Eagle Rock Energy Partners L P 10Q 2007 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended September 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). Yeso Noþ

The issuer had 50,699,647 common units outstanding as of November 12, 2007.

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 September 30, 2007 and December 31, 2006 (unaudited)		1
Condensed Consolidated Statements of Operations for the three months and nine months ended September 30, 2007 and 2006 (unaudited)		2
Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2007 and 2006 (unaudited)		3
Condensed Consolidated Statements of Members’ Equity for the nine months ended September 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		28
Cautionary Note Regarding Forward-Looking Statements		28
Item 3. Quantitative and Qualitative Disclosures About Market Risk		47
Item 4. Controls and Procedures		48

PART II. OTHER INFORMATION		49
Item 1. Legal Proceedings		49
Item 1A. Risk Factors		49
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		70
Item 3. Defaults Upon Senior Securities		70
Item 4. Submission of Matters to a Vote of Security Holders		70
Item 5. Other Information		70
Item 6. Exhibits		70
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)


	September 30,			December 31,
*($ in thousands)*	2007			2006
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	84,557		$	10,581
Accounts receivable		122,020			43,567
Risk management assets		30,213			13,837
Prepayments and other current assets		2,139			2,679

Total current assets		238,929			70,664

PROPERTY, PLANT AND EQUIPMENT — Net		1,249,110			554,063
INTANGIBLE ASSETS — Net		151,664			130,001
RISK MANAGEMENT ASSETS		9,252			17,373
OTHER ASSETS		13,804			7,800

TOTAL	$	1,662,759		$	779,901


LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	130,591		$	49,558
Due to affiliate		17,437			—
Accrued liabilities		20,754			7,996
Risk management liabilities		16,974			1,005

Total current liabilities		185,756			58,559

LONG-TERM DEBT		561,131			405,731
ASSET RETIREMENT OBLIGATIONS		9,045			1,819
DEFERRED TAX LIABILITY		3,045			1,229
RISK MANAGEMENT LIABILITIES		36,320			20,576
OTHER		315			—
COMMITMENTS AND CONTINGENCIES (Note 11) MEMBERS’ EQUITY (DEFICIT):
Common Unitholders(1)		716,942			116,283
Subordinated Unitholders(2)		151,749			176,248
General Partner(3)		(1,544	)		(544	)

Total members’ equity		867,147			291,987

TOTAL	$	1,662,759		$	779,901


(1)		50,633,720 common units (exclusive of restricted unvested common units) were issued and outstanding as of September 30, 2007 and 20,691,495 for December 31, 2006. These numbers do not include 527,021 units and 122,450 units issued to employees as of September 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 subordinated units were issued and outstanding as of September 30, 2007 and December 31, 2006.

(3)		844,551 general partner units were issued and outstanding as of September 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						Nine Months
	Ended September 30,						Ended September 30,
*($ in thousands except per share data)*	2007			2006			2007			2006
REVENUE:
Natural gas, natural gas liquids, condensate, and oil sales	$	253,056		$	132,907		$	554,797		$	373,001
Gathering, compression and processing fees		7,723			4,549			19,271			10,495
Minerals and royalty income		6,009			—			9,201			—
Gain/(loss) on risk management instruments		8,688			14,031			(26,209	)		(21,209	)
Other income		1,388			109			1,007			436

Total revenue		276,864			151,596			558,067			362,723

COSTS AND EXPENSES:
Cost of natural gas and natural gas liquids		196,839			100,723			451,838			288,881
Operations and maintenance		16,883			9,094			36,017			23,892
Taxes other than income		2,746			651			4,364			1,045
Other operating		220			—			1,931			—
General and administrative		7,196			2,446			16,587			8,063
Depreciation, depletion and amortization		25,105			11,244			50,883			31,459

Total costs and expenses		248,989			124,158			561,620			353,340

OPERATING INCOME (LOSS)		27,875			27,438			(3,553	)		9,383
OTHER (EXPENSE) INCOME:
Interest income		231			217			2,601			740
Other income		767			—			879			—
Interest expense, net		(19,152	)		(14,547	)		(32,980	)		(20,993	)
Other expense		2			—			(255	)		—

Total other (expense) income		(18,152	)		(14,330	)		(29,755	)		(20,253	)

INCOME (LOSS) BEFORE INCOME TAXES		9,723			13,108			(33,308	)		(10,870	)

