		(34,897	)		(35,241	)
Royalty income		3,121			—			3,121			—
Lease and rental income		71			—			71			—
Other income		—			147			—			327

Total revenue		174,441			114,886			281,203			211,204

COSTS AND EXPENSES:
Cost of natural gas and natural gas liquids		164,364			96,245			255,000			188,236
Operations and maintenance		11,397			9,116			19,320			14,798
General and administrative		5,898			3,557			10,821			6,010
Other operating		—			—			1,711			—
Depreciation, depletion and amortization		14,149			11,001			25,779			20,215

Total costs and expenses		195,808			119,919			312,631			229,259

OPERATING LOSS		(21,367	)		(5,033	)		(31,428	)		(18,055	)
OTHER (EXPENSE) INCOME:
Interest income		176			—			300			40
Other income		91			—			91			—
Interest expense		(2,172	)		(3,428	)		(10,028	)		(5,963	)
Other expense		(255	)		—			(1,966	)		—

Total other (expense) income		(2,160	)		(3,428	)		(11,603	)		(5,923	)

STATE INCOME TAX PROVISION		256			508			420			508


NET LOSS	$	(23,783	)	$	(8,969	)	$	(43,451	)	$	(24,486	)


NET LOSS PER COMMON UNIT -
BASIC AND DILUTED:
Net loss
Common units	$	(0.28	)	$	(0.31	)	$	(0.55	)	$	(0.91	)
Subordinated units		(0.71	)		(0.31	)		(1.36	)		(0.91	)
General partner units		(0.71	)		(0.31	)		(1.36	)		(0.91	)
Basic and Diluted (units in thousands)
Common units		30,613			4,180			25,680			13,552
Subordinated units		20,691			24,151			20,691			12,809
General partner units		845			589			845			427

See notes to condensed consolidated financial statements.

EAGLE ROCK ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)


	Six Months
	Ended June 30,
*($ in thousands)*	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(43,451	)	$	(24,486	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization		25,779			20,215
Amortization of debt issuance costs		—			432
Reclassifying financing derivative settlements		(100	)		(500	)
Equity-based compensation expense		792			—
Other		2			35
Changes in assets and liabilities — net of acquisitions:
Accounts receivable		(24,943	)		1,021
Prepayments and other current assets		223			546
Risk management activities		34,539			26,724
Accounts payable		28,328			(13,714	)
Accrued liabilities		6,212			4450
Other assets		738			324

Net cash provided by operating activities		28,119			15,047

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment		(37,993	)		(12,931	)
Advances to affiliates		(10,665	)		—
Acquisitions		(118,475	)		(100,524	)
Cash acquired in acquisitions		3,821			—
Escrow cash		—			7,643
Purchase of intangible assets		(1,199	)		(2,185	)
Other		22			—

Net cash used in investing activities		(164,489	)		(107,997	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt		34,400			354
Repayment of long-term debt		(18,000	)		(10,600	)
Payment of debt issuance costs		—			(862	)
Proceeds from derivative contracts		100			500
Payment of deferred offering costs		—			(1,267	)
Contribution by members		—			98,390
Proceeds from equity issuance		127,500			—
Distributions to members and affiliates		(16,185	)		(5,833	)

Net cash (used in) provided by financing activities		127,815			80,682

NET CHANGE IN CASH AND CASH EQUIVALENTS		(8,555	)		(12,269	)
CASH AND CASH EQUIVALENTS — Beginning of period		10,581			19,372

CASH AND CASH EQUIVALENTS — End of period	$	2,296		$	7,103

Interest paid — net of amounts capitalized	$	7,925		$	17,339

Investments in property, plant and equipment not paid	$	4,892		$	1,284

Acquisition of assets for equity	$	182,291		$	—

See notes to condensed consolidated financial statements.

EAGLE ROCK ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY

FOR THE SIX MONTH PERIOD ENDED JUNE 30, 2007
(Unaudited)


				Number of					Number of
	General			Common		Common			Subordinated		Subordinated
	Partner			Units		Units			Units		Units			Total
	($ in thousands, except unit amounts)
BALANCE — December 31, 2006	$	(544	)		20,691,495	$	116,283			20,691,495	$	176,248		$	291,987

Equity issued to private investors		—			7,005,495		127,500			—		—			127,500
Equity issued in acquisitions		—			8,587,769		182,291			—		—			182,291
Net loss		(1,140	)		—		(14,371	)		—		(27,940	)		(43,451	)
Distributions		—			—		(16,185	)		—		—			(16,185	)
Restricted unit expense		13			—		463			—		316			792


BALANCE — June 30, 2007	$	(1,671	)		36,284,759	$	395,981			20,691,495	$	148,624		$	542,934

See notes to condensed consolidated financial statements.

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. ORGANIZATION AND DESCRIPTION OF BUSINESS

Organization— Eagle Rock Energy Partners, L.P., a Delaware limited partnership, formed in May 2006, is an indirect subsidiary of Eagle Rock Holdings, L.P. (“Holdings”). Holdings is a portfolio company of Irving, Texas based private equity capital firm, Natural Gas Partners. Eagle Rock Pipeline, L.P. was formed on November 14, 2005 for the purpose of owning a limited partnership interest in Eagle Rock Midstream Resources, L.P.

Initial Public Offering— Eagle Rock Energy Partners, L.P. was formed for the purpose of completing a public offering of common units. On October 24, 2006, it offered and sold 12,500,000 common units in its initial public offering, or IPO, at a price of $19.00 per unit. Net proceeds from the sale of the units, $222.1 million after underwriting costs, were used for reimbursement of capital expenditures for investors prior to the initial public offering, replenish working capital, and the payment of distribution arrearages. In connection with the initial public offering, Eagle Rock Pipeline, L.P. was merged with and into a newly formed subsidiary of Eagle Rock Energy Partners, L.P.

Basis of Presentation and Principles of Consolidation— The accompanying financial statements include assets, liabilities and the results of operations of Eagle Rock Energy Partners, L.P. and its predecessor entities (Eagle Rock Midstream Resources, L.P. and Eagle Rock Pipeline, L.P.). The reorganization of these entities was accounted for as a reorganization of entities under common control. The general partner interests of Eagle Rock Pipeline, L.P. and Eagle Rock Midstream Resources, L.P. are held by Eagle Rock Pipeline GP, L.L.C. a wholly-owned subsidiary of Eagle Rock Energy Partners, L.P. On March 22, 2006, Eagle Rock Pipeline GP, L.L.C. and Eagle Rock Pipeline, L.P. were converted to Delaware entities. Eagle Rock Pipeline, L.P., Eagle Rock Midstream Resources, L.P., Eagle Rock Pipeline GP, L.L.C. and their subsidiaries and, effective October 24, 2006, Eagle Rock Energy Partners, L.P. are collectively referred to as “Eagle Rock Energy” or the “Partnership.”

Description of Business— We are a growth-oriented Delaware limited partnership engaged in the business of gathering, compressing, treating, processing, transporting and selling natural gas, fractionating and transporting natural gas liquids, or NGLs, which we call our “midstream” business, and in the business of acquiring, developing and producing interests in oil and natural gas properties, which we call our “upstream” business. The Partnership’s natural gas pipelines gather natural gas from designated points near producing wells and transports these volumes to third-party pipelines, the Partnership’s gas processing plants, utilities and industrial consumers. Natural gas transported to the Partnership’s gas processing plants, either on the Partnership’s pipelines or third-party pipelines, is treated to remove contaminants, conditioned or processed into marketable natural gas and natural gas liquids. The Partnership conducts its midstream operations within Louisiana and three geographic areas of Texas. The Partnership’s Texas panhandle assets consist of assets acquired from ONEOK, Inc. on December 1, 2005, and include gathering and processing assets (the “Texas Panhandle System”). The Partnership’s southeast Texas and Louisiana assets include a non-operated 25% undivided interest in a processing plant as well as a non-operated 20% undivided interest in a connected gathering system (the “Texas and Louisiana System”). On April 7, 2006, the Partnership’s Texas and Louisiana System completed the acquisition of a 100% interest in the Brookeland and Masters Creek processing plants in east Texas from Duke Energy Field Services. On June 2, 2006, the Partnership’s Texas Panhandle System completed the acquisition of 100% of Midstream Gas Services, L.P. On May 3, 2007, we completed our acquisition of Laser Midstream Energy, L.P. (“Laser”) and certain of its subsidiaries (“Laser Acquisition”) (see Note 4). The Laser assets include gathering systems and related compression and processing facilities in South Texas, East Texas and North Louisiana, now a part of both our Texas and Louisiana and South Texas Systems.

With respect to our upstream business, we completed the acquisition of certain fee minerals, royalties, overriding royalties and non-operated working interest properties from Montierra Minerals & Production, L.P. (“Montierra”) (a Natural Gas Partners VII, L.P. portfolio company) and NGP-VII Income Co-Investment Opportunities, L.P. (“Co-Invest”) (a Natural Gas Partners affiliate) (collectively, “the Montierra Acquisition”) on April 30, 2007 (see Note 4). As a result of this acquisition, our upstream assets include royalty interests located in multiple producing trends across the United States. The assets include interests in mineral acres and interests in wells with net proved producing reserves of approximately 4.5 billion cubic feet of natural gas and 2.5 million barrels of crude oil. On June 18, 2007, we also completed the acquisition of certain assets owned by MacLondon Energy, L.P. (see Note 4) which include

additional interests in wells in which the Partnership already owns a royalty interest as a result of the Montierra Acquisition.

Currently, based on revenues generated during the second quarter 2007, our midstream business comprises approximately 98% of our business and our upstream business comprises approximately 2%. We intend to acquire and construct additional assets in both our midstream and upstream businesses, and 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, as well as in the operation of oil and natural gas properties and assets.

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. Eagle Rock Energy is the owner of a non-operating undivided interest in the Indian Springs gas processing plant and the Camp Ruby gas gathering system. Eagle Rock Energy owns these interests as tenants-in-common with the majority owner-operator of the facilities. Accordingly, Eagle Rock Energy includes its pro-rata share of assets, liabilities, revenues and expenses related to these assets in its financial statements. All intercompany accounts and transactions are eliminated in the consolidated financial statements. The unaudited consolidated interim financial statements as of and for the three and six months ended June 30, 2007 and 2006 have been prepared on the same basis as the annual financial statements and should be read in conjunction with the annual financial statements included in the Partnership’s 2006 Annual Report on Form 10-K/A filed with the Securities and Exchange Commission. The results of operations for the interim periods presented are not necessarily indicative of the results to be expected for the entire year.

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.

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. 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. Drilling costs are capitalized, but charged to expense if the well is determined to be unsuccessful. We carry the costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well as long as we are making sufficient progress towards assessing the reserves and the economic and operating viability of the project.

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

Geological, geophysical and dry hole costs on oil and natural gas properties relating to unsuccessful wells are charged to expense as incurred.

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.

Other Significant Accounting Policies

Interim Condensed Disclosures— The information for the three and six months ended June 30, 2007 and 2006 is unaudited but in the opinion of management, reflects all adjustments which are normal, recurring and necessary for a fair presentation of financial position and results of operations for the interim periods. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission.

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

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

The Partnership places its cash and cash equivalents with high-quality institutions and in money market funds. The Partnership derives its revenue from customers primarily in the natural gas industry. During 2006, the Partnership increased the parties to which it was selling liquids and natural gas from two to seven. These industry concentrations have the potential to impact the Partnership’s overall exposure to credit risk, either positively or negatively, in that the Partnership’s customers could be affected by similar changes in economic, industry or other conditions. However, the Partnership believes the credit risk posed by this industry concentration is offset by the creditworthiness of the Partnership’s customer base. The Partnership’s portfolio of accounts receivable is comprised primarily of mid-size to large domestic corporate entities.

Certain Other Concentrations— The Partnership relies on natural gas producer customers for its midstream natural gas and natural gas liquid supply, with the top two producers in each system accounting for 27% of its natural gas supply in its Texas Panhandle System, 33% of its natural gas supply in the East Texas/Louisiana System and 38% of its natural gas supply in the South Texas System for the month ended June 30, 2007. While there are numerous natural gas and natural gas liquid producers and some of these producer customers are subject to long-term contracts, the Partnership may be unable to negotiate extensions or replacements of these contracts, on favorable terms, if at all. If the Partnership were to lose all or even a portion of the natural gas volumes supplied by these producers and was unable to acquire comparable volumes, the Partnership’s results of operations and financial position could be materially adversely affected.

Property, Plant, and Equipment— Property, plant, and equipment consists primarily of gas gathering systems, gas processing plants, NGL pipelines, conditioning and treating facilities and other related facilities, and oil and gas properties, which are carried at cost less accumulated depreciation and depletion. The Partnership charges repairs and maintenance against income when incurred and capitalizes renewals and betterments, which extend the useful life or expand the capacity of the assets. The Partnership calculates depreciation on the straight-line method principally over 20-year estimated useful lives of the Partnership’s newly developed or acquired assets. The weighted average useful lives are as follows:


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

The Partnership capitalizes interest on major projects during extended construction time periods. Such interest is allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. During the three and six month periods ended June 30, 2007, the Partnership capitalized interest of approximately $0.3 million and $0.8 million, respectively. The Partnership did not record capitalized interest in the prior year’s second quarter.

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

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

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

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

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

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

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

If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets.

In accordance with SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets,we assess proved oil and natural gas properties for possible impairment when events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. We recognize an impairment loss as a result of a triggering event and when the estimated undiscounted future cash flows from a property are less than the carrying value. If an impairment is indicated, the cash flows are discounted at a rate approximate to our cost of capital and compared to the carrying value for determining the amount of the impairment loss to record. Estimated future cash flows are based on management’s expectations for the future and include estimates of oil and natural gas reserves and future commodity prices and operating costs. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate property impairment.

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 $8.3 million for the six months ended June 30, 2007, and approximately $7.5 million for the six months ended June 30, 2006. Estimated aggregate amortization expense for each of the five succeeding years is as follows: 2008 — $23.0 million; 2009 — $23.0 million; 2010 — $23.0 million; 2011 — $13.6 million; and 2012 — $4.9 million. Intangible assets consisted of the following:


	June 30,			December 31,
*($ in thousands)*	2007			2006
Rights-of-way and easements — at cost	$	68,550		$	66,801
Less: accumulated amortization		(5,208	)		(3,510	)
Contracts		112,421			80,210
Less: accumulated amortization		(20,093	)		(13,500	)

Net intangible assets	$	155,670		$	130,001

The amortization period for our rights-of-way and easements is 20 years and contracts range from 5 to 15 years, respectively, and overall, approximately 13 years average in total as of June 30, 2007.

Other Assets — Other assets primarily consist of costs associated with debt issuance ($6.9 million) and acquisitions ($1.7 million), net of amortization for the six months ended June 30, 2007 and equity investments in non-affiliates related to the Montierra Acquisition ($3.4 million). Amortization of debt issuance costs is calculated using the straight-line method over the maturity of the associated debt (or the expiration of the contract).

Transportation and Exchange Imbalances — In the course of transporting natural gas and natural gas liquids for others, the Partnership may receive for redelivery different quantities of natural gas or natural gas liquids than the quantities actually delivered. These transactions result in transportation and exchange imbalance receivables or payables which are recovered or repaid through the receipt or delivery of natural gas or natural gas liquids in future periods, if not subject to cash out provisions. Imbalance receivables are included in accounts receivable and imbalance payables are included in accounts payable on the consolidated balance sheets and marked-to-market using current market prices in effect for the reporting period of the outstanding imbalances. For the midstream business, as of December 31, 2006, the Partnership had imbalance receivables totaling $0.3 million and imbalance payables totaling $1.9 million, respectively. For the midstream business, as of June 30, 2007, the Partnership had imbalance receivables totaling $0.7 million and imbalance payables totaling $2.3 million, respectively. Changes in market value and the settlement of any such imbalance at a price greater than or less than the recorded imbalance results in either an upward or downward adjustment, as appropriate, to the cost of natural gas sold.

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

	•		sales of natural gas, NGLs and condensate;

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

	•		NGL transportation from which we generate revenues from transportation fees;

	•		royalties, overriding royalties and lease bonuses.

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

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

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

The Partnership uses the sales method of accounting for natural gas revenues for the upstream segment. Under this method, revenues are recognized based on actual volumes of natural gas sold to purchasers. The volumes of natural gas sold may differ from the volumes to which the Partnership is entitled based on its interests in the properties. Differences between volumes sold and volumes based on entitlements create natural gas imbalances. Material imbalances are reflected as adjustments to reported gas reserves and future cash flows. There were no material natural gas imbalances as of June 30, 2007.

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

Partnership has recorded environmental liabilities of approximately $0.3 million as of December 31, 2006 and June 30, 2007.

Income Taxes — No provision for federal income taxes related to the operation of Eagle Rock Energy is included in the accompanying consolidated financial statements as such income is taxable directly to the partners holding interests in the Partnership. The state of Texas enacted a margin tax in May 2006 which requires the Partnership to report beginning in 2008, based on 2007 results. The method of calculation for this margin tax is similar to an income tax, requiring the Partnership to recognize currently the impact of this new tax using a margin approach based upon revenues less a qualified portion of cost of goods sold, operating costs and depreciation for 2007 activities. In addition, the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities are also considered. Approximately $1.2 million estimated deferred state tax liability has been recorded at June 30, 2007. (see Note 13)

Derivatives — Statement of Financial Accounting Standards (“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. SFAS No. 133 provides that normal purchase and normal sale contracts, when appropriately designated, are not subject to the statement. Normal purchases and normal sales are contracts which provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business. The Partnership’s forward natural gas purchase and sales contracts are designated as normal purchases and sales. Substantially all forward contracts fall within a one-month to four-year term; however, the Partnership does have certain contracts which extend through the life of the dedicated production. The Partnership uses financial instruments such as puts, swaps and other derivatives to mitigate the risks to cash flows resulting from changes in commodity prices and interest rates. The Partnership recognizes these financial instruments on its consolidated balance sheet at the instrument’s fair value with changes in fair value reflected in the 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.

NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS

In February 2006, the Financial Accounting Standards Board (the “FASB”) issued SFAS No. 155,Accounting for Certain Hybrid Financial Instruments, an amendment of FASB Statements No. 133 and No. 140 (SFAS No. 155). SFAS No. 155 amends SFAS No. 133, which required a derivative embedded in a host contract which does not meet the definition of a derivative be accounted for separately under certain conditions. SFAS No. 155 amends SFAS No. 133 to narrow the scope of such exception to strips which represent rights to receive only a portion of the contractual interest cash flows or of the contractual principal cash flows of a specific debt instrument. In addition, SFAS No. 155 amends SFAS No. 140,Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,which permitted a qualifying special-purpose entity to hold only a passive derivative financial instrument pertaining to beneficial interests issued or sold to parties other than the transferor. SFAS No. 155 amends SFAS No. 140 to allow a qualifying special purpose entity to hold a derivative instrument pertaining to beneficial interests that itself is a derivative financial instrument. SFAS No. 155 is effective for all financial instruments acquired or issued (or subject to a re-measurement event) following the start of an entity’s first fiscal year beginning after September 15, 2006. The Partnership adopted SFAS No. 155 on January 1, 2007, and it had no effect on the results of operations or financial position.

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. The Partnership is currently evaluating the effect the adoption of this statement will have, if any, on its consolidated results of operations and financial position.

items at fair value. SFAS No. 159 is effective for us as of January 1, 2008 and will have no impact on amounts presented for periods prior to the effective date. We cannot currently estimate the impact of SFAS No. 159 on our consolidated results of operations, cash flows or financial position and have not yet determined whether or not we will choose to measure items subject to SFAS No. 159 at fair value.

A significant portion of the Partnership’s sale and purchase arrangements are accounted for on a gross basis in the statements of operations as natural gas sales and costs of natural gas, respectively. These transactions are contractual arrangements which establish the terms of the purchase of natural gas at a specified location and the sale of natural gas at a different location at the same or at another specified date. These arrangements are detailed either jointly, in a single contract or separately, in individual contracts which are entered into concurrently or in contemplation of one another with a single or multiple counterparties. Both transactions require physical delivery of the natural gas and the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk and counterparty nonperformance risk. In accordance with the provision of Emerging Issues Task Force Issue No. 04-13,Accounting for Purchases and Sales of Inventory with the Same Counterparty(“EITF 04-13”), the Partnership reflects the amounts of revenues and purchases for these transactions as a net amount in its consolidated statements of operations beginning with April 2006. For the quarter ended June 30, 2007, the Partnership did not enter into any purchase and sale agreements with the same counterparty. As a result, EITF 04-13 had no effect on the results of operations for the quarter ended June 30, 2007.

In July 2006, the FASB issued FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109(FIN 48), which clarifies the accounting and disclosure for uncertainty in tax positions, as defined. FIN 48 seeks to reduce the diversity in practice associated with certain aspects of the recognition and measurement related to accounting for income taxes. This interpretation is effective for fiscal years beginning after December 15, 2006. The adoption of FIN 48 did not have a material impact on our results of operations or financial position.

NOTE 4. ACQUISITIONS

On April 30, 2007, the Partnership acquired certain fee mineral acres, royalty and overriding royalty interests from Montierra and Co-Invest, for an aggregate purchase price of $140.4 million, subject to price adjustments. Eagle Rock Energy paid consideration that totaled 6,390,400 of our common units and $6.0 million of cash. As part of this transaction, a 39.34% economic interest in the incentive distribution rights was conveyed from Eagle Rock Holdings, L.P. to Montierra.

The Partnership has recorded the acquisitions of Montierra and Co-Invest under the guidance of Staff Accounting Bulletin Topic 2D,Financial Statements of Oil and Gas Exchange Offers(“Topic 2D”). In accordance with Topic 2D, the Partnership has recorded the interest attributable to the ownership of Natural Gas Partners in Montierra and Co-Invest at their carryover basis (approximately $0.4 million). Those interests not attributable to Natural Gas Partners have been recorded at their fair value.

The assets conveyed in the Montierra Acquisition include fee mineral acres, royalty and overriding royalty interests in oil and natural gas producing wells with net proved producing reserves of approximately 4.6 billion cubic feet of gas and 2.5 million barrels of oil.

The purchase price was allocated on a preliminary basis to oil and gas properties and working capital, net and equity investments in non-affiliates, based on their respective fair value as determined by management. The preliminary purchase price has been allocated as presented below.


*($ in thousands)*
Oil and gas properties	$	132,414
Cash		936
Accounts receivable		6,342
Accounts payable		(1,906	)
Risk management liabilities		(717	)
Accrued liabilities		(104	)
Equity investments in non-affiliates		3,459

	$	140,424

On May 3, 2007, Eagle Rock Energy Partners, L.P. acquired Laser Midstream Energy II, LP, a Delaware limited partnership, Laser Gas Company I, LLC, a Delaware limited liability company, Laser Midstream Company, LLC, a Texas limited liability company, and Laser Midstream Energy, LP, a Delaware limited partnership for a total purchase

price of approximately $143.4 million, consisting of $113.6 million in cash and 1,407,895 of our common units. The assets subject to the transaction include gathering systems and related compression and processing facilities in south Texas, east Texas and north Louisiana.

The purchase price was allocated on a preliminary basis to property, plant and equipment and intangibles in the amounts of $107.2 million and $32.2 million, respectively, based on their respective fair value as determined by management with the assistance of a third-party valuation specialist. In addition to long-term assets, the Partnership assumed certain accrued liabilities. The preliminary purchase price has been allocated as presented below.


*($ in thousands)*
Property, plant and equipment	$	107,183
Intangibles		32,210
Cash		2,885
Accounts receivable		31,182
Other current assets		279
Accounts payable		(30,082	)
Other current liabilities		(287	)

	$	143,370

On June 18, 2007, the Partnership acquired from MacLondon Energy, L.P. (“MacLondon”) certain mineral royalty and overriding royalty interests in which the Partnership already owned an interest as a result of the Montierra and Co-Invest acquisitions. MacLondon Energy, L.P.’s assets were acquired for a total consideration of approximately $18.9 million.

The following pro forma information for the six months ended June 30, 2007, assumes the Laser, Montierra, Co-Invest and MacLondon acquisitions had been acquired by Eagle Rock Energy on January 1, 2007:


*($ in thousands)*	June 30, 2007
Pro forma earnings data:
Revenues(a)	$	408,298
Cost and expenses		(446,292	)

Loss from operations	$	(37,994	)


(a)		Excludes non-realized revenues risk management loss of $39.4 million.

NOTE 5. FIXED ASSETS AND ASSET RETIREMENT OBLIGATIONS

Fixed assets consisted of the following:


	June 30,			December 31,
*($ in thousands)*	2007			2006
Land	$	1,064		$	853
Plant		112,463			81,485
Gathering and pipeline		540,401			433,779
Equipment and machinery		46,391			37,185
Vehicles and transportation equipment		3,420			2,740
Office equipment, furniture, and fixtures		1,079			511
Computer equipment		4,628			4,623
Corporate		126			126
Linefill		4,157			3,923
Proved properties		91,278			—
Unproved properties		60,069			—
Construction in progress		17,768			19,677

		882,846			584,902
Less: accumulated depletion, depreciation and amortization		(49,989	)		(30,839	)

Net fixed assets	$	832,857		$	554,063

Depreciation expense for the three and six months ended June 30, 2007 and for the three and six months ended June 20, 2006 were approximately $7.5 million, $5.6 million, $17.5 million and $12.8 million, respectively. Depletion expense for the three months and six months ended June 30, 2007 and for the three and six months ended June 30, 2006 were approximately $1.5 million, $1.5 million, $0.0 million and $0.0 million, respectively (the Partnership did not own oil and natural gas properties in 2006 and, therefore, did not incur depletion expense during 2006).

Asset Retirement Obligations – The Partnership recognizes asset retirement obligations 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, 2006	$	1,819
Additional liability on newly built assets		49
Accretion expense		79

Asset retirement obligations — June 30, 2007	$	1,947

NOTE 6. LONG-TERM DEBT

Long-term debt consisted of:


	June 30,		December 31,
*($ in thousands)*	2007		2006
Revolver	$	122,881	$	106,481
Term loan		299,250		299,250

Total debt		422,131		405,731
Less: current portion		—		—

Total long-term debt	$	422,131	$	405,731

On August 31, 2006, the Partnership amended and restated its existing credit agreement (the “Amended and Restated Credit Agreement”). The Amended and Restated Credit Agreement was a $500.0 million credit agreement with a syndicate of commercial and investment banks and institutional lenders, with Goldman Sachs Credit Partners L.P., as the administrative agent. The Amended and Restated Credit Agreement provided for $300.0 million aggregate principal amount of Series B Term Loans (the “Term Loan”) and up to $200.0 million aggregate principal amount of Revolving Commitments (the “Revolver”). On May 4, 2007, Eagle Rock Energy expanded its revolver commitment level under its Amended and Restated Credit Agreement by $100.0 million to $300.0 million. No incremental funding under the Amended and Restated Credit Agreement was needed for the Laser and Montierra acquisitions. As of June 30, 2007, we have total borrowing availability of $600.0 million and we have $422.1 million drawn down under the facility.

The Amended and Restated Credit Agreement includes a sub limit for the issuance of standby letters of credit for the aggregate unused amount of the Revolver. At June 30, 2007, the Partnership had $6.9 million of outstanding letters of credit.

During the quarter ended June 30, 2007 and 2006, the Partnership recorded approximately $0.4 million and $0.2 million of debt issuance amortization expense, respectively. As of June 30, 2007, the unamortized amount of debt issuance costs was $7.4 million.

With the consummation of the Partnership’s initial public offering on October 27, 2006, quarterly installments under the Term Loan ceased with the balance due on the Term Loan maturity date, August 31, 2011. The Revolver matures on the revolving commitment termination date, August 31, 2011.

In certain instances defined in the Amended and Restated Credit Agreement, the Term Loan is subject to

mandatory repayments and the Revolver is subject to a commitment reduction for cumulative asset sales exceeding $15.0 million; insurance/condemnation proceeds; the issuance of equity securities; and the issuance of debt.

The Amended and Restated Credit Agreement contains various covenants which limit the Partnership’s ability to grant certain liens; make certain loans and investments; make certain capital expenditures outside the Partnership’s current lines of business or certain related lines of business; make distributions other than from available cash; merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of the Partnership’s assets. Additionally, the Amended and Restated Credit Agreement limits the Partnership’s ability to incur additional indebtedness with certain exceptions and purchase money indebtedness and indebtedness related to capital or synthetic leases not to exceed $7.5 million.

The Amended and Restated Credit Agreement also contains covenants, which, among other things, require the Partnership, on a consolidated basis, to maintain specified ratios or conditions as follows:

	•		Adjusted EBITDA (as defined) to interest expense of not less than 2.5 to 1.0; and

	•		Total consolidated funded debt to Adjusted EBITDA (as defined) of not more than 5.0 to 1.0 and 5.25 to 1.0 for the three quarters following a material acquisition.

Based upon the senior debt to Adjusted EBITDA ratio calculated as of June 30, 2007 (utilizing the September 2006, December 2006, March 2007 and June 2007 quarters Consolidated Adjusted EBITDA as defined under the Credit Agreement annualized for an annual Adjusted EBITDA amount for the ratio), the Partnership has approximately $165.1 million of unused capacity under the Amended and Restated Credit Agreement Revolver at June 30, 2007 on which the Partnership pays a 0.75% commitment fee per year.

At the Partnership’s election, the Term Loan and the Revolver bear interest on the unpaid principal amount either at a base rate plus the applicable margin (defined as 1.25% per annum, reducing to 1.00% when consolidated funded debt to Adjusted EBITDA (as defined) is less than 3.5 to 1); or at the Adjusted Eurodollar Rate plus the applicable margin (currently 2.75% per annum, reducing to 2.25% when consolidated funded debt to Adjusted EBITDA (as defined) is less than 3.5 to 1). At June 30, 2007, the weighted average interest rate on our outstanding debt balance was 8.13%. The applicable margin increased by 0.50% per annum on January 31, 2007, under the Amended and Restated Credit Agreement as the Partnership elected not to obtain a rating by S&P and Moody’s.

Base rate interest loans are paid the last day of each March, June, September and December. Eurodollar Rate Loans are paid the last day of each interest period, representing one-, two-, three- or six-, nine- or twelve-months, as selected by the Partnership. Interest on the Term Loan is paid approximately each March 31, June 30, September 30 and December 31 of each year. The Partnership pays a commitment fee equal to (1) the average of the daily difference between (a) the revolver commitments and (b) the sum of the aggregate principal amount of all outstanding revolver loans plus the aggregate principal amount of all outstanding swing loans times (2) 0.50% per annum; provided, the commitment fee percentage increased by 0.25% per annum on January 31, 2007, as the Partnership elected not to obtain a rating by S&P and Moody’s. The Partnership also pays a letter of credit fee equal to (1) the applicable margin for revolving loans which are Eurodollar Rate loans times (2) the average aggregate daily maximum amount available to be drawn under all such Letters of Credit (regardless of whether any conditions for drawing could then be met and determined as of the close of business on any date of determination). Additionally, the Partnership pays a fronting fee equal to 0.125%, per annum, times the average aggregate daily maximum amount available to be drawn under all letters of credit.

The obligations under the Amended and Restated Credit Agreement are secured by first priority liens on substantially all of the Partnership’s assets, including a pledge of all of the capital stock of each of its subsidiaries.

Prior to entering into the Amended and Restated Credit Agreement, the Partnership operated under a $475.0 million credit agreement (the “Credit Agreement”) with a syndicate of commercial banks, including Goldman Sachs Credit Partners L.P., as the administrative agent. The Credit Agreement was entered into on December 1, 2005. The Credit Agreement provided for $400.0 million aggregate principal amount of Series A Term Loans (the “Original Term Loan”) and up to $75.0 million ($100.0 million effective June 2, 2006) aggregate principal amount of Revolving Commitments (the “Original Revolver”). The Credit Agreement included a sub limit for the issuance of standby letters of credit for the lesser of $55.0 million or the aggregate unused amount of the Original Revolver.

Scheduled maturities of long-term debt as of June 30, 2007, were as follows:


	Principal
*($ in thousands)*	Amount
2007	$	—
2008		—
2009		—
2010		—
2011		422,131

	$	422,131

The Partnership was in compliance with the financial covenants under the Amended and Restated Credit Agreement as of June 30, 2007. If an event of default existed under the Amended and Restated Credit Agreement, the lenders would be able to accelerate the maturity of the Amended and Restated Credit Agreement and exercise other rights and remedies.

NOTE 7. MEMBERS’ EQUITY

On April 30, 2007 and as partial consideration for the Montierra Acquisition, the Partnership issued and transferred to the sellers 6,390,400 common units.

On May 3, 2007 and as partial consideration for the Laser Acquisition, the Partnership issued and transferred to the sellers 1,407,895 common units.

On May 3, 2007, the Partnership completed the private placement of 7,005,495 common units among a group of institutional investors for gross proceeds of $127.5 million. The proceeds from the private offering were used to fully fund the cash portion of the purchase price of the Laser Acquisition. The offering closed simultaneously with the Laser Acquisition.

On June 18, 2007 and as consideration for the MacLondon acquisition, the Partnership issued and transferred to the sellers 789,474 common units.

At June 30, 2007, there were 36,284,759 common units, 20,691,495 subordinated units (all subordinated units owned by Holdings) and 844,551 general partner units outstanding. In addition, there were 450,021 restricted unvested 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 September 30, 2009 for which there does not exist any cumulative common unit arrearage and other conditions pursuant to the partnership agreement have been met.

On January 26, 2007, the Partnership declared its 2006 fourth quarter cash distribution to its common unitholders of record as of February 7, 2007. The distribution amount per common unit was $0.3625 which was adjusted to $0.2679 per unit for the partial quarter the units were outstanding due to the initial public offering date. The distribution was made on February 15, 2007. A distribution was also made to the pre-IPO common unitholders for the period before the effective date of the initial public offering. No distributions were declared on the general partner or subordinated units.

On May 4, 2007, the Partnership declared a cash distribution of $0.3625 per unit for the first quarter ending March 31, 2007. The distribution was paid May 15, 2007, to common unitholders of record as of May 7, 2007, not including unitholders who acquired units in either the Montierra Acquisition or Laser Acquisition. No distributions were declared on the general partner or subordinated units.

On August 6, 2007, the Partnership declared a cash distribution of $0.3625 per unit for the second quarter ending June 30, 2007. The distribution will be paid August 14, 2007 to common unitholders of record as of August 8, 2007, not including unitholders who acquired units in the MacLondon (see Note 4), EAC or Redman acquisitions (see Note 15). No distributions were declared on the general partner or subordinated units.

NOTE 8. RELATED PARTY TRANSACTIONS

Holdings previously had a management advisory arrangement with Natural Gas Partners requiring a quarterly fee payment. At the time of the initial public offering, Holdings terminated the agreement with a $6.0 million payment to Natural Gas Partners. The termination fee was recorded as an expense of the Partnership during the fourth quarter of 2006, with the offset as a capital contribution. Holdings owns and controls the general partner of the partnership while Holdings is controlled by Natural Gas Partners with minority ownership by certain management personnel of the Partnership’s general partner.

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’s Texas Panhandle Systems has the option to sell a portion of its gas supply. The Partnership has received a Letter of Credit related to this agreement. The Partnership recorded revenues of $8.2 million and $13.9 million for the three and six month periods ended June 30, 2007 from the agreement, of which there was a receivable of $2.0 million outstanding at June 30, 2007.

The Partnership entered into an Omnibus Agreement with Eagle Rock Energy G&P, LLC, Holdings and the Partnership’s general partner which requires the Partnership to reimburse Eagle Rock Energy G&P, LLC for the payment of certain expenses incurred on the Partnership’s behalf, including payroll, benefits, insurance and other operating expenses, and provides certain indemnification obligations.

The Partnership does not directly employ any persons to manage or operate our business. Those functions are provided by our general partner. We reimburse the general partner for all direct and indirect costs of these services.

On April 30, 2007, the Partnership completed the acquisition of certain fee minerals, royalties, overriding royalties and non-operated working interest properties from Montierra and Co-Invest, a Natural Gas Partners portfolio company and affiliate, respectively, for an aggregate purchase price of approximately $140.4 million. Montierra and Natural Gas Partners received as consideration a total of 6,390,400 Eagle Rock Energy common units and $6.0 million in cash. As part of this transaction, a 39.34% economic interest in the incentive distribution rights was conveyed from Eagle Rock Holdings, L.P. to Montierra. One or more Natural Gas Partners private equity funds (“NGP”) directly or indirectly owns a majority of the equity interests in Eagle Rock Energy, Montierra and Co-Invest. Because of the potential conflict of interest between the interests of Eagle Rock Energy G&P, LLC (the “Company”) and the public unitholders of Eagle Rock Energy, the Board of Directors authorized the Company’s Conflicts Committee to review, evaluate, and, if determined appropriate, approve the Montierra Acquisition. The Conflicts Committee, consisting of independent Directors of the Company, determined that the Montierra Acquisition was fair and reasonable to Eagle Rock Energy and its public unitholders and recommended to the Board of Directors of the Company that the transaction be approved and authorized. In determining the purchase consideration for the Montierra Acquisition, the Board of Directors considered the valuation of the properties involved in the transaction, the valuation of the units to be offered as consideration in the transaction, and the cash flow of Montierra and Co-Invest, including cash receipts and royalty interests.

In connection with the closing of our initial public offering, on October 24, 2006, we entered into a registration rights agreement with Eagle Rock Holdings, L.P. in connection with its contribution to us of all of its limited and general partner interests in Eagle Rock Pipeline. In the registration rights agreement, we agreed, for the benefit of Eagle Rock Holdings, L.P., to register the common units it holds, the common units issuable upon conversion of the subordinated units that it holds and any common units or other equity securities issuable in exchange for the common units and subordinated units it holds.

In connection with the closing of the Montierra Acquisition, we entered into a registration rights agreements with Montierra and NGP-VII Income Co-Investment Opportunities, L.P. (“Co-Invest”). In the registration rights agreements, we agreed, for the benefit of Montierra and Co-Invest, to register the common units it holds, the common units issuable upon conversion of the subordinated units that it holds and any common units or other equity securities issuable in exchange for the common units and subordinated units it holds.

NOTE 9. FAIR VALUE OF FINANCIAL INSTRUMENTS

The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments.

The carrying amount of cash equivalents is believed to approximate their fair values because of the short maturities of these instruments. As of June 30, 2007, the debt associated with the Amended and Restated Credit Agreement bore interest at floating rates. As such, carrying amounts of these debt instruments approximates fair value.

NOTE 10. RISK MANAGEMENT ACTIVITIES

The Credit Agreement required the Partnership to enter into interest rate risk management activities. In December 2005, 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 for a period of five years from January 1, 2006 to January 1, 2011. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense. The table below summarizes the terms, amounts received or paid and the fair values of the various interest rate swaps:


								($ in thousands)
								Fair Value
Roll Forward	Expiration		Notional		Fixed			June 30,
Effective Date	Date		Amount		Rate			2007
01/03/2006		01/03/2011	$	100,000,000		4.9500	%	$	1,961
01/03/2006		01/03/2011		100,000,000		4.9625			1,906
01/03/2006		01/03/2011		50,000,000		4.8800			1,091
01/03/2006		01/03/2011		50,000,000		4.8800			1,091

For the three month periods ended June 30, 2007 and 2006, the Partnership recorded a fair value gain within interest expense of $6.8 million and $9.0 million, respectively. For the six month periods ended June 30, 2007 and 2006, the Partnership recorded $5.5 million and $4.5 million, respectively. As of June 30, 2007 and 2006, the fair value of these contracts totaled approximately $6.0 million and approximately $7.5 million, respectively.

The prices of natural gas 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 natural gas 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. We are implementing 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 intend to monitor and ensure compliance with this Risk Management Policy through senior level executives in our operations, finance and legal departments.

During 2005 and 2006, the Partnership entered into the following risk management activities (excluding transactions that settled in previous periods):

	•		NGL puts, costless collar and swap transactions for the sale of Mont Belvieu natural gas liquids with a combined notional amount of 195,000 Bbls per month, 17,000 Bbls per month, 57,000 Bbls per month and 54,000 Bbls per month for 2007, 2008, 2009, and 2010, respectively;

	•		Condensate puts and costless collar transactions for the sale of West Texas Intermediate crude oil with a combined notional amount of 104,000 Bbls per month, 80,000 Bbls per month, 40,000 Bbls per month and 40,000 Bbls per month for 2007, 2008, 2009, and 2010, respectively;

	•		Natural gas calls for the purchase of Henry Hub natural gas with a notional amount of 100,000 MMBtu per month for 2007;

•

Fixed swap agreements to hedge WTS-WTI basis differential in amount of 20,000 Bbls per month for a term of January through December 2007; and

The NGL derivatives are intended to hedge the risk of lower prices for NGLs with offsetting increases in the value of the NGL derivatives. The condensate derivatives are intended to hedge the risk of lower NGL and condensate prices with offsetting increases in the value of the puts based on the correlation between NGL prices and crude oil prices. The natural gas derivatives are intended to hedge the risk of increasing natural gas prices with the offsetting value of the natural gas derivatives.

As a result of the Montierra acquisition, the Partnership novated Montierra’s existing hedging instruments consisting of:

	•		Costless collar transactions for West Texas Intermediate crude oil with a combined notional amount of 8,000 Bbls per month for 2007 and 6,000 Bbls per month for 2008; and

	•		Costless collar transactions for Henry Hub natural gas with a combined notional amount of 45,000 MMBtu per month, 30,000 MMBtu per month, and 20,000 MMBtu per month for 2007, 2008 and 2009, respectively.

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. For the three and six month periods ended June 30, 2007, the Partnership recorded a loss on risk management instruments of $27.2 million and $34.9 million, respectively, representing a fair value (unrealized) loss of $26.7 million, amortization of put premiums of $2.0 million and net (realized) settlements gain from the Partnership of $1.5 million. As of June 30, 2007, the fair value liability of these contracts, including the put premiums, totaled approximately $40.3 million. As of June 30, 2006, the fair value loss of these contracts, including premiums, totaled $2.0 million.

NOTE 11. COMMITMENTS AND CONTINGENT LIABILITIES

Litigation — The Partnership is subject to several lawsuits, primarily related to the payments of liquids and gas proceeds in accordance with contractual terms. The Partnership has accruals of approximately $2.8 million and $1.5 million as of June 30, 2007 and December 31, 2006, respectively, related to these matters. In April 2007, the Partnership received notice of an arbitration award against the Partnership in the approximate amount of $1.4 million. The award relates to a fee dispute regarding our Panhandle Segment and such dispute occurred prior to our acquisition of those assets. The Partnership recorded the liability for such arbitration award in the first quarter 2007 in Other operating expense in the statement of operations. In addition, the Partnership is also subject to other lawsuits related to the payment of liquid and natural gas proceeds in accordance with contractual terms for which the Partnership has been indemnified up to a certain dollar amount. 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.

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 public liability insurance for liabilities arising to third parties for bodily injury and property damage 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 all real and personal property damage, including damages arising from boiler and machinery breakdowns, earthquake, flood damage and business interruption/extra expense, and (5) 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. The cost of general insurance coverages continued to fluctuate over the past year reflecting the changing conditions of the insurance markets.

Regulatory Compliance— In the ordinary course of business, the Partnership is subject to various laws and regulations. In the opinion of management, compliance with existing laws and regulations will not materially affect the financial position of the Partnership.

Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, the Partnership must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership’s combined results of operations, financial position or cash flows. At June 30, 2007 and December 31, 2006, the Partnership had accrued approximately $0.3 million for environmental matters.

Other Commitments and Contingencies — 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 $0.3 million and $0.5 million for the three and six months ended June 30, 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 and one functional (corporate) segment:

Midstream Segment:

	(i)		gathering, processing, transportation and marketing of natural gas in the Texas Panhandle System;

	(ii)		gathering, processing, transportation and marketing of natural gas in the south Texas System;

	(iii)		gathering, processing and marketing of natural gas and related NGL transportation in the southeast Texas and Louisiana System;

Upstream Segment:

(iv)

crude oil and natural gas production (fee minerals, royalties and non-operated working interest ownership, lease bonus and rental income and equity income in non-affiliates); and

Corporate Segment:

(v)

risk management and other corporate activities.

Summarized financial information concerning the Partnership’s reportable segments is shown in the following table:


					Southeast
*($ in millions)*			South		Texas and
Three months ended June 30, 2007	Panhandle		Texas		Louisiana		Upstream		Corporate			Total
Sales to external customers	$	110.0	$	50.8	$	37.6	$	3.2	$	(27.2	)^(a)	$	174.4
Interest expense-net and other financing costs		—		—		—		—		2.2			2.2
Depreciation, depletion and amortization		10.0		0.4		2.0		1.5		0.2			14.1
Segment profit (loss)(b)		24.0		1.6		8.4		3.2		(27.1	)		10.1
Capital expenditures		10.4		0.8		2.5		—		0.1			13.8
Segment assets		581.8		75.5		277.7		162.2		44.7			1,141.9


					Southeast
*($ in millions)*			South		Texas and
Three months ended June 30, 2006	Panhandle		Texas		Louisiana		Upstream		Corporate			Total
Sales to external customers	$	105.7	$	—	$	24.3	$	—	$	(15.2	)^(a)	$	114.8
Interest expense-net and other financing costs		—		—		—		—		3.4			3.4
Depreciation, depletion and amortization		8.6		—		2.4		—		—			11.0
Segment profit (loss)(b)		27.6		—		6.2		—		(15.2	)		18.6
Capital expenditures		3.3		—		1.8		—		1.6			6.7
Segment assets		566.3		—		121.0		—		81.8			769.1

					Southeast
*($ in millions)*			South		Texas and
Six months ended June 30, 2007	Panhandle		Texas		Louisiana		Upstream		Corporate			Total
Sales to external customers	$	204.9	$	50.8	$	57.0	$	3.2	$	(34.7	)^(a)	$	281.2
Interest expense-net and other financing costs		—		—		—		—		10.0			10.0
Depreciation, depletion and amortization		19.8		0.4		3.7		1.5		0.4			25.8
Segment profit (loss)(b)		43.2		1.6		12.9		3.2		(34.7	)		26.2
Capital expenditures		22.5		1.8		14.9		—		0.3			39.5
Segment assets		581.8		75.5		277.7		162.2		44.7			1,141.9

					Southeast
*($ in millions)*			South		Texas and
Six months ended June 30, 2006	Panhandle		Texas		Louisiana		Upstream		Corporate			Total
Sales to external customers	$	212.2	$	—	$	34.2	$	—	$	(35.2	)^(a)	$	211.2
Interest expense-net and other financing costs		—		—		—		—		5.9			5.9
Depreciation, depletion and amortization		17.5		—		2.7		—		—			20.2
Segment profit (loss)(b)		50.1		—		8.1		—		(35.2	)		23.0
Capital expenditures		5.4		—		4.5		—		3.0			12.9
Segment assets		566.3		—		121.0		—		81.8			769.1


(a)		Represents results of our derivatives activity.

(b)		Segment profit (loss) is defined as sales to external customers minus cost of natural gas and natural gas liquids and other cost of sales for the midstream segments and royalty income and lease bonus income less production taxes and depletion for the upstream segment. Sales to external customers for the corporate column include the impact of the risk management activities.

The following table reconciles segment profit (loss) to income from continuing operations:


	Three Months			Three Months			Six Months			Six Months
	Ended			Ended			Ended			Ended
	June 30,			June 30,			June 30,			June 30,
*($ in millions)*	2007			2006			2007			2006
Segment profit	$	10.1		$	18.6		$	26.2		$	23.0
Operations and maintenance		(11.4	)		(9.1	)		(19.3	)		(14.8	)
General and administrative		(5.9	)		(3.6	)		(10.8	)		(6.0	)
Depreciation, depletion and amortization		(14.1	)		(11.0	)		(25.8	)		(20.2	)
Interest expense, net		(2.2	)		(3.4	)		(13.4	)		(6.0	)
State income tax provision		(0.3	)		(0.5	)		(0.4	)		(0.5	)

Net loss	$	(23.8	)	$	(9.0	)	$	(43.5	)	$	(24.5	)

NOTE 13. INCOME TAXES

No provision for federal income taxes related to the operation of the Partnership is included in the consolidated financial statements as such income is taxable directly to the partners holding interests in the Partnership. In May 2006, the State of Texas enacted a margin tax which will become effective in 2008. This margin tax will require the Partnership to determine a tax of 1.0% on our “margin,” as defined in the law, beginning in 2008 based on our 2007 results. The margin to which the tax rate will be applied generally will be calculated as our revenues for federal income tax purposes less a qualified portion of the cost of the products sold, operating expenses and depreciation

expense for federal income tax purposes, in the state of Texas. Under the provisions of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”, the Partnership is required to record the effects on deferred taxes for a change in tax rates or tax law in the period which includes the enactment date. For the three and six month periods ended June 30, 2007, the Partnership recorded approximately $0.2 million and approximately $0.4 million, respectively, deferred state tax expense.

Under FAS 109, taxes based on income like the Texas margin tax are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at the end of the period. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.

Temporary differences related to the Partnership’s property, including depreciation expense, will affect the Texas margin tax. As of June 30, 2007, the Partnership has a deferred state tax liability in the approximate amount of $1.2 million.

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 unit options, restricted units and phantom units. With the consummation of the initial public offering on October 24, 2006, 124,450 restricted common units were issued to the employees and directors of the General Partner who provide services to the Partnership. With the completion of the Montierra and Laser acquisitions, during May and June 2007, 345,271 restricted common units were issued to the employees and independent directors of the General Partner who provide services to the Partnership. The awards generally vest on the basis of one third of the award each year. During the restriction period, distributions associated with the granted awards will be distributed to the awardees. No options or phantom units have been issued to date.

A summary of the restricted common units activity for the six months ended June 30, 2007, is provided below:


	Number of
	Restricted			Weighted Average
	Units			FairValue
Outstanding at December 31, 2006		122,450		$	18.75
Granted		345,271		$	23.35
Vested		—
Forfeitures		(17,700	)	$	21.91

Outstanding at June 30, 2007		450,021		$	22.22

For the three and six month periods ended June 30, 2007, non-cash compensation expense of approximately $0.2 million and $0.6 million, respectively, was recorded related to the granted restricted units.

As of June 30, 2007, unrecognized compensation costs related to the outstanding restricted units under our LTIP totaled approximately $10.1 million. The restricted units granted in connection with the initial public offering were valued at the market price of the initial public offering less a discount for the delay in their cash distributions during the unvested period. The restricted units granted in 2007 were valued at the market price as of the date issued. The restricted units forfeited throughout the six months ended June 30, 2007 had a weighted average of $21.91. The remaining expense is to be recognized over a weighted average of 2.5 years.

NOTE 15. SUBSEQUENT EVENTS

On July 31, 2007, the Partnership announced it had completed the acquisition of Escambia Asset Co., LLC and Escambia Operating Company, LLC (collectively, “EAC”) for an aggregate purchase price of approximately $240.5 million, including working capital adjustments, comprised of approximately $224.0 million in cash and 689,857 in Eagle Rock Energy common units. The assets subject to this transaction includes operated wells in Escambia County, Alabama and proved reserves of approximately 12.2 MMBoe, of which 89% is proved developed producing. The transaction also included two treating facilities, one natural gas processing plant and related gathering systems. The

acquisition of EAC will be accounted for as a purchase in accordance with Staff Accounting Bulletin Topic 2D,Financial Statements of Oil and Gas Exchange Offers(“Topic 2D”).

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) (collectively, “Redman”). For a combined value of approximately $189.7 million, including working capital adjustments, Redman received as consideration a total of 4,428,334 newly-issued Eagle Rock Energy common units and $83.8 million in cash. The assets conveyed in the Redman transaction included operated and non-operated wells mainly located in East and South Texas and combined proved reserves of 8.3 MMBoe, of which 78% is proved developed producing. The acquisition of Redman will be accounted for as a purchase in accordance with Topic 2D.

One or more Natural Gas Partners private equity funds (“NGP”) directly or indirectly owns a majority of the equity interests in Eagle Rock Energy and Redman. Because of the potential conflict of interest between the interests of Eagle Rock Energy G&P, LLC (the “Company”) and the public unitholders of Eagle Rock Energy, the Board of Directors authorized the Company’s Conflicts Committee to review, evaluate, and, if determined appropriate, approve the Redman acquisition. The Conflicts Committee, consisting of independent Directors of the Company, determined that the Redman acquisition was fair and reasonable to Eagle Rock Energy and its public unitholders and recommended to the Board of Directors of the Company that the transaction be approved and authorized. In determining the purchase consideration for the Redman acquisition, the Board of Directors considered the valuation of the properties involved in the transaction, the valuation of the units to be offered as consideration in the transaction, and the reserves and operational cash flow of Redman.

On July 31, 2007, the Partnership completed the private placement of 9,230,770 common units to third-party investors for total cash proceeds of approximately $204.0 million to partially finance the cash consideration of the EAC and Redman acquisitions. The Partnership also has agreed to file a registration statement with the Securities and Exchange Commission registering for resale the newly-issued common units within 90 days after the closing. In addition, on July 31, 2007, the Partnership drew $106.0 million from its revolver facility under its Amended and Restated Credit Facility to finance the remaining cash consideration of the EAC and Redman acquisitions.