State income tax provision		352			236			772			744


NET INCOME (LOSS)	$	9,371		$	12,872		$	(34,080	)	$	(11,614	)


NET INCOME (LOSS) PER COMMON UNIT - BASIC AND DILUTED:
Basic:
Net income (loss)
Common units	$	0.25		$	0.44		$	(0.24	)	$	(0.42	)
Subordinated units		(0.09	)		0.44			(1.22	)		(0.42	)
General partner units		(0.09	)		0.44			(1.22	)		(0.42	)
Basic (units in thousands)
Common units		45,954			4,732			32,512			10,850
Subordinated units		20,691			24,151			20,691			16,631
General partner units		845			589			845			482

Diluted:
Net income (loss)
Common units	$	0.25		$	0.44		$	(0.24	)	$	(0.42	)
Subordinated units		(0.09	)		0.44			(1.22	)		(0.42	)
General partner units		(0.09	)		0.44			(1.22	)		(0.42	)
Diluted (units in thousands)
Common units		46,021			4,732			32,539			10,850
Subordinated units		20,691			24,151			20,691			16,631
General partner units		845			589			845			482

See notes to condensed consolidated financial statements.

EAGLE ROCK ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)


	Nine Months
	Ended September 30,
*($ in thousands)*	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(34,080	)	$	(11,614	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		50,883			31,459
Amortization of debt issuance costs		416			718
Reclassifying financing derivative settlements		(100	)		(514	)
Equity-based compensation expense		1,578			—
Other		(241	)		819
Changes in assets and liabilities — net of acquisitions:
Accounts receivable		(22,437	)		2,683
Prepayments and other current assets		2,115			972
Risk management activities		25,102			18,692
Accounts payable		24,516			(10,470	)
Advances due affiliates		17,541			—
Accrued liabilities		11,018			6,748
Other assets		287			318

Net cash provided by operating activities		76,598			39,811

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment		(53,787	)		(21,242	)
Acquisitions		(426,960	)		(100,524	)
Cash acquired in acquisitions		23,790			—
Escrow cash		—			7,643
Purchase of intangible assets		(1,128	)		(2,618	)
Other		22			—

Net cash used in investing activities		(458,063	)		(116,741	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt		173,400			—
Proceeds from revolver		—			3,000
Repayment of long-term debt		(18,054	)		(2,886	)
Repayment from revolver		—			(11,619	)
Payment of debt issuance costs		—			(2866	)
Proceeds from derivative contracts		100			514
Payment of deferred offering costs		—			(2,584	)
Contribution by members		—			98,540
Proceeds from equity issuance		331,500			—
Distributions to members and affiliates		(31,775	)		7,690

Net cash (used in) provided by financing activities		455,171			74,409

NET CHANGE IN CASH AND CASH EQUIVALENTS		73,706			(2,521	)
CASH AND CASH EQUIVALENTS — Beginning of period		10,851			19,372

CASH AND CASH EQUIVALENTS — End of period	$	84,557		$	16,851

Interest paid — net of amounts capitalized	$	27,212		$	22,858

Investments in property, plant and equipment not paid	$	2,068		$	1,092

Acquisition of assets for equity	$	307,937		$	—

See notes to condensed consolidated financial statements.

EAGLE ROCK ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY
FOR THE NINE MONTH PERIOD ENDED SEPTEMBER 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		—			16,236,265		331,500			—		—			331,500
Equity issued in acquisitions		—			13,705,960		307,937			—		—			307,937
Net loss		(1,023	)		—		(7,990	)		—		(25,067	)		(34,080	)
Distributions		—			—		(31,775	)		—		—			(31,775	)
Restricted unit expense		23			—		987			—		568			1,578


BALANCE — September 30, 2007	$	(1,544	)		50,633,720	$	716,942			20,691,495	$	151,749		$	867,147

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 Energy Partners, L.P. conducts its business through approximately twenty different subsidiaries, and one of the direct subsidiaries, Eagle Rock Pipeline GP, L.L.C., serves as the general partner of approximately ten of the other subsidiaries.

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, replenishment of working capital, and the payment of distribution arrearages.