NOTE 16. RESTATEMENT

In October 2007, subsequent to the filing of its Quarterly Report on Form 10-Q for the interim period ended June 30, 2007, the Partnership discovered accounting errors effecting gross revenues and cost of goods sold in the subsidiaries acquired during the second quarter of 2007, and discussed these errors with the Audit Committee of the Board of Directors of G&P. The errors impact the Partnership’s South Texas Segment and relate to two items: (i) marketing service agency agreements and (ii) intra-segment transactions. Certain of the subsidiaries’ marketing service agency agreements were accounted for on a “gross” revenue basis — recording gross revenues and gross expenses related to the natural gas transactions covered by the agency agreements as if title and/or credit risk had effectively passed to the Partnership, rather than on a “net” revenue basis — recording only the agency fee as revenue, properly reflecting the fact that neither title nor credit risk actually passed to the Partnership. The subsidiaries also recorded a number of intra-segment transactions related to the South Texas Segment, and these intra-segment transactions were not properly eliminated as part of the consolidation for the second quarter of 2007, resulting in an overstatement of revenues and costs by an equal amount. Management, at the direction of the Audit Committee, concluded that the Partnership should restate previously issued interim unaudited condensed consolidated financial statements for the three and six months ended June 30, 2007 to reflect the correct accounting treatment for these items.

A summary of the effects of the restatement is as follows:


	Three Months				Six Months
	Ended June 30, 2007				Ended June 30, 2007
	As Previously		As		As Previously		As
*($ in thousands except per share data)*	Reported		Restated		Reported		Restated
REVENUE:
Natural gas sales	$	132,795	$	107,220	$	181,067	$	155,492

COSTS AND EXPENSES:
Cost of natural gas and natural gas liquids		189,939		164,364		280,575		255,000

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

The following management discussion and analysis gives effect to the restatement discussed in Note 16 of the Notes to the Unaudited Condensed Consolidated Financial Statements.

Overview

We are a Delaware limited partnership formed in March 2006 to own and operate the assets that have historically been owned and operated by Eagle Rock Pipeline, L.P. and its subsidiaries. In 2002, certain former and current members of our management team formed Eagle Rock Energy, Inc. to provide midstream services to natural gas producers. In 2003, certain former and current members of our management team and Natural Gas Partners formed Eagle Rock Holdings, L.P., the successor to Eagle Rock Energy, Inc., to own, operate, acquire and develop complementary natural gas midstream assets. Our growth is organic as well as through acquisitions. We have grown significantly through acquisitions historically focused in the midstream business. During the second quarter 2007, we completed the Laser Acquisition, a midstream acquisition described below. During the second quarter 2007, we also completed our first transaction (the Montierra Acquisition described below) in the upstream business. Additionally, in the second quarter 2007, we also completed the MacLondon Acquisition, described below. In the third quarter 2007, we completed two additional transactions (the Redman Acquisition and the EAC Acquisition described below) in the upstream business.

Our organic growth projects include the expansion and extension of our gathering systems in the Texas Panhandle (East-West gathering pipeline) and our Tyler County pipeline and extension allowing for flexibility between our southeast Texas and Louisiana System (Brookeland, Masters Creek and Indian Springs), as well as increasing gas well connects and processing plants modifications. In addition, we put into service the extension of our Tyler County pipeline in late March 2007 and started up our idled Red Deer processing plant in the Texas Panhandle Systems on June 21, 2007.

We believe we continue to have significant opportunities for continued expansion of our existing gathering and processing systems in order to increase the capacity, efficiency and profitability of these systems through the implementation of commercial and operational development projects. Additionally, we have significant opportunities to expand our newly acquired exploration and production assets.

Cautionary Note Regarding Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by Eagle Rock Energy Partners, L.P. (the “Partnership”) in periodic press releases and some oral statements of Partnership officials during presentations about the Partnership, 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 the Partnership believes 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 since many of the factors which determine these results are subject to uncertainties and risks, difficult to predict, 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, 2006, filed with the Securities and Exchange Commission on April 2, 2007 and Form 10-K/A filed with the Securities and Exchange Commission on July 26, 2007.

Our Operations

Our results of operations for our Texas Panhandle Systems, south Texas Systems, southeast Texas and Louisiana Systems are determined primarily by the volumes of natural gas gathered, compressed, treated, processed and transported through our gathering, processing and pipeline systems and the associated commodity prices for natural gas, NGLs and condensate. We gather and process natural gas pursuant to a variety of arrangements generally categorized as “fee-based” arrangements, “percent-of-proceeds” arrangements, “fixed recovery” arrangements and “keep-whole” arrangements. Under fee-based arrangements, we earn cash fees for the services we render. Under the latter two types of arrangements, we generally purchase raw natural gas and sell processed natural gas and NGLs.

Percent-of-proceeds and keep-whole arrangements involve commodity price risk to us because our margin is based in part on natural gas and NGL prices. We seek to minimize our exposure to fluctuations in commodity prices in several ways, including managing our contract portfolio. In managing our contract portfolio, we classify our gathering and processing contracts according to the nature of commodity risk implicit in the settlement structure of those contracts.

	•		Fee-Based Arrangements. Under these arrangements, we generally are paid a fixed cash fee for performing the gathering and processing service. This fee is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. A sustained decline, however, in commodity prices could result in a decline in volumes and, thus, a decrease in our fee revenues. These arrangements provide stable cash flows, but minimal, if any, upside in higher commodity price environments. As of June 30, 2007, these arrangements accounted for approximately 35% of our natural gas volumes.

	•		Percent-of-Proceeds Arrangements. Under these arrangements, we generally gather raw natural gas from producers at the wellhead, transport the gas through our gathering system, process the gas and sell the processed gas and/or NGLs at prices based on published index prices. These arrangements provide upside in high commodity price environments, but result in lower margins in low commodity price environments. We regard the margin from this type of arrangement, that is, the sale proceeds less amounts remitted to the producers, as an important analytical measure of these arrangements. The price paid to producers is based on an agreed percentage of one of the following: (1) the actual sale proceeds; (2) the proceeds based on an index price; or (3) the proceeds from the sale of processed natural gas or NGLs or both. We refer to contracts in which we share only in specified percentages of the proceeds from the sale of NGLs and in which the producer receives 100% of the proceeds from natural gas sales, as “percent-of-liquids” arrangements. Under percent-of-proceeds arrangements, our margin correlates directly with the prices of natural gas and NGLs and under percent-of-liquids arrangements, our margin correlates directly with the prices of NGLs (although there is often a fee-based component to both of these forms of contracts in addition to the commodity sensitive component). As of June 30, 2007, these arrangements accounted for about 38% of our natural gas volumes.

	•		Fixed Recovery Arrangements.Under these arrangements, we generally gather raw natural gas from producers at the wellhead, transport the natural gas through our gathering system, process the natural gas and sell the processed natural gas and/or NGLs at prices based on published index prices. These arrangements provide upside in high commodity price environments, but result in lower margins in law commodity price environments. We regard the margin from this type of arrangement, that is, the sale proceeds less amounts remitted to the producers, as an important analytical measure of these arrangements. The price paid to the producers is based on an agreed to theoretical product recovery factor to be applied against the wellhead production and then a percentage of the theoretical proceeds based on an index or actual sales prices multiplied to the theoretical production. To the extent that the actual recoveries differ from the theoretical product recovery factor, this will affect the margin. As of June 30, 2007, these arrangements accounted for approximately 17% of our natural gas volumes.

•

Keep-Whole Arrangements. Under these arrangements, we process raw natural gas to extract NGLs and pay to the producer the full thermal equivalent volume of raw natural gas received from the producer in the form of either processed natural gas or its cash equivalent. We are generally entitled to retain the processed NGLs and to sell them for our account. Accordingly, our margin is a function of the difference between the value of the NGLs produced and the cost of the processed gas used to replace the thermal equivalent value of those NGLs. The profitability of these arrangements is subject not only to the commodity price risk of natural gas and NGLs, but also to the price of natural gas relative to NGL prices. These arrangements can provide large profit margins in favorable commodity price environments, but also can be subject to losses if the cost of natural gas exceeds the value of its thermal equivalent of NGLs. Many of our keep-whole contracts include provisions that reduce our commodity price exposure, including (1) conditioning floors that require the keep-whole contract to convert to a fee-based arrangement if the NGLs have a lower value than their thermal equivalent in natural gas, (2) embedded discounts to the applicable natural gas index price under which we may reimburse the producer an amount in cash for the thermal equivalent volume of raw natural gas acquired from the producer, or (3) fixed cash fees for ancillary services, such as gathering, treating and compressing. As of June 30, 2007, these arrangements accounted for about 10% of our natural gas volumes. Approximately 87% of these keep-whole arrangements have fee components.

In addition, we are a seller of NGLs and are exposed to commodity price risk associated with downward movements in NGL prices. NGL prices have experienced volatility in recent years in response to changes in the supply and demand for NGLs and market uncertainty. In response to this volatility, we have instituted a hedging program to reduce our exposure to commodity price risk. Under this program, we have hedged substantially all of our share of NGL volumes under percent-of-proceed and keep-whole contracts in 2006 and 2007 through the purchase of NGL put contracts, costless collar contracts and swap contracts. We have also economically hedged substantially all of our share of NGL volumes under percent-of-proceed contracts from 2008 through 2010 through a combination of direct NGL hedging as well as indirect hedging through crude oil costless collars. Additionally, to mitigate the exposure to natural gas prices from keep-whole volumes, we have purchased natural gas calls from 2006 to 2007 to cover substantially all of our short natural gas position associated with our keep-whole volumes. We anticipate that after 2007, our short natural gas position will be reduced because of our increased volumes in the Texas Panhandle and the volumes contributed from our acquisitions. In addition, we intend to pursue fee-based arrangements, where market conditions permit, and to increase retained percentages of natural gas and NGLs under percent-of-proceed arrangements. We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.

The following is a summary of the contracts that are significant to our operations, which contracts consist of a natural gas liquids exchange agreement, a gathering and processing agreement and four gas purchase agreements.

ONEOK Hydrocarbon. We are a party to a natural gas liquids exchange agreement with ONEOK Hydrocarbon, L.P., dated December 1, 2005. We deliver all of our natural gas liquids extracted at six of our natural gas processing plants in the Texas Panhandle to ONEOK for transportation and fractionation services. We take title to all of these volumes and they are physically delivered to Conway, Kansas where mid-continent type natural gas liquids pricing is available, with an option to exchange certain volumes at Mont Belvieu, Texas where gulf coast type natural gas liquids pricing is available. The primary contract term expires on June 30, 2010, of which an extension to June 30, 2015, may be mutually agreed to by the parties.

Chesapeake Energy Marketing. We are a party to a natural gas purchase agreement with Chesapeake Energy Marketing Inc., dated July 1, 1997, whereby we purchase raw natural gas from a number of wells on acreage dedicated to us located in Moore and Carson Counties, Texas. The natural gas from these wells is delivered into our Stinnett and Cargray gathering and processing systems. The acreage dedication under this contract is for the life of the leases from which the natural gas is produced. We pay Chesapeake an index posted gas price, less a fixed charge and fixed commodity fee and a fixed fuel percentage. Under this contract, there is an annual option to renegotiate the fuel and fees components. The original agreement was between MC Panhandle, Inc. and MidCon Gas Services Corp. and, as a result of ownership changes, the contract is now between Chesapeake and us.

Ergon Energy Partners, L.P. We are a party to a gas purchase agreement with Ergon Energy Partners, L.P., dated September 1, 2005, whereby we gather and process raw natural gas from a number of wells on acreage dedicated to us located in Tyler County, Texas. The natural gas from these wells is delivered to our Tyler County pipeline system.

The term of this contract runs through September 30, 2011. We receive a percentage of the natural gas liquid value and fees for gathering and processing services.

Prize Operating Company. We are a party to a gas purchase agreement with Prize Operating Company, dated March 28, 1994, whereby we gather and process raw natural gas from a number of wells on acreage dedicated to us located in Roberts and Hemphill Counties, Texas, delivered to our Canadian processing plant. This is a life of lease contract. We receive a percentage of the natural gas liquid value and a percentage of the natural gas residue value for gathering and processing services. The original agreement was between Warren Petroleum Company and Wallace Oil & Gas, Inc. and, as a result of ownership changes, the contract is now between Cimarex and us.

In our upstream business, the results of operations are determined primarily by oil and gas revenues from our royalty, overriding royalty and non-operated working interests (less applicable production taxes), and lease bonuses and delay rentals derived from our fee minerals holdings. The royalty and overriding royalty interests do not bear drilling or production costs. Ownership of the mineral interest in a property is a perpetual ownership.

Our upstream revenues are highly sensitive to changes in oil, gas and NGL prices and levels of production. As of June 30, 2007, we have hedged a significant portion of our expected production through 2009 using oil and gas derivatives, which allows us to mitigate, but not eliminate, commodity price risk.

Our revenue, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other producers. Oil, gas and NGL prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil, gas or NGL could materially and adversely affect our financial position, our results of operations, the quantities of productive reserves that we can economically produce and our access to capital.

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.

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

Upstream volumes.Our upstream assets are comprised of royalty, overriding royalty, non-producing mineral, and non-operating working interests, and therefore, we do not operate any of the properties in which we have an interest. In order to maintain or increase our cash flows from our Upstream segment, we are reliant upon the efforts of the operators of our interests. We do not control whether or when additional drilling or recompletion activity will be conducted on the properties in which we have an interest; however, when these activities do occur, we do not bear any of their costs (with the exception of two wells in which we own a working interest).

The level of drilling and recompletion activity conducted by the operators of our interests is a function of many factors beyond our control, such as commodity prices, availability of oilfield goods and services, and the requirements and limitations placed by various legislative and regulatory entities. Nevertheless, at any time, there is often a significant amount of drilling and recompletion activity occurring on the properties in which we own an interest. We refer to this phenomenon as the “regeneration effect” of mineral and royalty interests. We monitor the additional production volumes that we realize from regeneration, and use this information to make adjustments to our reserves estimates on a regular basis. The additional production we realize, and the resulting adjustments to our reserves, are important measures of the performance of our upstream business.

Margins. As of June 30, 2007, our overall portfolio of processing contracts reflected a net short position in natural gas of approximately 8,343 MMBtu/d (meaning we were a net buyer of natural gas) and a net long position in NGLs (including condensate) of approximately 6,406 Bbls/d (meaning we were a net seller of NGLs). As a result, during this period, our margins were positively impacted to the extent the price of NGLs increased in relation to the price of natural gas and were adversely impacted to the extent the price of NGLs declined in relation to the price of natural gas. We refer to the price of NGLs in relation to the price of natural gas as the fractionation spread. This portfolio performed well in response to favorable fractionation spreads during these periods. Because of the hedging program of our commodity risk, we have been able to develop overall favorable fractionation spreads within a range and we anticipate our unit margins will not be subject to significant downward fluctuations if commodity prices were to change in an unfavorable relationship.

Risk Management. For the quarter ended June 30, 2007, our risk management portfolio value changes reflected a $27.2 million unrealized non-cash loss recorded to Total Revenues for our natural gas, natural gas liquids and condensate associated derivatives. In addition, we recorded $6.8 million unrealized non-cash gain within Interest and Other Expense related to the interest rate swaps associated with our credit agreement. As both of the unrealized positions reflect underlying commodity prices and interest rates both in the short and long-term, the unrealized value position will be subject to variability from period to period.

Operating Expenses. Operating expenses are a separate measure we use to evaluate operating performance of field operations. Direct labor, insurance, repair and maintenance, utilities and contract services comprise the most significant portion of our operating expenses. These expenses are largely independent of the volumes through our systems, but fluctuate depending on the activities performed during a specific period. We do not deduct operating expenses from total revenues in calculating segment margin because we separately evaluate commodity volume and price changes in segment margin.

With the exception of two wells in which we own a minor working interest, the majority of our upstream assets are non-cost-bearing interests in oil and gas wells. Therefore, except for the two wells mentioned, the operating expenses in our upstream business currently includes only production taxes at applicable rates.

Adjusted EBITDA. We define Adjusted EBITDA as net income (loss) plus income tax, interest-net, depletion, depreciation and amortization expense, other non-cash operating expenses less non realized revenues risk management loss (gain) activities and less net income from discontinued operations. We have included as an addback to net income (loss) for 2007 the approximate $1.4 million arbitration award (see Note 11) relating to a period before the Partnership owned or operated the related assets. 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.

General Trends and Outlook

We expect our business to continue to be affected by the following key trends. 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, Demand and Outlook. Natural gas continues to be a critical component of energy consumption in the United States. According to the Energy Information Administration, or EIA, total annual domestic consumption of natural gas is expected to increase from approximately 22.2 trillion cubic feet, or Tcf, in 2005 to

approximately 22.35 Tcf in 2010. During the last three years, the United States has on average consumed approximately 22.3 Tcf per year, while total marketed domestic production averaged approximately 18.5 Tcf per year during the same period. The industrial and electricity generation sectors currently account for the largest usage of natural gas in the United States.

We believe current natural gas prices and the existing strong demand for natural gas will continue to result in relatively high levels of natural gas-related drilling in the United States as producers seek to increase their level of natural gas production. Although the natural gas reserves in the United States have increased overall in recent years, a corresponding increase in production has not been realized. We believe this lack of increased production is attributable to insufficient pipeline infrastructure, the continued depletion of existing wells and a tight labor and equipment market. We believe an increase in United States natural gas production, additional sources of supply such as liquid natural gas, and imports of natural gas will be required for the natural gas industry to meet the expected increased demand for natural gas in the United States.

Most of the areas in which we operate are experiencing significant drilling activity. Although we anticipate continued high levels of exploration and production activities in substantially all of the areas in which we operate, fluctuations in energy prices can affect production rates over time and levels of investment by third parties in exploration for and development of new natural gas reserves. We have no control over the level of natural gas exploration and development activity in the areas of our midstream operations.

Crude Oil Supply, Demand and Outlook.Throughout the world, crude oil is a highly desired commodity. During the last decade, several large, developing nations have undergone tremendous growth in their economies and in their consumption of crude oil, while many developed nations have continued to increase their consumption. We believe that over the long term these trends will continue (particularly in the developing economies of Asia), although there may be periods of slower growth than those that were experienced in the last several years.

The supply of crude oil has continued to increase as well, but perhaps not as quickly as demand. To some extent, this can be attributed to the fact that much of the current and incremental supply sources are in parts of the world that suffer from political and economic instability, or are countries that lack the capital and human resources required to better expand their crude oil supply capability. We believe that this provides some rationale for the record-high crude oil prices that have been recently experienced.

Although crude oil supply and demand is effected by a myriad of factors, many of which are unpredictable, our opinion is that demand for crude oil will remain strong, in the absence of a significant economic slowdown in the developed and developing nations. We also expect crude oil supply to continue to increase, but not by amounts that are likely to reduce prices significantly. Because of our observations regarding supply and demand, we have a favorable outlook for future crude oil prices. Nevertheless, we recognize that crude oil prices are highly volatile.

Impact of Interest Rates and Inflation. The credit markets have experienced historically low interest rates over the past several years. If the overall United States economy continues to strengthen, we believe it is likely that monetary policy will tighten further, resulting in higher interest rates to counter possible inflation. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. During the quarter, we have seen a tightening of capital availability in the capital markets due to the continuing pressure from the subprime mortgage markets and corresponding reaction by lenders to risk. Although this could limit our ability to raise funds in the capital markets, we expect in this regard to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances.

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations in 2006 or 2007. It may in the future, however, increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. Our operating revenues and costs are influenced to a greater extent by price changes in natural gas and NGLs. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees.

Formation and Acquisitions

We are a Delaware limited partnership formed in March 2006, to own and operate the assets that have historically been owned and operated by Eagle Rock Holdings, L.P. and its subsidiaries. In 2002, certain former and current members of our management team formed Eagle Rock Energy, Inc. to provide midstream services to natural gas producers. In 2003, certain former and current members of our management team and Natural Gas Partners formed Eagle Rock Holdings, L.P., the successor to Eagle Rock Energy, Inc., to own, operate, acquire and develop complementary midstream energy assets. Natural Gas Partners is one of the largest private equity fund sponsors of companies in the energy sector and, since 2003, has provided us with significant support in pursuing acquisitions.

In addition to the acquisitions carried out prior to our initial public offering on October 24, 2006, we have recently completed the following transactions:

Acquisition of fee minerals, royalties and working interest properties from Montierra Minerals & Production, L.P.

On April 30, 2007, we completed the acquisition of 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”), for an aggregate purchase price of $127.4 million. Montierra and NGP received as consideration a total of 6,390,400 Eagle Rock Energy common units and extinguishment of $6.0 million of debt. The assets acquired include interests in over 2,500 wells in multiple producing trends across 17 states in the United States, interests in approximately 5.6 million gross mineral acres or 430,000 net mineral acres, and interests in over 2,500 well with net proved producing reserves of approximately 4.5 billion cubic feet of natural gas and 3.5 million barrels of crude oil.

Acquisition of Laser Midstream Energy, L.P.

On May 3, 2007, we acquired all of the non-corporate interests of Laser Midstream Energy, LP and certain subsidiaries (the “Laser Acquisition”), for a total purchase price of approximately $136.8 million, consisting of $110.0 million in cash and 1,407,895 of our common units. The assets subject to the transaction include over 405 miles of gathering systems and related compression and processing facilities in South Texas, East Texas and North Louisiana.

Acquisition of fee minerals, royalties and working interest properties from MacLondon Energy, L.P.

On June 18, 2007, we completed the acquisition of certain fee mineral and royalties owned by MacLondon Energy, L.P. (the “MacLondon Acquisition”), for a purchase price of $18.9 million. MacLondon received as consideration a total of 789,474 common units. The transaction has an effective date of January 1, 2007.

Acquisition of Escambia Asset Co., L.P.

On July 31, 2007, we completed the acquisition of Escambia Asset Co., LLC and Escambia Operating Company, LLC (the “EAC Acquisition”) for an aggregate purchase price of approximately $240.5 million, including working capital adjustments, comprised of approximately $224.0 million in cash and 689,857 in Eagle Rock Energy common units. The assets subject to this transaction included 33 operated wells in Escambia County, Alabama with net production of approximately 3,300 Boepd and proved reserves of approximately 12.2 MMBoe, of which 89% is proved developed producing. The transaction also included two treating facilities with 100 MMcfd of capacity, one natural gas processing plant with 40 MMcfd of capacity and related gathering systems. The acquisition has an effective date of April 1, 2007.

Acquisition of Redman Energy Holdings, L.P.

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”). For a combined value of approximately $189.7 million, including working capital adjustments, Redman received as consideration a total of 4,428,334 newly-issued Eagle Rock Energy common units and $83.8 million in cash. The assets conveyed in the Redman transaction included 76 operated and 95 non-operated wells mainly located in East and South Texas with a net production of 1,810 Boepd and combined proved reserves of 8.3 MMBoe, of which 78% is proved developed producing.

Critical Accounting Policies and Estimates

Except for the adoption of the Successful Efforts method of accounting for oil and gas properties described below and in Note 2, Summary of Significant Accounting Policies, as a result of the Montierra and MacLondon acquisitions, there have been no changes during the second quarter of 2007 to our critical accounting policies as we described in our Annual Report on Form 10-K and Annual Report on Form 10-K/A for the year ended December 31, 2006.

Geological, geophysical and dry hole costs on oil and natural gas properties relating to unsuccessful wells are charged to expense as incurred.

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.

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

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. We prepare our reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing their reserve reports. The accuracy of our reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates.

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

EAGLE ROCK ENERGY PARTNERS, L.P.

RESULTS OF OPERATIONS

The following table is a summary of the results of operations for the three month period ended June 30, 2007 and 2006:


	Three Months						Six Months
	Ended June 30,						Ended June 30,
*($ in thousands)*	2007			2006			2007			2006
Sales of natural gas, NGLS and condensate	$	191,621		$	125,985		$	301,742		$	240,172
Compression, gathering and processing		6,883			3,925			11,166			5,946
Gain/(loss) on realized risk management instrument		1,502			(241	)		4,501			570
Gain/(loss) on unrealized risk management instrument		(28,757	)		(14,930	)		(39,398	)		(35,811	)
Royalty income		3,121			—			3,121			—
Lease and bonus income		71			—			71			—
Other income		—			147			—			327

Total operating revenue		174,441			114,886			281,203			211,204

Purchase of natural gas and NGLs		164,364			96,245			255,000			188,236


Segment profit(a)		10,077			18,641			26,203			22,968

Operating and maintenance expense		11,397			9,115			19,320			14,797
General and administrative expense		5,898			3,557			10,821			6,010
Other (income)/expense		(91	)		—			1,620			—
Depreciation, depletion and amortization		14,149			11,001			25,779			20,215
Interest-net including realized risk management instrument		8,736			2,566			16,568			10,036
Unrealized risk management interest related instrument		(6,485	)		863			(4,874	)		(4,112	)
State income tax provision		256			508			420			508


Net loss	$	(23,783	)	$	(8,969	)	$	(43,451	)	$	(24,486	)


Adjusted EBITDA(b)	$	22,159		$	20,899		$	36,252		$	38,011


(a)		Defined as operating revenues minus the cost of natural gas and NGLs and other cost of sales. Operating revenues include both realized and unrealized risk management activities.

(b)		Defined as net income (loss) plus income tax, interest-net, depletion, depreciation and amortization expense, separation costs, other non-cash operating expenses less non realized revenues risk management loss (gain) activities and less net income from discontinued operations. The prior year legal arbitration settlement recorded in Other expense for June 30, 2007 quarter has also been added back to net income (loss).

The following table reconciles segment profit to net loss:


	Three Months				Six Months
	Ended June 30,				Ended June 30,
*($ in thousands)*	2007		2006		2007		2006
Segment profit:	$	10,077	$	18,641	$	26,203	$	22,968
*Less:*
Operations and maintenance		11,397		9,115		19,320		14,797
General and administrative		5,898		3,557		10,821		6,010


	Three Months						Six Months
	Ended June 30,						Ended June 30,
*($ in thousands)*	2007			2006			2007			2006
Depreciation, depletion and amortization		14,149			11,001			25,779			20,215
Interest-net including realized risk management instrument		8,736			2,566			16,568			10,036
Unrealized risk management interest related instrument		(6,485	)		863			(4,874	)		(4,112	)
Other (income)/expense		(91	)		—			1,620			—
State income tax provision		256			508			420			508

Net loss	$	(23,783	)	$	(8,969	)	$	(43,451	)	$	(24,486	)

The following table reconciles Adjusted EBITDA to net loss:


	Three Months						Six Months
	Ended June 30,						Ended June 30,
*($ in thousands)*	2007			2006			2007			2006
Adjusted EBITDA:	$	22,159		$	20,899		$	36,252		$	38,011
*Less:*
State income tax provision		256			508			420			508
Interest-net including realized risk management instrument		8,736			2,566			16,568			10,036
Unrealized risk management interest related instrument		(6,485	)		863			(4,874	)		(4,112	)
Depreciation, depletion and amortization		14,149			11,001			25,779			20,215
Equity-based compensation expense		620			—			792			—
Other (income)/expense		(91	)		—			1,620			39
*Plus:*
Risk management instruments-unrealized		(28,757	)		(14,930	)		(39,398	)		(35,811	)


Net loss	$	(23,783	)	$	(8,969	)	$	(43,451	)	$	(24,486	)

Three Months Ended June 30, 2007 Compared with Three Months Ended June 30, 2006

Operating revenues for sales of natural gas, NGLs and condensate for the second quarter of 2007 increased by $65.6 million, 52% increase, from the second quarter of 2006 due primarily to the addition of natural gas, NGL and condensate revenues from the Laser Acquisition, increased volumes on the Tyler County system and improved NGL pricing with respect to the second quarter of 2006. Negatively impacting revenue for the second quarter of 2007 as compared to the second quarter of 2006 was the unscheduled shutdown and turnaround of a large processing plant in the Texas Panhandle segment, lower crude oil prices and an increase in our short natural gas position due to improved recoveries on certain contracts.

Compression, gathering and processing for second quarter 2007 is $6.8 million as compared to $3.9 million for the second quarter 2007, or an increase of 74%. This increase reflects primarily the increase in fee contracts for gas compression and conditioning as well as the inclusion of the Laser acquisitions in the current year quarter and the completion of the Tyler County Pipeline extension project in March 2007.

Realized risk management net gain for the three month period ended June 30, 2007 is $1.5 million compared to $0.2 million for the three month period ended June 30, 2006. The increase is primarily due to the reduction in crude oil average pricing between the second quarter of 2006 ($70.66 per barrel) and the second quarter of 2007 ($65.08 per barrel).

Unrealized risk management net loss for the June 2007 quarter is a $28.8 million loss versus a $14.9 million loss in the June 2006 quarter. The activities for both quarters reflect the movement in future period prices during the quarters on the open derivative positions as well as amortization in both quarters for put premiums as the underlying options have expired. As the forward price curves for our hedged commodities shift in relations to caps, floors, swap and strike prices at which we have executed the derivative instrument, the fair value of such instruments changes through time. The mark to market net unrealized loss reflects overall unfavorable forward curve price movement during the period with respect to our derivative instruments. The unrealized mark to market activities recorded do not impact cash activities during the quarter.

Royalty income, lease and bonus income contributed $3.2 million during the June 2007 quarter as a result of the Montierra and MacLondon acquisitions during the quarter.

Purchase of natural gas and NGLs increased by $68.1 million, 71% increase, reflecting primarily the addition of Laser’s gas purchase contracts during the quarter and the increase in natural gas and natural gas liquids prices in the current period as compared to last year.

Segment profit decreased to $10.1 million for the June 2007 quarter compared to $18.6 million for the June 2006 quarter. The decrease is primarily from the higher net unrealized losses on risk management derivatives between periods.

Operations and maintenance expense increased in the current quarter by $2.3 million compared to June 2006 quarter primarily from the operations of the Laser and Montierra acquisitions ($1.4 million), as well as higher costs in the current quarter in our Panhandle segment primarily related to the unscheduled shutdown and turnaround of one of our large processing plants.

General and administrative expenses also increased $2.3 million primarily from the addition of infrastructure to support the Laser and Montierra acquisitions ($0.6 million) the higher costs of being a publicly-traded partnership, including increases in its corporate infrastructure as well as higher third party costs for accounting and auditing, legal fees, Sarbanes Oxley compliance activities and increased related insurance expense. Also, the current quarter activities included $0.3 million of expense related to partnership units registration rights filings.

Increase of $3.1 million in depreciation, depletion and amortization for current year’s quarter is primarily from the Laser and Montierra acquisitions ($2.1 million) as well as associated depreciation on construction projects completed and placed in service since June 2006 such as the Tyler County Pipeline extension and the Red Deer plant.

Interest-net including realized risk management instrument reflects primarily interest expense associated with our Amended and Restated Credit Agreement and the realized interest rate hedges for the period. The increase in interest expense between periods, approximately $6.2 million, is from increased funded debt, increased base interest rate and a higher add-on on rate.

Unrealized risk management interest related instrument for the June 2007 quarter of $6.5 million net gain relates to future period’s interest rate swaps and from changes during the quarter in the underlying interest rate associated with the derivatives. The unrealized mark to market loss does not impact cash activities during the quarter.

State income taxes recorded during the June 2007 quarter of approximately $0.3 million reflects the Texas Margin Tax (see Note 13) and was recorded as a deferred tax liability.

Six Months Ended June 30, 2007 Compared with Six Months Ended June 30, 2006

Financial results for the six months ended June 30, 2007 included activities of the Montierra (acquired April 30, 2007), Laser (May 3, 2007) and MacLondon (June 18, 2007) business combinations. The timing of these acquisitions affects the comparison between quarters.

Operating revenues for sales of natural gas, NGLs and condensate for the six months ended June 30, 2007 increased by $61.6 million, 26% increase, from the six months ended June 30, 2006 due primarily to the addition of natural gas, NGL and condensate revenues from the Laser Acquisition, a full six months of the Brookeland and MGS acquisitions and improved NGL pricing with respect to the first six months of 2006. Negatively impacting revenue for the six months ended June 30, 2007 as compared to the six months ended June 30, 2006 was the unscheduled shutdown and turnaround of two large processing plant in the Texas Panhandle segment and lower crude oil prices.

Compression, gathering and processing for six months ended June 30, 2007 is $11.2 million as compared to $5.9 million for the six months ended June 30, 2006, or an increase of 90%. This increase reflects primarily the increase in fee contracts for gas compression and conditioning as well as the inclusion of the Laser Acquisition in the second quarter of 2007, inclusion of a full six months of the Brookeland and MGS acquisitions and the completion of the Tyler County Pipeline extension project in March 2007.

Realized risk management net gain for six months ended June 30, 2007 is $4.5 million compared to $0.6 million for the six months ended June 30, 2006. The increase is primarily due to the reduction in crude oil average pricing between the first six months of 2006 ($67.04 per barrel) and the first six months of 2007 ($61.71 per barrel).

Unrealized risk management net loss for the six months ended June 30, 2007 is a $39.4 million loss versus a $35.8 million loss in the six months ended June 30, 2006. The activities for both periods reflect the movement in future period prices during the periods on the open hedge positions as well as amortization in both periods for put premiums as the underlying options have expired. As the forward price curves for our hedged commodities shift in relations to caps, floors, swap and strike prices at which we have executed the derivative instrument, the fair value of such instruments changes through time. The mark to market net unrealized loss reflects overall unfavorable forward curve price movement for the period with respect to our derivative instruments. The unrealized mark to market activities recorded do not impact cash activities during the period.

Royalty income, lease and bonus income contributed $3.2 million during the six months ended June 30, 2007 as a result of the Montierra and MacLondon acquisitions during the second quarter of 2007.

Purchase of natural gas and NGLs increased by $66.8 million, 35% increase, reflecting primarily the addition of Laser’s gas purchase contracts during the second quarter of 2007, inclusion of a full six months of the Brookeland and MGS acquisitions and the increase in natural gas liquids in the current period as compared to last year. In addition, an increase in our short natural gas position as a result of the two plant turnaround in the Texas Panhandle and improved recoveries on certain fixed recovery contracts in our southeast Texas and Louisiana segment during the second quarter of 2007 also increased our purchases of natural gas during the period.

Segment profit increased to $26.2 million for the six months ended June 30, 2007 compared to $23.0 million for the six months ended June 30, 2006. The increase is primarily from the positive addition of the Laser and Montierra acquisitions, inclusion of the Brookeland and MGS acquisitions for a full six months and the completion of the Tyler County Pipeline extension in March 2007.

Operations and maintenance expense increased in the six months ended June 30, 2007 by $4.5 million compared to the six months ended June 30, 2006 primarily from the operations of the Laser and Montierra acquisitions ($1.4 million), as well as higher costs in the current quarter in our Panhandle segment primarily related to the unscheduled shutdown and turnaround of two of our large processing plants during the first six months of 2007.

General and administrative expenses also increased by $4.8 million primarily from the addition of infrastructure to support the Laser and Montierra acquisitions ($0.6 million) the higher costs of being a publicly-traded partnership, including increases in its corporate infrastructure as well as higher third party costs for accounting and auditing, legal fees, Sarbanes Oxley compliance activities and increased related insurance expense.

Other operating expense reflects the arbitration award recorded during the first six months of 2007 of approximately $1.4 million (see Contingencies, Note 11) related to a dispute on the Panhandle operations for periods before the Partnership ownership. In addition, approximately $0.3 million relates to a separation expense accrual recorded during the current quarter.

Increase of $5.6 million in depreciation, depletion and amortization for six months ended June 30, 2007 is primarily from the Laser and Montierra acquisitions ($2.1 million) as well as associated depreciation on construction projects completed and placed in service since June 2006 such as the Tyler County Pipeline extension.

Interest-net including realized risk management instrument reflects primarily interest expense associated with our Amended and Restated Credit Agreement and the realized interest rate hedges for the period. The increase in interest expense between periods, approximately $6.5 million, is from increased funded debt, increased base interest rate and a higher add-on on rate.