Basis of Presentation and Principles of Consolidation— The accompanying financial statements include assets, liabilities and 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.). In connection with the initial public offering, Eagle Rock Pipeline, L.P. became our subsidiary and Eagle Rock Midstream Resources, L.P. was dissolved. 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. are, and the general partner interests of Eagle Rock Midstream Resources, L.P. prior to our IPO were, held by Eagle Rock Pipeline GP, L.L.C., now a wholly-owned subsidiary of Eagle Rock Energy Partners, L.P. For the time periods prior to October 24, 2006, Eagle Rock Pipeline, L.P., Eagle Rock Midstream Resources, L.P., Eagle Rock Pipeline GP, L.L.C. and their subsidiaries, and for time periods on and after October 24, 2006, Eagle Rock Energy Partners, L.P. and its affiliates, 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: (i) gathering, compressing, treating, processing, transporting and selling natural gas, fractionating and transporting natural gas liquids, or NGLs, which we call our “midstream” business, (ii) acquiring, developing and producing interests in oil and natural gas properties, which we call our “upstream” business, and (iii) acquiring and managing fee minerals and royalty interests across the United States, which we call our “minerals” business. The Partnership conducts its business in six segments, three within the midstream business, one that is the upstream business, one that is the minerals business, and one for corporate business.

As to the midstream business, the Partnership’s natural gas pipelines gather natural gas from designated points near producing wells and transport these volumes to third-party pipelines, the Partnership’s gas processing plants, utilities and industrial consumers. Natural gas transported to the Partnership’s gas processing plants, either on the Partnership’s pipelines or third-party pipelines, is treated to remove contaminants, conditioned and/or processed into marketable natural gas and natural gas liquids (NGLs).

The Partnership conducts, evaluates and reports on its midstream business within three distinct segments — the Texas Panhandle Segment, the South Texas Segment, and the East Texas and Louisiana Segment (formerly referred as the Southeast Texas and North Louisiana Segment). The Partnership’s Texas Panhandle Segment consists of gathering and processing assets acquired from ONEOK, Inc. on December 1, 2005. The Partnership’s East Texas and Louisiana Segment consists of a non-operated 25% undivided interest in a processing plant as well as a non-operated 20% undivided interest in a connected gathering system, a 100% interest in the Brookeland and Masters Creek processing plants in East Texas, acquired from Duke Energy Field Services on April 7, 2006, a 100% interest in the Roberts County processing plant and related gathering systems acquired on June 2, 2006, and certain gathering systems and related compression and processing facilities in East Texas and Louisiana, acquired in the Partnership’s acquisition of Laser Midstream Energy, L.P. (“Laser”) and certain of its subsidiaries (“Laser Acquisition”) on May 3, 2007. The Partnership’s South Texas Segment consists of gathering systems and related compression and processing facilities in South Texas acquired in the Partnership’s acquisition of Laser and certain of its subsidiaries on May 3, 2007.

The Partnership conducts, evaluates and reports on its upstream business as one segment. On July 31, 2007, the Partnership assembled the Upstream Segment by closing two transactions contemporaneously. In one transaction, the Partnership completed the acquisition of Escambia Asset Co., LLC and Escambia Operating Company, LLC (“the EAC Acquisition”) (Note 4). In the second separate transaction on July 31, 2007, the Partnership completed the acquisition of Redman Energy Holdings, L.P. and Redman Energy Holdings II, L.P. (former Natural Gas Partners VII, L.P. and Natural Gas Partners VIII, L.P. portfolio companies, respectively) and certain related assets owned by NGP Income Co-Investment Opportunities Fund II, L.P. (a Natural Gas Partners affiliate) (collectively referred to as “the Redman Acquisition”) (Note 4).

The Partnership conducts, evaluates and reports on its minerals business as one segment. The Partnership’s Minerals Segment consists of certain fee minerals, royalties, overriding royalties and non-operated working interest properties acquired on April 30, 2007 indirectly by acquisition of certain entities from Montierra Minerals & Production, L.P. (“Montierra”) (a former Natural Gas Partners VII, L.P. portfolio company) and directly from NGP-VII Income Co-Investment Opportunities, L.P. (“Co-Invest”) (a Natural Gas Partners affiliate) (collectively, “the Montierra Acquisition”) and certain fee minerals, royalties, overriding royalties and non-operated working interest properties acquired on June 18, 2007 directly from MacLondon Energy, L.P. that related to the same acreage covered by the assets acquired under the Montierra Acquisition. As a result of these acquisitions, our Minerals Segment includes mineral and royalty interests located in multiple producing trends across the United States.

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 nine months ended September 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 (“SEC”). 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.