Unrealized risk management interest related instrument for the six months ended June 30, 2007 of $4.9 million net loss relates to future period’s interest rate swaps and from changes during the period in the underlying interest rate associated with the derivatives. The unrealized mark to market loss does not impact cash activities during the quarter.

State income taxes recorded during the six months ended June 30, 2007 quarter of approximately $0.4 million reflects the Texas Margin Tax (see Note 13) and was recorded as a deferred tax liability.

Other Matters

Wildfires in Texas Panhandle.Wildfires in the Texas Panhandle during the week of March 11, 2006, temporarily affected our operations in the region. While the fires did not cause material direct damage to our facilities, some experienced down-time caused by power outages by the local electric co-ops. We had two processing and gathering facilities in the area impacted with reduced flow rates as producers had shut-in their production during the fires. There was minimal and temporary damage sustained in the field to a very small number of metering facilities and one flow line. Less than $0.1 million was spent on repairs caused by the fires. The overall economic impact was between $0.5 million and $1.0 million.

Environmental.A Phase I environmental study was performed on our Texas Panhandle assets by an independent environmental consultant engaged by us in connection with our pre-acquisition due diligence process in 2005. As a result of performing the Phase I environmental study, we are planning to conduct environmental investigations at 11 properties, the costs of which are estimated to collectively range between $0.2 million and $0.4 million, and for which we have accrued reserves in the amount of $0.3 million as of June 30, 2007. Depending on the findings made during those investigations, and in anticipation of implementing amended SPCC (Spill Prevention Control and Counter-measure) plans at multiple locations as well as performing selected cavern closures, we estimate an additional $1.2 million to $2.5 million in costs could be incurred by us in resolving environmental issues at those properties. We believe the likelihood we will be liable for any significant potential remediation liabilities identified in the study is remote. Separately, (1) we are entitled to indemnification with respect to certain environmental liabilities retained by prior owners of these properties, and (2) we purchased an environmental pollution liability insurance policy. The policy pays for on-site clean-up as well as costs and damages to third parties and currently has a one-year term with a $5.0 million limit subject to a $0.5 million deductible. We expect to renew this policy on an annual basis.

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 for our unitholders.

Cash Flows and Capital Expenditures

Since our inception in 2003 through June 30, 2007, there have been several key events that have had major impacts on our cash flows. They are:

	•		the acquisition of the Dry Trail plant on December 5, 2003 in the amount of approximately $18.0 million which was financed through equity of $6.0 million and debt of $14.0 million;

	•		the acquisition of a 20% interest in the Camp Ruby gathering system and a 25% interest in the Indian Springs processing plant on July 1, 2004 for approximately $20.0 million, consisting of proceeds achieved with the sale of the Dry Trail plant;

	•		the acquisition of the midstream assets in the Texas Panhandle on December 1, 2005 for approximately $531 million, which was financed through an additional equity contribution of $133 million and debt of $400

million, not including $27.5 million in risk management costs related to option premiums financed entirely with equity;

	•		the acquisition of the Brookeland gathering and processing facility and related assets on March 31, 2006 and April 7, 2006 for approximately $95.8 million, which we financed entirely with equity;

	•		the acquisition of all of the partnership interests in Midstream Gas Services, L.P. on June 2, 2006 for approximately $25.0 million which we financed with $4.7 million in cash and $21.3 million in Eagle Rock Pipeline, L.P. units;

	•		the acquisition of certain fee minerals, royalties and non-operated working interest properties from Montierra Minerals & Production, L.P., and NGP-VII Income Co-Investment Opportunities, L.P. on April 30, 2007 for an aggregate purchase price of $127.4 million financed with 6,390,400 of our common units and the extinguishment of $6.0 of debt;

	•		the acquisition of Laser Midstream Energy, LP, on May 3, 2007,including its subsidiaries Laser Quitman Gathering Company, LP, Laser Gathering Company, LP, Hesco Gathering Company, LLC, and Hesco Pipeline Company, LLC for a total purchase price of $136.8 million, consisting of $110.0 million in cash and 1,407,895 of our common units; and

	•		the private placement of 7,005,495 common units to several institutional purchasers in a private offering resulting in gross proceeds of $127.5 million, on May 3, 2007. The proceeds from this offering were used to fully fund the cash portion of the purchase price of the Laser Acquisition and other general company purposes.

On February 7, 2007, Eagle Rock Energy declared a cash distribution of $0.3625 per unit for the fourth quarter of 2006, prorated to $0.2679 per common unit for the timing of the initial public offering on October 24, 2006. The distribution to the common units was paid on February 15, 2007. No distribution was made to the subordinated or general partners for the quarter.

On May 4, 2007, Eagle Rock Energy expanded its revolver commitment level under its Amended and Restated Credit Agreement by $100.0 million to $300.0 million in total. No incremental funding under the Amended and Restated Credit Agreement was needed for the Laser and Montierra acquisitions. As of June 30, 2007, under the Amended and Restated Credit Agreement, we have total borrowing availability of $600 million and we have $422.1 million drawn down under the facility.

On May 4, 2007, Eagle Rock Energy declared a cash distribution of $0.3625 per common unit for the first quarter ending March 31, 2007. The distribution was paid May 15, 2007, for common unitholders of record as of May 7, 2007, not including unitholders who acquired units in either the Montierra Acquisition or the Laser Acquisition. No distribution was made to the subordinated or general partners for the quarter.

On July 31, 2007, Eagle Rock Energy completed three acquisitions in its midstream and upstream businesses for a combined purchase price of approximately $448.8 million, including working capital adjustments. In aggregate the transactions will result in the payment of $307.8 million in cash, including working capital adjustments and the issuance of 5,905,922 newly-issued common units. Additionally, Eagle Rock Energy completed the private placement of 9,230,770 common units to third-party investors, for total cash proceeds of approximately $204 million. The proceeds from this equity private placement were used to partially fund the cash portion of these acquisitions. In addition, on July 31, 2007, the Partnership drew $106 million from its revolver facility under its Amended and Restated Credit Facility to finance the remaining cash consideration of the EAC and Redman acquisitions.

On August 6, 2007, the Partnership declared a cash distribution of $0.3625 per unit for the second quarter ending June 30, 2007. The distribution will be paid August 14, 2007 to common unitholders of record as of August 8, 2007, not including unitholders who acquired units in the MacLondon (see Note 4), EAC or Redman acquisitions (see Note 15). No distribution was made to the subordinated or general partners for the quarter.

With the Laser and Montierra transactions, as well as the acquisitions completed on July 31, the Partnership expects to be able to make its distributions to all unitholders, including subordinated unitholders, for the fourth quarter ending December 31, 2007.

Working Capital (Deficit).Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. As of June 30, 2007, working capital was a negative (current liabilities exceeded current assets) $13.8 million as compared to a $12.1 million (positive) balance as of December 31, 2006. However, the Partnership has the ability to draw on its credit facility, if needed, to satisfy its current liabilities.

The net decreases in working capital of $25.8 million from December 31, 2006 to June 30, 2007, resulted primarily from the following factors:

	•		cash balances and marketable securities and cash advances to affiliates increased overall by $2.4 million and was impacted primarily from the working capital balances acquired in the Laser acquisition, from the results of operations, timing of capital expenditures payments, financing activities including our debt activities as well as members’ equity distributions;

	•		trade accounts receivable increased by $62.5 million primarily from the receivables assumed in the Laser and Montierra acquisitions;

	•		risk management net working capital balance decreased by a net $20.6 million as a result of the changes in the mark-to-market unrealized positions and fair value changing of the option premiums;

	•		prepayments and other current assets decreased by $1.0 million primarily from the property and liability prepaid insurance balances;

	•		accounts payable increased by $62.0 million from December 31, 2006 primarily as a result of the payables assumed in the Laser and Montierra acquisitions, activities and timing of payments, including capital expenditures activities; and

	•		accrued liabilities increase of $7.1 million primarily reflects unbilled expenditures related primarily to capital expenditures.

Cash Flows Six Months 2007 Compared to Six Months 2006

Cash Flows from Operating Activities.Increase of $13.1 million for the six months ended June 30, 2007 as compared to the six months ended June 30, 2006 is the result of increased working capital sources of $25.8 million and non-cash income charges of $6.3 million, offset by higher net loss of $19.0 million.

Cash Flows Used in Investing Activities.Cash flows used in investing activities for the six months ended June 30, 2007 as compared to the six months ended June 30, 2006, increased by $56.5 million. The investing activities for the prior year’s period reflect the Brookeland acquisition transaction for $102.7 million, and an escrow payment cash source related to the acquisition of $7.6 million. Capital expenditures between the two periods is cash used in current period of $119.7 million reflecting the Laser acquisition and higher capital expenditure activities of $25.1 million primarily associated with the Tyler County Pipeline extension and Red Deer projects for the current year’s activities. In addition cash advances to affiliates increased cash flows used in investing activities by $10.7 million and cash acquired in acquisition increased it by $3.8 million.

Cash Flows Provided by (Used in) Financing Activities.Cash flows provided by financing activities for the six months ended June 30, 2007 was $127.8 million as compared to a source of cash of $80.7 million for the June 2006 six month period. The increase in cash provided of $47.1 million is primarily from the issuance of members’ equity in May 2007 associated with the Laser acquisition of $127.5 million as compared to contributions by members in the six months ended June 30, 2006 of $98.4 million related to the Brookeland acquisition. Proceeds from long-term debt, net of repayment of long term debt, increased $26.6 million compared to the six months ended June 30, 2006. In the six months ended June 30 2007, there was a distribution to common unit holders of $16.2 million, compared to a $5.8 million distribution made in the six months ended June 30, 2006.

Capital Requirements

As we continue to expand our midstream and upstream businesses through acquisitions, our needs for capital, both as acquisition capital and as maintenance capital, continue to grow. We anticipate that we will have sufficient access to capital to maintain and commercially exploit the midstream and upstream assets being acquired.

In connection with the Montierra Acquisition and the acquisitions completed on July 31, 2007 (the Redman Acquisition and the EAC Acquisition), we are expanding our upstream line of business further, including becoming an operator of upstream 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 resource. We anticipate that we will meet these requirements through cash generated from operations, equity issuances, or incurring debt; however, we cannot provide assurances that we will be able to obtain the necessary capital under terms acceptable to us.

Our current capital budget anticipates that we will spend approximately $58.3 million in total in 2007 on our existing assets. To date, we have spent approximately $40.7 million primarily in the Tyler County Pipeline Extension and Red Deer Processing Plant projects. With the recent completion of the Redman Acquisition and the EAC Acquisition, we have increased our capital budget by $12.5 million on an annual basis. This increase results primarily from our anticipated drilling efforts and required cost-sharing arrangements as a working interest owner of oil and natural gas properties. Although we cannot provide assurances, we expect to be able to fund this increase in the capital budget through cash from operations.

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 well attachments costs 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, including those relating to the acquisition of the Dry Trail plant, the Camp Ruby gathering system, the Indian Springs processing plant, the Panhandle Assets, the Brookeland and Masters Creek gathering and processing assets, and the Montierra and Laser assets. 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 Amended and Restated Credit Agreement and the incurrence of debt and equity securities to finance any future growth capital expenditures or acquisitions. The upward trend in interest rates experienced recently will increase our borrowing costs on additional debt financing incurred to finance future acquisitions, as compared to our borrowing costs under our currently hedged credit facility.

Amended and Restated Credit Agreement

On August 31, 2006, we entered into an Amended and Restated Credit Agreement which provided for $300.0 million aggregate principal amount of Series B Term Loans and up to $200.0 million aggregate principal amount of revolving commitments. On May 4, 2007, Eagle Rock Energy expanded its revolver commitment level under its Amended and Restated Credit Agreement by $100.0 million to $300.0 million. No incremental funding under the Amended and Restated Credit Agreement was needed for the Laser and Montierra acquisitions. The Amended and Restated Credit Agreement includes a sub limit for the issuance of standby letters of credit for the

aggregate unused amount of the revolver. At June 30, 2007, we had $299.3 million outstanding under the term loan, $122.9 million outstanding under the revolver and $6.9 million of outstanding letters of credit.

At our election, the term loan and the revolver bear interest on the unpaid principal amount either at a base rate plus the applicable margin (defined as 1.25% per annum, reducing to 1.00% when consolidated funded debt to Adjusted EBITDA (as defined) is less than 3.5 to 1); or at the adjusted Eurodollar rate plus the applicable margin (defined as 2.25% per annum, reducing to 2.00% when consolidated funded debt to Adjusted EBITDA (as defined) is less than 3.5 to 1). At August 31, 2006, we elected the Eurodollar rate plus the applicable margin (defined as 2.25%) for a cumulative rate of 7.65%. The applicable margin increased by 0.50% per annum on January 31, 2007, a result of the Partnership not pursuing a rating by both S&P and Moody’s, per the agreement.

Base rate interest loans are paid the last day of each March, June, September and December. Eurodollar rate loans are paid the last day of each interest period, representing one-, two-, three- or six-, nine- or twelve-months, as selected by us. Interest on the term loans is paid each March 31, June 30, September 30 and December 31 of each year, commencing on September 30, 2006. We pay a commitment fee equal to (1) the average of the daily difference between (a) the revolver commitments and (b) the sum of the aggregate principal amount of all outstanding revolver loans plus the aggregate principal amount of all outstanding swing loans times (2) 0.50% per annum; provided, the commitment fee percentage shall increase by 0.25% per annum on January 31, 2007. We also pay a letter of credit fee equal to (1) the applicable margin for revolving loans that are Eurodollar rate loans times (2) the average aggregate daily maximum amount available to be drawn under all such letters of credit (regardless of whether any conditions for drawing could then be met and determined as of the close of business on any date of determination). Additionally, we pay a fronting fee equal to 0.125%, per annum, times the average aggregate daily maximum amount available to be drawn under all letters of credit.

The obligations under the Amended and Restated Credit Agreement are secured by first priority liens on substantially all of our assets, including a pledge of all of the capital stock of each of our subsidiaries. In addition, the credit facility contains various covenants limiting our ability to incur indebtedness, grant liens and make distributions and certain financial covenants requiring us to maintain:

•

an interest coverage ratio (the ratio of our consolidated Adjusted EBITDA to our consolidated interest expense, in each case as defined in the credit agreement) of not less than 2.5 to 1.0, determined as of the last day of each quarter for the four quarter period ending on the date of determination; and a leverage ratio (the ratio of our consolidated indebtedness to our consolidated Adjusted EBITDA, in each case as defined in the credit agreement) of not more than 5.0 to 1.0 (or, on a temporary basis for not more than three consecutive quarters following the consummation of certain acquisitions, not more than 5.25 to 1.0).

We will use the available borrowing capacity under our Amended and Restated Credit Agreement for working capital purposes, maintenance and growth capital expenditures and future acquisitions. The Partnership has approximately $171.0 million of unused capacity under the agreement as of June 30, 2007.

Off-Balance Sheet Obligations. We have no off-balance sheet transactions or obligations.

Debt Covenants. At June 30, 2007 and December 31, 2006, we were in compliance with the covenants of the credit facilities.

Total Contractual Cash Obligations. The following table summarizes our total contractual cash obligations as of December 31, 2006 and June 30, 2007. All of the $405.7 million of term loans outstanding on December 31, 2006 are scheduled for interest rate resets on three-month intervals. Interest rates were last reset for all amounts outstanding on June 30, 2007.


($ in millions)	Payments Due by Period
Contractual Obligations	Total		2007		2008		2009		2010-2011		Thereafter
Long-term debt (including interest)(1)	$	561.6	$	16.1	$	32.9	$	32.9	$	479.7	$	0.0
Operating leases		4.4		0.7		0.7		0.7		0.3		2.0
Purchase obligations(2)		—		—		—		—		—		—

Total contractual obligations	$	566.0	$	16.8	$	33.6	$	33.6	$	480.0	$	2.0


(1)		Assumes our fixed swapped average interest rate of 4.92% plus the applicable margin under our Amended and Restated Credit Agreement, which remains constant in all periods.

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

Recent Accounting Pronouncements

In February 2006, the Financial Accounting Standards Board, or the FASB issued SFAS No. 155,Accounting for Certain Hybrid Financial Instruments, an amendment of FASB Statements No. 133 and No. 140 (SFAS No. 155). SFAS No. 155 amends SFAS No. 133, which required a derivative embedded in a host contract which does not meet the definition of a derivative be accounted for separately under certain conditions. SFAS No. 155 amends SFAS No. 133 to narrow the scope of such exception to strips which represent rights to receive only a portion of the contractual interest cash flows or of the contractual principal cash flows of a specific debt instrument. In addition, SFAS No. 155 amends SFAS No. 140,Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities, which permitted a qualifying special-purpose entity to hold only a passive derivative financial instrument pertaining to beneficial interests issued or sold to parties other than the transferor. SFAS No. 155 amends SFAS No. 140 to allow a qualifying special purpose entity to hold a derivative instrument pertaining to beneficial interests that itself is a derivative financial instrument. SFAS No. 155 is effective for all financial instruments acquired or issued (or subject to a re-measurement event) following the start of an entity’s first fiscal year beginning after September 15, 2006. The Partnership adopted SFAS No. 155 on January 1, 2007, and it had no effect on the results of operations or financial position for the quarter ended June 30, 2007.

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. The Company is currently evaluating the effect the adoption of this statement will have, if any, on its consolidated results of operations and financial position.

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 is effective for us as of January 1, 2008 and will have no impact on amounts presented for periods prior to the effective date. We cannot currently estimate the impact of SFAS No. 159 on our consolidated results of operations, cash flows or financial position and have not yet determined whether or not we will choose to measure items subject to SFAS No. 159 at fair value.