Impairment of Oil and Gas Properties

net cash flows from proved reserves, utilizing a risk-free rate of return. We cannot predict the amount of impairment charges that may be recorded in the future. Unproved leasehold costs are reviewed periodically and a loss is recognized to the extent, if any, that the cost of the property has been impaired.

Property Retirement Obligations

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

Other Significant Accounting Policies

Interim Condensed Disclosures— The information for the three and nine months ended September 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. The Partnership also increased the number of parties to which it sell liquids and natural gas as a result of the acquisitions completed during 2007. 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 business’s natural gas and natural gas liquid supply, with the top two producers (by segment) accounting for 34% of its natural gas supply in the Texas Panhandle Segment, 38% of its natural gas supply in the East Texas/Louisiana Segment and 39% of its natural gas supply in the South Texas Segment for the month ended September 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. These percentages are calculated based on MMBtus gathered during the month of September 2007.

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 nine month periods ended September 30, 2007, the Partnership capitalized interest of approximately $0.3 million and $0.8 million, respectively. During the three and nine month periods ended September 30, 2006, the Partnership capitalized interest of $0.2 million and $0.2 million, respectively.

Producing Oil and Natural Gas Properties —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.

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.

Impairment of Oil and Gas Properties

We review our improved properties at the field level when management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future oil and natural gas reserves that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels. If the carrying amount of an asset exceeds the sum of the undiscounted estimated future net cash flows, we recognize impairment expense equal to the difference between the carrying value and the fair value of the asset, which is estimated to be the expected present value of discounted future net cash flows from proved reserves, utilizing a risk-free rate of return. We cannot predict the amount of impairment charges that may be recorded in the future. Unproved leasehold costs are reviewed periodically and a loss is recognized to the extent, if any, that the cost of the property has been impaired.

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 $13.1 million for the nine months ended September 30, 2007 and approximately $11.6 million for the nine months ended September 30, 2006. Estimated aggregate amortization expense for each of the five succeeding years is as follows: 2008 — $18.2 million; 2009 — $18.2 million; 2010 — $16.6 million; 2011 — $6.5 million; and 2012 — $6.5 million. Intangible assets consisted of the following (as of September 30, 2007 and December 2006):


	September 30,			December 31,
*($ in thousands)*	2007			2006
Rights-of-way and easements — at cost	$	69,366		$	66,801
Less: accumulated amortization		(6,073	)		(3,510	)
Contracts		112,422			80,210
Less: accumulated amortization		(24,051	)		(13,500	)

Net intangible assets	$	151,664		$	130,001

The amortization period for our rights-of-way and easements is 20 years and contracts range from 5 to 20 years, and are approximately 13 years on average as of September 30, 2007.

Other Assets— Other assets primarily consist of costs associated with: debt issuance, net of amortization ($6.5 million); business deposits to various providers and state or regulatory agencies ($2.7 million); and equity in earnings

of unconsolidated non-affiliate related to the Montierra Acquisition ($4.1 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 September 30, 2007, the Partnership had imbalance receivables totaling $0.5 million and imbalance payables totaling $2.1 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, oil and condensate;

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

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

	•		royalties, overriding royalties and lease bonuses.

Revenues associated with sales of natural gas, NGLs, oil 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 September 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 $2.4 million as of September 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 September 30, 2007. Through the Redman acquisition, the Partnership acquired a corporation as part of the transaction. At the time of closing, $1.0 million of deferred taxes was recorded related to book/tax differences for the related assets in the corporation. The corporation structure could expose us to income taxes, however the Partnership believes its related structure and agreements at the acquisitions should minimize any future tax exposure (see Note 13).

Derivatives — 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 consolidated statement of operations, as the Partnership has not designated any of these derivative instruments as hedges. The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as a financing activity in the statement of cash flows. See Note 10 for a description of the Partnership’s risk management activities.

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

NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS

In 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 to 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.

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.

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.

A significant portion of the Partnership’s sale and purchase arrangements are accounted for on a gross basis in the consolidated statements of operations as natural gas sales and costs of natural gas, respectively. These transactions are contractual arrangements which establish the terms of the purchase of natural gas at a specified location and the sale of natural gas at a different location at the same or at another specified date. These arrangements are detailed either jointly, in a single contract or separately, in individual contracts which are entered into concurrently or in contemplation of one another with a single or multiple counterparties. Both transactions require physical delivery of the natural gas and the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk and counterparty nonperformance risk. 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 and the nine months ended September 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 September 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

MontierraAcquisition. On April 30, 2007, the Partnership acquired (through part entity purchase and part asset purchase in the Montierra Acquisition) certain fee mineral acres, royalty and overriding royalty interests. Eagle Rock Energy paid consideration that totaled 6,390,400 of our common units and $6.0 million of cash, subject to adjustment. 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 recorded the Montierra Acquisition 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 at their carryover basis. Those interests not attributable to Natural Gas Partners have been recorded at their fair value.

The assets acquired in the Montierra Acquisition include fee mineral acres, royalty and overriding royalty interests in oil and natural gas producing wells.

The purchase price was allocated on a preliminary basis to “oil and gas properties”, “cash”, “accounts receivable”, “accounts payable”, “risk management liabilities”, “accrued liabilities” and “equity investments in non-affiliates” in the amounts of approximately $132.4 million, $0.9 million, $6.3 million, ($1.9) million, ($0.7) million, ($0.1) million and $3.5 million, respectively, based on their respective fair value as determined by management. The preliminary purchase price allocation is set forth in more detail (and tabular format) below.


*($ in thousands)*
Oil and gas properties
Proved Properties	$	82,758
Unproved Properties		49,656
Cash		936
Accounts receivable		6,342
Accounts payable		(1,906	)
Risk management liabilities		(717	)
Accrued liabilities		(104	)
Equity in earnings of non-affiliate		3,459

	$	140,424

LaserAcquisition. On May 3, 2007, Eagle Rock Energy Partners, L.P. acquired certain entities from Laser Midstream Energy II, LP, a Delaware limited partnership, and Laser Midstream Company, LLC, a Texas limited liability company. The sellers recorded total consideration, subject to adjustment, 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”, “intangibles”, “cash”, “accounts receivable”, “other current assets”, “accounts payable” and “other current liabilities” in the amounts of approximately $107.2 million, $32.2 million, $2.9 million, $31.1 million, $0.3 million, ($30.1) million and ($0.3) 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 allocation is set forth in more detail (and tabular format) 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

MacLondonAcquisition. 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 789,474 units.

EAC Acquisition.On July 31, 2007, we completed the acquisition of Escambia Asset Co., LLC and Escambia Operating Company, LLC (the “EAC Acquisition”). Upon closing, the sellers in the EAC Acquisition received approximately $224.0 million in cash and 689,857 in Eagle Rock common units, subject to adjustment. The assets subject to the EAC Acquisition include 31 operated productive wells in Escambia County, Alabama, two associated treating facilities with 100 MMcf/d of capacity, one associated natural gas processing plant with 40 MMcf/d of capacity and related gathering systems.

The purchase price was allocated on a preliminary basis to “oil and gas properties”, “equipment and vehicles”, “cash and cash equivalents”, “accounts receivable”, “prepaid assets”, “risk management assets”, “other assets”, “accounts payable”, “accrued liabilities”, “asset retirement obligations” and “risk management liabilities” in the amounts of approximately $227.3 million, $4.8 million, $4.7 million, $17.7 million, $0.9 million, $2.2 million, $1.4 million, ($11.4) million, ($0.8) million, ($3.6) million and ($0.9) million, respectively, based on their respective fair value as determined by management with the assistance of a third-party valuation specialist. The preliminary purchase price allocation is set forth in more detail (and tabular format) below. The EAC Acquisition was accounted for as a purchase in accordance with FASB No. 141, Business Combinations.


*($ in thousands)*
Oil and gas properties
Proved Proved Properties	$	201,191
Unproved Properties		19,370
Plant and related assets		11,560
Cash and cash equivalents		4,732
Accounts receivable		17,713
Prepaid assets		868
Risk management assets		2,186
Other assets		1,376
Accounts payable		(11,440	)
Accrued liabilities		(849	)
Asset retirement obligations		(3,560	)
Risk management liabilities.		(943	)

	$	242,204

Redman Acquisition.On July 31, 2007, Eagle Rock 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”). Upon closing, sellers in the Redman Acquisition received as consideration, subject to adjustment, a total of 4,428,334 newly-issued Eagle Rock common units and $83.8 million in cash.