In July 2006, the FASB, issued FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109(FIN 48), which clarifies the accounting and disclosure for uncertainty in tax positions, as defined. FIN 48 seeks to reduce the diversity in practice associated with certain aspects of the recognition and measurement related to accounting for income taxes. This interpretation is effective for fiscal years beginning after December 15, 2006. The adoption of FIN 48 did not have a material impact on our results of operations or financial position.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Risk and Accounting Policies

We are exposed to market risks associated with commodity prices, counterparty credit and interest rates. Our management has established a comprehensive review of our market risks and is developing risk management policies and procedures to monitor and manage these market risks. Our general partner is responsible for delegation of transaction authority levels, and has established a Risk Management Committee. Our general partner will be responsible for the overall approval of market risk management policies. The Risk Management Committee is composed of senior management members of our general partner (including 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 credit risk and commodity

price risk, including monitoring exposure limits. The Risk Management Committee reports quarterly to the Board of Directors of the general partner on positions and exposures, credit exposures and overall risk management in the context of market activities.

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 and marketing activities. These activities produce a naturally long position in NGLs and crude oil, and a natural short position in natural gas. We attempt to mitigate commodity price risk exposure by matching pricing terms between our purchases and sales of commodities; to the extent that we market commodities in which pricing terms cannot be matched and there is a substantial risk of price exposure, we attempt to use financial derivative instruments (“hedges”) to mitigate the risk. These hedges are only intended to mitigate the risk associated with our natural physical position; our risk management policy prohibits entering into speculative derivative positions. See Note 10, Risk Management Activities, for additional discussion of our hedging activities.

Both our profitability and our cash flow are affected by volatility in prevailing crude oil, natural gas and NGL prices. These prices are impacted by changes in the supply and demand for these commodities, as well as market uncertainty and other factors. Historically, changes in the prices of heavy NGLs, such as natural gasoline, have generally correlated with changes in the price of crude oil. For a discussion of the volatility of crude oil, natural gas and NGL prices, please read “Risk Factors.”

Adverse effects on our cash flow from changes in crude oil, natural gas and NGL product prices could adversely affect our ability to make distributions to unitholders. We manage this commodity price exposure through an integrated strategy that includes management of our contract portfolio, matching sales prices of commodities with purchases, optimization of our portfolio by monitoring basis and other price differentials in our areas of operations, and the use of derivative contracts. Crude oil natural gas and NGL prices can also affect our profitability indirectly by influencing the level of drilling activity and related opportunities for our service.

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.

There have been no significant changes in our market risk from what was disclosed in our Annual Report filed on Form 10-K for the year ended December 31, 2006.

Item 4. Controls and Procedures.

At the end of the period covered by this report, an evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of the general partner of our general partner, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rule 13a—15(e) and 15d—15(e) of the Exchange Act of 1934, as amended). Based on that evaluation, management, including the Chief Executive Officer and Chief Financial Officer of the general partner of our general partner, concluded our disclosure controls and procedures were effective as of June 30, 2007 to provide reasonable assurance that the information required to be disclosed by us in the reports we file or submit under the Exchange Act of 1934, as amended, is properly recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms.

Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

We and our subsidiaries may become party to legal proceedings which arise from time to time in the ordinary course of business. While the outcome of these proceedings cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on the financial statements.

We carry insurance with coverage and coverage limits consistent with our assessment of risks in our business and of an acceptable level of financial exposure. Although there can be no assurance such insurance will be sufficient to mitigate all damages, claims or contingencies, we believe our insurance provides reasonable coverage for known asserted or unasserted claims. In the event we sustain a loss from a claim and the insurance carrier disputed coverage or coverage limits, we may record a charge in a different period than the recovery, if any, from the insurance carrier.

Item 1A. Risk Factors.

Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses.

If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units and the trading price of our common units could decline.

The following risks should be read in conjunction with other risk factors disclosed under Item 1A. Risk Factors in our Annual Report onForm 10-K for the year ended December 31, 2006. The following risks are included in this report because of our recently completed Montierra Acquisition, described in Note 4 to our Unaudited Consolidated Financial Statements included with this report and the Redman Acquisition and EAC Acquisition, described in Note 15 to our Unaudited Consolidated Financial Statements included with this report.

Risks Related to Our Business

Because of the natural decline in production from existing wells, our success depends on our ability to obtain new sources of production and supplies of oil, natural gas and NGLs, which are dependent on certain factors beyond our control. Our success is also dependent on developing current reserves. Any decrease in production or supplies of oil, natural gas or NGLs could adversely affect our business and operating results.

Our gathering and transportation pipeline systems are connected to or dependent on the level of production from natural gas wells, from which production will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our gathering and transportation pipeline systems and NGL pipelines and the asset utilization rates at our natural gas processing plants, we must continually obtain new supplies of natural gas. The primary factors affecting our ability to obtain new supplies of natural gas and NGLs and attract new customers to our assets include: (1) the level of successful drilling activity by producers near our systems and (2) our ability to compete for volumes from successful new wells.

The level of drilling activity is dependent on economic and business factors beyond our control. The primary factor that impacts drilling decisions is natural gas prices. Currently, natural gas prices are high in relation to historical prices. For example, the rolling twelve-month average NYMEX daily settlement price of natural gas has increased from $5.49 per MMBtu as of December 31, 2003 to $7.23 per MMBtu as of December 31, 2006. If the high price for natural gas were to decline, the level of drilling activity could decrease. A sustained decline in natural gas prices could result in a decrease in exploration and development activities in our fields and the fields served by our gathering and pipeline transportation systems and our natural gas treating and processing plants, which would lead to reduced utilization of these assets. Other factors that impact production decisions include producers’ capital budgets, the ability of producers to obtain necessary drilling and other governmental permits and regulatory changes. Because of these factors, even if new natural gas reserves are discovered in areas served by our assets, we and other producers may choose not to develop those reserves. If we are not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells due to reductions in drilling activity or competition, throughput on our pipelines and the utilization rates of our treating and processing facilities would decline, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions.

Now that we have entered the exploration and production business in addition to our midstream business, we have additional risks inherent with declining reserves. Producing reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our decline rate may change when additional wells are drilled, make acquisitions and under other circumstances. Our future cash flows and income and our ability to maintain and to increase distributions to unitholders are partly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations. Factors that may hinder our ability to acquire additional reserves or develop current reserves include competition, access to capital,

prevailing oil and natural gas prices, the costs incurred by the operators to develop and exploit current and future oil and natural gas reserves and the number and attractiveness of properties for sale.

Natural gas, NGLs, Crude Oil and other commodity prices are volatile, and a reduction in these prices could adversely affect our cash flow and our ability to make distributions.

We are subject to risks due to frequent and often substantial fluctuations in commodity prices. NGL prices generally fluctuate on a basis that correlates to fluctuations in crude oil prices. In the past, the prices of natural gas and crude oil have been extremely volatile, and we expect this volatility to continue. A drop in prices can significantly affect our financial results and impede our growth, including our ability to maintain or increase our borrowing capacity, to repay current or future indebtedness and to obtain additional capital on attractive terms, all of which can affect our ability to pay distributions. Changes in crude oil and natural gas prices have a significant impact on the value of our reserves and on our cash flows. The NYMEX daily settlement price for natural gas for the prompt month contract in 2006 ranged from a high of $9.87 per MMBtu to a low of $3.63 per MMBtu. The NYMEX daily settlement price for crude oil for the prompt month contract in 2006 ranged from a high of $77.03 per barrel to a low of $55.81 per barrel. The markets and prices for natural gas and NGLs depend upon factors beyond our control. These factors include demand for oil, natural gas and NGLs, which fluctuate with changes in market and economic conditions and other factors, including:

	•		the impact of weather or force majeure events on the demand for oil and natural gas;

	•		the level of domestic oil and natural gas production and demand;

	•		the level of imported oil and natural gas availability and demand;

	•		the level of consumer product demand;

	•		political and economic conditions and events in, as well as actions taken by foreign oil and natural gas producing nations;

	•		overall domestic and global economic conditions;

	•		the availability of local, intrastate and interstate transportation systems including natural gas pipelines and other transportation facilities to our production;

	•		the availability and marketing of competitive fuels;

	•		delays or cancellations of crude oil and natural gas drilling and production activities;

	•		the impact of energy conservation efforts, including technological advances affecting energy consumption; and

	•		the extent of governmental regulation and taxation.

Lower oil or natural gas prices may not only decrease our revenues and net proceeds, but also reduce the amount of oil or natural gas that we can economically produce. As a result, the operator of any of the properties could determine during periods of low commodity prices to shut in or curtail production, or to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management’s plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken and our ability to borrow funds under our credit facility, which may adversely affect our ability to make cash distributions to our unitholders.

Our natural gas gathering and processing businesses operate under two types of contractual arrangements that expose our cash flows to increases and decreases in the price of natural gas and NGLs: percentage-of-proceeds and keep-whole arrangements. Under percentage-of-proceeds arrangements, we generally purchase natural gas from producers and retain an agreed percentage of the proceeds (in cash or in-kind) from the sale at market prices of pipeline-quality gas and NGLs or NGL products resulting from our processing activities. Under keep-whole arrangements, we receive the NGLs removed from the natural gas during our processing operations as the fee for providing our services in exchange for replacing the thermal content removed as NGLs with a like thermal content in pipeline-quality gas or its cash equivalent. Under these types of arrangements our revenues and our cash flows increase or decrease as the prices of natural gas and NGLs fluctuate. The relationship between natural gas prices and NGL prices may also affect our profitability. When natural gas prices are low relative to NGL prices, under keep-whole arrangements it is more profitable for us to process natural gas. When natural gas prices are high relative to NGL prices, it is less profitable for us and our customers to process natural gas both because of the higher value of natural gas and of the increased cost (principally that of natural gas as a feedstock and a fuel) of separating the mixed NGLs from the natural gas. As a result, we may experience periods in which higher natural gas prices relative to NGL prices reduce our processing margins or reduce the volume of natural gas processed at some of our plants. For a detailed discussion of these arrangements, please read Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Operations in our annual report on Form 10-K for the year ended December 31, 2006.

Our hedging activities may have a material adverse effect on our earnings, profitability, cash flows and financial condition.

We are exposed to risks associated with fluctuations in commodity prices. The extent of our commodity price risk is related largely to the effectiveness and scope of our hedging activities. In order to reduce our exposure to commodity price risk, we directly hedged substantially all of our share of expected NGL volumes in 2006 and 2007 under percent-of-proceed and keep-whole contracts. This has been accomplished primarily through the purchase of NGL put contracts but also through executing NGL costless collar contracts and swap contracts. We have also hedged substantially all of our share of expected NGL volumes from 2008 through 2010 under percent-of-proceed contracts through a combination of direct NGL hedging as well as indirect hedging through crude oil costless collars. Additionally, to mitigate the exposure to natural gas prices from keep-whole volumes, we have purchased natural gas calls from 2006 to 2007 to cover our short natural gas position. Finally, we have entered into hedging arrangements for a significant portion of our oil and natural gas production. Our management will evaluate whether to enter into any new hedging arrangements, but there can be no assurance that we will enter into any new hedging arrangement or that our future hedging arrangements will be on terms similar to our existing hedging arrangements.

To the extent we hedge our commodity price and interest rate risk, we may forego the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor. Furthermore, because we have entered into derivative transactions related to only a portion of the volume of our expected oil and natural gas production, natural gas supply and production of NGLs and condensate from our processing plants, we will continue to have direct commodity price risk to the unhedged portion. Our actual future supply and production may be significantly higher or lower than we estimate at the time we entered into the derivative transactions for that period. If the actual amount is higher than we estimate, we will have less commodity price risk than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the underlying physical commodity, resulting in a reduction of our liquidity.

As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, even though our management monitors our hedging activities, these activities can result in substantial losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the applicable hedging arrangement, the hedging arrangement is imperfect or ineffective, or our hedging policies and procedures are not properly followed or do not work as planned. The steps we take to monitor our hedging activities may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.

As a result of our hedging activities and our practice of marking to market the value of our hedging instruments, we will also experience significant variations in our unrealized derivative gains/(losses) from period to period. These variations from period to period will follow variations in the underlying commodity prices and interest rates. As this item is of a non-cash nature, it will not impact our cash flows or our ability to make our distributions. However, it will impact our earnings and other profitability measures. To illustrate, during the twelve months ended December 31, 2006, we experienced positive movements in our underlying commodities’ prices which led to an unrealized derivative loss of $26.3 million. This $26.3 million loss had a direct impact on our net income (loss) line resulting in a net loss of $23.1 million. For additional information regarding our hedging activities, please read Item 7A. Quantitative and Qualitative Disclosures about Market Risk in our annual report on Form 10-K for the year ended December 31, 2006.

Our estimated oil and natural gas reserve quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.

Numerous uncertainties are inherent in estimating quantities of oil and natural gas reserves. Our estimates of our net proved reserve quantities are based upon reports of petroleum engineers. The process of estimating oil and natural gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir, and these reports rely upon various assumptions, including assumptions regarding future oil and natural gas prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling and production. Any significant variance in our assumptions by actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. In addition, our wells are characterized by low production rates per well. As a result, changes in future production costs assumptions could have a significant effect on our proved reserve quantities.

The standardized measure of discounted future net cash flows of our estimated net proved reserves is not necessarily the same as the current market value of our estimated net proved reserves. We base the discounted future net cash flows from our estimated net proved reserves on prices and costs in effect on the day of the estimate. Actual prices received for production and actual costs of such production will be different than these assumptions, perhaps materially.

The timing of both our production and our incurrence of expenses in connection with the development and production of our properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. Any material inaccuracy in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves which could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

Furthermore, due to the nature of ownership of royalties, overriding royalties and fee minerals, we will not usually be able to control the timing of drilling by the operators who have taken an oil and gas lease on our lands. This leads to uncertainty in the timing of future reserve additions and production increases resulting from new drilling across our assets. Any material inaccuracy in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves which could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

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

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the maintenance, construction and acquisition of midstream assets and oil and natural gas reserves. We intend to finance our future capital expenditures with cash flows from operations, borrowings under

our credit facility and the issuance of debt and equity securities. The incurrence of debt will require that a portion of our cash flows from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. Our cash flows from operations and access to capital are subject to a number of variables, including:

	•		volume throughput through our pipelines and processing facilities;

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

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

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

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

If our revenues or the borrowing base under our credit facility decrease as a result of lower commodity prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. Our credit facility may restrict our ability to obtain new financing. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our capital projects, which in turn could lead to a possible decline in our gathering and processing available capacity or in our natural gas and crude oil reserves and production, which could adversely effect our business, results of operation, financial conditions and ability to make distributions to our unitholders. In addition, we may lose opportunities to acquire oil and natural gas properties and businesses.

We typically do not obtain independent evaluations of other producer’s natural gas reserves dedicated to our gathering and pipeline systems; therefore, volumes of natural gas on our systems in the future could be less than we anticipate.

We typically do not obtain independent evaluations of other producer’s natural gas reserves connected to our systems due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, we do not have independent estimates of total reserves dedicated to our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering systems is less than we anticipate and we are unable to secure additional sources of natural gas, then the volumes of natural gas on our systems in the future could be less than we anticipate. A decline in the volumes of natural gas on our systems could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions.

The loss of any of our significant customers could result in a decline in our volumes, revenues and cash available for distribution.

Midstream. We rely on certain natural gas producer customers for a significant portion of our natural gas and NGL supply. The make-up of gas suppliers can change from time to time based upon a number of reasons, some of which are success of the producer’s drilling programs, additions or cancellations of new agreements and acquisition of new systems. As of December 31, 2006, our two largest suppliers were affiliates of Chesapeake Energy Corporation and Prize Operating Company, accounting for approximately 12% and 10% respectively, of our natural gas supply. We may be unable to negotiate long-term contracts or extensions or replacements of existing contracts, on favorable terms, if at all. The loss of all or even a portion of the natural gas volumes supplied by these customers, as a result of competition or otherwise, could have a material adverse effect on our business, results of operations and financial condition, unless we were able to acquire comparable volumes from other sources.

Upstream. To the extent any significant customer reduces the volume of its oil or natural gas purchases from us, we could experience a temporary interruption in sales of, or a lower price for, our oil and natural gas production and our revenues and cash available for distribution could decline which could adversely affect our ability to make cash distributions to our unitholders.

We may not successfully balance our purchases and sales of natural gas, which would increase our exposure to commodity price risks.

We purchase from producers and other customers a substantial amount of the natural gas that flows through our natural gas gathering, processing and transportation systems for resale to third parties, including natural gas marketers and end-users. We may not be successful in balancing our purchases and sales. A producer or supplier could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause our purchases and sales to be unbalanced. If our purchases and sales are unbalanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income and cash flows.

If third-party pipelines and other facilities interconnected to our systems become unavailable to transport or produce natural gas and NGLs, our revenues and cash available for distribution could be adversely affected.

We depend upon third-party pipelines, natural gas gathering systems and other facilities that provide delivery options to and from our pipelines and facilities for the benefit of our customers. Since we do not own or operate any of these pipelines or other facilities, their continuing operation is not within our control. If any of these third-party pipelines and other facilities become unavailable or limited in their ability to transport or produce natural gas and NGLs, our revenues and cash available for distribution could be adversely affected.

Our access to transportation options may affect our revenues and cash available for distribution.

Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. These factors and the availability of markets are beyond our control. If market factors dramatically change, the impact on our revenues could be substantial and could adversely affect our ability to produce and market oil and natural gas, the value of our units and our ability to pay distributions on our units.

Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.

We compete with similar enterprises in our respective areas of operation. Some of our competitors are large oil and natural gas companies that have greater financial resources and access to supplies of natural gas and NGLs than we do.

Midstream. Some of these competitors may expand or construct gathering, processing and transportation systems that would create additional competition for the services we provide to our customers. In addition, our customers who are significant producers of natural gas may develop their own gathering, processing and transportation systems in lieu of using ours. Likewise, our customers who produce NGLs may develop their own processing facilities in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions.

Upstream. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil and natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, these companies may have a greater ability to continue drilling activities during periods of low oil and natural gas prices, to contract for drilling equipment, to secure trained personnel and to absorb the burden of present and future federal, state, local and other laws and regulations. The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases.

In both the midstream and upstream businesses, competition has been strong in hiring experienced personnel, particularly in the engineering, accounting and financial reporting, tax and land departments. In addition, competition is strong for attractive midstream assets as well as oil and natural gas producing properties, oil and natural gas companies and undeveloped leases and drilling rights. We may be often outbid by competitors in our attempts to acquire assets, properties or companies. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Our natural gas gathering and intrastate transportation operations are generally exempt from Federal Energy Regulatory Commission, or FERC, regulation under the Natural Gas Act of 1938, or NGA, except for Section 311 as discussed below, but FERC regulation still affects these businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its oil and natural gas regulatory activities, including, for example, its policies on open access transportation, ratemaking, capacity release and market center promotion, indirectly affect intrastate markets. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However, FERC may not continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to oil and natural gas transportation capacity. In addition, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of regular litigation, so, in such a circumstance, the classification and regulation of some of our gathering facilities and intrastate transportation pipelines may be subject to change based on future determinations by FERC and the courts.

Other state and local regulations also affect our business. Common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or transport oil or natural gas. Federal law leaves any economic regulation of natural gas gathering to the states. The states in which we operate have adopted complaint-based regulation of oil and natural gas gathering activities, which allows oil and natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to oil and natural gas gathering access and rate discrimination. Other state regulations may not directly regulate our business, but may nonetheless affect the availability of natural gas for purchase, processing and sale, including state regulation of production rates and maximum daily production allowable from gas wells. While our proprietary gathering lines currently are subject to limited state regulation, there is a risk that state laws will be changed, which may give producers a stronger basis to challenge proprietary status of a line, or the rates, terms and conditions of a gathering line providing transportation service. Please read Item 1. Business — Regulation of Operations in our annual report on Form 10-K for the year ended December 31, 2006, and “Business — Regulation of Operations” in this prospectus.

We are subject to compliance with stringent environmental laws and regulations that may expose us to significant costs and liabilities.

Our operations are subject to stringent and complex federal, state and local environmental laws and regulations governing the discharge of materials into the environment or otherwise to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to limit or prevent releases of materials from our pipelines and facilities and the imposition of substantial liabilities for pollution resulting from our operations. Failure or delay in obtaining regulatory approvals or drilling permits by us or our operators could have a material adverse effect on our ability to develop our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs. In addition, regulations regarding conservation practices and the protection or correlative rights affect our operations by limiting the quantity of oil and natural gas that may be produced and sold.

Numerous governmental authorities, such as the U.S. Environmental Protection Agency, also known as the “EPA,” and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, assessment of monetary penalties and the issuance of injunctions limiting or preventing some or all of our operations.

These costs and liabilities could arise under a wide range of federal, state and local environmental laws and regulations, including, for example:

	•		the federal Clean Air Act and comparable state laws and regulations that impose obligations related to air emissions;


	•		the federal Clean Water Act and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated bodies of water;


	•		the federal Resource Conservation and Recovery Act, or RCRA, and comparable state laws that impose requirements for the handling and disposal of waste from our facilities; and


	•		the Comprehensive Environmental Response, Compensation and Liability Act of 1980, or CERCLA, also known as “Superfund,” and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which we have sent waste for disposal.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including the RCRA, CERCLA, the federal Oil Pollution Act and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

There is inherent risk of incurring significant environmental costs and liabilities in connection with our operations due to our handling of petroleum hydrocarbons and wastes, operation of our wells, gathering systems and other facilities, air emissions and water discharges related to our operations and historical industry operations and waste disposal practices. Joint and several, strict liability may be incurred under these environmental laws and regulations in connection with discharges or releases of petroleum hydrocarbons and wastes on, under or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of properties through which our gathering systems pass and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations or financial position. We may not be able to recover some or any of these costs from insurance. See Item 1. Business — Environmental Matters in our annual report on Form 10-K for the year ended December 31, 2006, and “Business – Environmental Matters” in this prospectus.

Our construction of new assets may not result in revenue increases and is subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.

One of the ways we intend to grow our business is through the construction of new midstream assets. The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. If we undertake these projects, they may not be completed on schedule or at the budgeted cost, or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand a pipeline, the construction may occur over an extended period of time, and we will not receive any material increases in revenues until the project is completed. Moreover, we may construct facilities to capture anticipated future growth in production in a region in which such growth does not

materialize. We often do not have access to third-party estimates of potential reserves in an area prior to constructing facilities in such area. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. In addition, the construction of additions to our existing gathering and transportation assets may require us to obtain new rights-of-way prior to constructing new pipelines. We may be unable to obtain such rights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.

If we do not make acquisitions on economically acceptable terms, our future growth will be limited.

Our ability to grow our business depends, in part, on our ability to make acquisitions that result in an increase in the cash generated from operations per unit. If we are unable to make these accretive acquisitions either because we are: (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms, or (3) outbid by competitors, then our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations per unit because of unforeseen circumstances.

In our upstream business in particular, properties that we buy may not produce as projected and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities, which could adversely affect our cash available for distribution. One of our growth strategies is to capitalize on opportunistic acquisitions of oil and natural gas reserves. Any future acquisition will require an assessment of recoverable reserves, title, future oil and natural gas prices, operating costs, potential environmental hazards, potential tax and ERISA liabilities and other liabilities and similar factors. Ordinarily, our review efforts are focused on the higher valued properties and are inherently incomplete because it generally is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and potential problems, such as ground water contamination and other environmental conditions and deficiencies in the mechanical integrity of equipment are not necessarily observable even when an inspection is undertaken. Any unidentified problems could result in material liabilities and costs that negatively impact our financial conditions and results of operations and our ability to make cash distributions to our unitholders.

Any acquisition, midstream or upstream, involves potential risks, including, among other things:

	•		mistaken assumptions about future prices, volumes, revenues and costs of oil and natural gas, including synergies and estimates of the oil and natural gas reserves attributable to a property we acquire;

	•		an inability to integrate successfully the businesses we acquire;

	•		inadequate expertise for new geographic areas, operations or products and services;

	•		the assumption of unknown liabilities;

	•		limitations on rights to indemnity from the seller;

	•		mistaken assumptions about the overall costs of equity or debt;

	•		the diversion of management’s and employees’ attention from other business concerns;

	•		unforeseen difficulties operating in new product areas or new geographic areas;

	•		customer or key employee losses at the acquired businesses; and

•

establishment of internal controls and procedures that we are required to maintain under the Sarbanes-Oxley Act of 2002.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and the limited partners will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

Our ability to derive benefits from our acquisitions will depend on our ability to integrate operations to achieve the benefits of the acquisitions.

Achieving the anticipated benefits from acquisitions depends in part upon whether we are able to integrate the assets or businesses of these acquisitions, in an efficient and effective manner. We may not be able to accomplish the integration process smoothly or successfully. The difficulties combining businesses or assets potentially will include, among other things:

	•		geographically separated organizations and possible differences in corporate cultures and management philosophies;

	•		significant demands on management resources, which may distract management’s attention from day-to-day business;

	•		differences in the disclosure systems, accounting systems, and accounting controls and procedures of the two companies, which may interfere with our ability to make timely and accurate public disclosure; and

	•		the demands of managing new lines of business acquired.

Any inability to realize the potential benefits of the acquisition, as well as any delays in integration, could have an adverse effect upon the revenues, level of expenses and operating results of the company, after the acquisitions, which may affect the value of our common units after the acquisition.

We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.

We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights of way or if such rights of way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs that is not fully insured or interrupts normal operations, our operations and financial results could be adversely affected.

Our operations are subject to many hazards inherent in the drilling, producing, gathering, compressing, treating, processing and transporting of oil, natural gas and NGLs, including:

	•		damage to production equipment, pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism;

	•		inadvertent damage from construction, farm and utility equipment;

	•		leaks of natural gas, NGLs and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of pipeline, equipment or facilities;

	•		fires and explosions; and

•

other hazards that could also result in personal injury and loss of life, pollution and suspension of operations, such as the uncontrollable flow of oil or natural gas or well fluids.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and attorney’s fees and other expenses incurred in the prosecution or defense of litigation and may result in curtailment or suspension of our related operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations and ability to pay distributions to our unitholders.

As is customary in the industry, we maintain insurance against some but not all of these risks. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. We are not fully insured against all risks inherent to our business. For example, we do not have any property insurance on any of our underground pipeline systems that would cover damage to the pipelines. We are not insured against all environmental accidents that might occur which may include toxic tort claims, other than those considered to be sudden and accidental. If a significant accident or event occurs that is not fully insured, it could adversely affect our operations and financial condition. In addition, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially, and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to our indemnification rights, for potential environmental liabilities. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition, results of operations and ability to pay distributions to our unitholders.

Our current debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities. In addition, we may incur substantial debt in the future to enable us to maintain or increase our reserve and production levels and to otherwise pursue our business plan. This debt may restrict our ability to make distributions.

In December 2005, we entered into up to a $475.0 million senior secured credit facility, consisting of up to a $400.0 million term loan facility and up to a $75.0 million revolving credit facility for our acquisition of the ONEOK Texas natural gas gathering and processing assets. The revolver facility was increased to $100.0 million in June 2006. On August 31, 2006, we entered into an amended and restated credit facility that provided for an aggregate of approximately $500.0 million borrowing capacity. Concurrent with the Laser and Montierra acquisitions, the revolver facility was again increased by $100 million to an aggregate of $600.0 million. Our level of debt could have important consequences to us, including the following:

	•		our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

	•		we will need a portion of our cash flow to make interest payments on our debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders;

	•		our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

	•		our debt level may limit our flexibility in responding to changing business and economic conditions.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. In addition, our ability to service debt under our amended and restated credit facility will depend on market interest rates, since we anticipate that the interest rates applicable to our borrowings will fluctuate with movements in interest rate markets. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or

refinancing our debt, or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms, or at all.

Our upstream business requires a significant amount of capital expenditures to maintain and grow production levels. If prices were to decline for an extended period of time, if the costs of our acquisition and drilling and development operations were to increase substantially, or if other events were to occur which reduced our revenues or increased our costs, we may be required to borrow significant amounts in the future to enable us to finance the expenditures necessary to replace the reserves we produce. The cost of the borrowings and our obligations to repay the borrowings will reduce amounts otherwise available for distributions to our unitholders.

Shortages of drilling rigs, equipment and crews could delay our operations and reduce our cash available for distribution.

Higher oil and natural gas prices generally increase the demand for drilling rigs, equipment and crews and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Shortages of, or increasing costs for, experienced drilling crews and oil field equipment and services could restrict our and other operators’ ability to drill the wells and conduct the operations currently planned. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues and cash available for distribution.

Our and other operators’ drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors.

Our and other operators’ drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors, including:

	•		unexpected drilling conditions;

	•		drilling, production or transportation facility or equipment failure or accidents;

	•		shortages or delays in the availability of drilling rigs and other services and equipment;

	•		adverse weather conditions;

	•		compliance with environmental and governmental requirements;

	•		title problems;

	•		unusual or unexpected geological formations;

	•		pipeline ruptures;

	•		fires, blowouts, craterings and explosions; and

	•		uncontrollable flows of oil or natural gas or well fluids.

Any curtailment to the gathering systems used by operators could also require such operators to find alternative means to transport the oil and natural gas production from the underlying properties, which alternative means could require such operators to incur additional costs. We do not provide midstream services to all of our upstream activities.

Any such curtailment, delay or cancellation may limit our ability to make cash distributions to our unitholders.

Restrictions in our amended and restated credit facility limit our ability to make distributions and limit our ability to capitalize on acquisitions and other business opportunities.

Our amended and restated credit facility contains covenants limiting our ability to make distributions, incur indebtedness, grant liens, make acquisitions, investments or dispositions and engage in transactions with affiliates.

Furthermore, our amended and restated credit facility contains covenants requiring us to maintain certain financial ratios and tests. Any subsequent replacement of our credit facility or any new indebtedness could have similar or greater restrictions.

Increases in interest rates, which have recently experienced record lows, could adversely impact our unit price and our ability to issue additional equity, to incur debt to make acquisitions or for other purposes or to make cash distributions at our intended levels.

The credit markets recently have experienced record lows in interest rates over the past several years. As the overall economy strengthens, it is likely that monetary policy will continue to tighten further, resulting in higher interest rates to counter possible inflation. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity, to incur debt to make acquisitions or for other purposes or to make cash distributions at our intended levels.

Due to our lack of industry and geographic diversification in our midstream operations, adverse developments in our operations or operating areas would reduce our ability to make distributions to our unitholders.

We rely on the revenues generated from our midstream and upstream energy businesses, and as a result, our financial condition depends upon prices of, and continued demand for, natural gas, NGLs and condensate. While our upstream properties are well diversified geographically, all of our midstream assets are located in the Texas Panhandle, southeast and south Texas and Louisiana. Due to our lack of diversification in industry type and location, an adverse development in one of these businesses or operating areas would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.

We are exposed to the credit risks of our key producer customers, and any material nonpayment or nonperformance by our key producer customers could reduce our ability to make distributions to our unitholders.

We are subject to risks of loss resulting from nonpayment or nonperformance by our producer customers. Any material nonpayment or nonperformance by our key producer customers could reduce our ability to make distributions to our unitholders. Furthermore, some of our producer customers may be highly leveraged and subject to their own operating and regulatory risks, which could increase the risk that they may default on their obligations to us.

Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our results of operations.

The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks on our industry in general, and on us in particular, is not known at this time. Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for refined products, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror.

Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.

If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud.

Prior to our initial public offering, which was completed on October 24, 2006, we have been a private company and have not filed reports with the SEC. We produce our consolidated financial statements in accordance with the requirements of GAAP, but our internal accounting controls may not currently meet all standards applicable to companies with publicly traded securities. Effective internal controls are necessary for us to provide reliable financial reports to prevent fraud and to operate successfully as a publicly traded partnership. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future, including compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 will require us, among other things, annually to review and report on, and our independent registered public accounting firm to attest to, our internal control over financial reporting. We must comply with Section 404 for our fiscal year ending December 31, 2007. Any failure to develop or maintain effective controls, or difficulties encountered in their implementation or other effective improvement of our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm’s, conclusions about the effectiveness of our internal controls and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

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

The information required for this item is provided in Notes 4, Acquisitions, 7, Members’ Equity, and 15, Subsequent Events, included in the Notes to the Unaudited Consolidated Financial Statements included under Part I, Item 1, which information is incorporated by reference into this item.

We did not repurchase any of our common units during the period covered by this report. However, 10,400 common units were forfeited by departing employees whose common units had not vested at the time of the termination of employment.

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 such form.

Item 6. Exhibits.

	2.1		Partnership Interests Purchase and Contribution Agreement By and Among Laser Midstream Energy II, LP, Laser Gas Company I, LLC, Laser Midstream Company, LLC, Laser Midstream Energy, LP, and Eagle Rock Energy Partners, L.P., dated as of March 30, 2007 (incorporated by reference to Exhibit 2.1 in the registrant’s registration statement on Form S-1 (No. 333-144938)).

	2.2		Partnership Interests Contribution Agreement By and Among Montierra Minerals and Production, L.P., NGP Minerals, L.L.C. and Eagle Rock Energy Partners, L.P., dated as of March 31, 2007 (incorporated by reference to Exhibit 2.2 in the registrant’s registration statement on Form S-1 (No. 333-144938)).

	2.3		Asset Contribution Agreement By and Among NGP 2004 Co-Investment Income, L.P., NGP Co-Investment Income Capital Corp., NGP-VII Income Co-Investment Opportunity, L.P., dated as

			of March 31, 2007 (incorporated by reference to Exhibit 2.3 in the registrant’s registration statement on Form S-1 (No. 333-144938)).

	4.5		Registration Rights Agreement dated May 2, 2007, among Eagle Rock Energy Partners, L.P. and the purchasers listed thereto (incorporated by reference to Exhibit 4.5 in the registrant’s registration statement on Form S-1 (No. 333-144938)).

	10.14		Common Unit Purchase Agreement By and Among Eagle Rock Energy Partners, L.P. and The Purchasers Named Herein, dated March 30, 2007 (incorporated by reference to Exhibit 10.14 in the registrant’s registration statement on Form S-1 (No. 333-144938)).

	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 and18 U.S.C. Section 1350

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.

November 1, 2007


		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

		/s/ Alfredo Garcia

		Chief Financial Officer and Senior Vice
		President, Corporate Development
		(Duly Authorized and Principal Financial Officer)

EAGLE ROCK ENERGY PARTNERS, L.P.

EXHIBIT INDEX


2.1		Partnership Interests Purchase and Contribution Agreement By and Among Laser Midstream Energy II, LP, Laser Gas Company I, LLC, Laser Midstream Company, LLC, Laser Midstream Energy, LP, and Eagle Rock Energy Partners, L.P., dated as of March 30, 2007 (incorporated by reference to Exhibit 2.1 in the registrant’s registration statement on Form S-1 (No. 333-144938)).

2.2		Partnership Interests Contribution Agreement By and Among Montierra Minerals and Production, L.P., NGP Minerals, L.L.C. and Eagle Rock Energy Partners, L.P., dated as of March 31, 2007 (incorporated by reference to Exhibit 2.2 in the registrant’s registration statement on Form S-1 (No. 333-144938)).

2.3		Asset Contribution Agreement By and Among NGP 2004 Co-Investment Income, L.P., NGP Co-Investment Income Capital Corp., NGP-VII Income Co-Investment Opportunity, L.P., dated as of March 31, 2007 (incorporated by reference to Exhibit 2.3 in the registrant’s registration statement on Form S-1 (No. 333-144938)).

4.5		Registration Rights Agreement dated May 2, 2007, among Eagle Rock Energy Partners, L.P. and the purchasers listed thereto (incorporated by reference to Exhibit 4.5 in the registrant’s registration statement on Form S-1 (No. 333-144938)).

10.14		Common Unit Purchase Agreement By and Among Eagle Rock Energy Partners, L.P. and The Purchasers Named Herein, dated March 30, 2007 (incorporated by reference to Exhibit 10.14 in the registrant’s registration statement on Form S-1 (No. 333-144938)).

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 and18 U.S.C. Section 1350

Eagle Rock Energy Partners L P (EROC) Inactive 10-Q/A2007 Q2 Quarterly report (amended)