The purchase price was allocated on a preliminary basis to “oil and gas properties”, “cash and cash equivalents”, “accounts receivable, net”, “prepaid assets”, “derivatives receivable”, “other assets”, “accounts payable”, “deferred tax payable” and “other long-term liabilities” in the amounts of approximately $179.2 million, $15.2 million, $6.3 million, $0.6 million, $1.1 million, $1.1 million, ($11.3) million, ($1.0) million and ($0.5) million, respectively, based on their respective fair value as determined by management. The preliminary purchase price allocation is set forth in more detail (and tabular format) below. The acquisition of Redman was accounted for as a purchase in accordance with Topic 2D.


*($ in thousands)*
Oil and gas assets
Proved Properties	$	179,242
Cash and cash equivalents		15,237
Accounts receivable, net		6,334
Prepaid assets		576
Derivatives receivable		1,119
Other assets		1,134
Accounts payable		(11,340	)
Deferred tax payable		(1,028	)
Other long-term liabilities		(512	)

	$	190,762

One or more NGP private equity funds directly or indirectly owned a majority of the equity interests in Eagle Rock and the Redman entities. Because of the potential conflict of interest between the interests of the Company and the public unitholders of Eagle Rock, the Board of Directors authorized the Company’s Conflicts Committee to review, evaluate, and, if determined appropriate, approve the Redman Acquisition. The Conflicts Committee, consisting of independent Directors of the Company, determined that the Redman Acquisition was fair and reasonable to Eagle Rock and its public unitholders and recommended to the Board of Directors of the Company that the transaction be approved and authorized. In considering the fairness of the Redman Acquisition, the Conflicts Committee considered the valuation of the properties involved in the transaction, the valuation of the units to be offered as consideration in the transaction, and the cash flow of Redman. Based on the recommendation of the Conflicts Committee, the Board of Directors approved the transaction.

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


*($ in thousands)*	September 30, 2007
Pro forma earnings data:
Revenues(a)	$	796,679
Less: Cost and expenses		625,630

Income from continuing operations	$	171,049


(a)		Excludes non-realized revenues risk management loss of $30.5 million.

NOTE 5. PROPERTY, PLANT AND EQUIPMENT AND ASSET RETIREMENT OBLIGATIONS

Fixed assets consisted of the following:


	September 30,			December 31,
*($ in thousands)*	2007			2006
Land	$	1,064		$	853
Plant		132,318			81,485
Gathering and pipeline		544,409			433,779
Equipment and machinery		46,738			37,185
Vehicles and transportation equipment		3,627			2,740
Office equipment, furniture, and fixtures		1,180			511
Computer equipment		4,770			4,623
Corporate		126			126
Linefill		4,157			3,923
Proved properties		475,208			—
Unproved properties		79,565			—
Construction in progress		25,428			19,677

		1,318,590			584,902
Less: accumulated depreciation, depletion and amortization		(69,480	)		(30,839	)

Net fixed assets	$	1,249,110		$	554,063

Depreciation expense for the three and nine months ended September 30, 2007 and for the three and nine months ended September 30, 2006 was approximately $10.9 million, $26.8 million, $7.1 million and $19.8 million, respectively. Depletion expense for the three months and nine months ended September 30, 2007 and for the three and nine months ended September 30, 2006 was approximately $9.4 million, $10.9 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,as it pertains to our oil and gas properties, 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		84
Additional liability related to recent acquisitions		6,968
Accretion expense		174

Asset retirement obligations — September 30, 2007	$	9,045

NOTE 6. LONG-TERM DEBT

Long-term debt consisted of:


	September 30,		December 31,
*($ in thousands)*	2007		2006
Revolver	$	261,881	$	106,481
Term loan		299,250		299,250

Total debt		561,131		405,731
Less: current portion		—		—

Total long-term debt	$	561,131	$	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 the Revolver 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. On July 31, 2007, the Partnership drew $106.0 million from the Revolver to fund a portion of the EAC and Redman acquisitions. As of September 30, 2007, Eagle Rock Energy had total borrowing availability of $600.0 million and had $561.1 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 September 30, 2007, the Partnership had $12.4 million of outstanding letters of credit.

During the quarter ended September 30, 2007 and 2006, the Partnership recorded approximately $0.4 million and $0.2 million of debt issuance amortization expense, respectively. As of September 30, 2007, the unamortized amount of debt issuance costs was $6.5 million.

With the consummation of the Partnership’s initial public offering on October 24, 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, also on 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 September 30, 2007 (utilizing the December 2006, March 2007, June 2007 and September 2007 quarters Consolidated Adjusted EBITDA as defined under the Credit Agreement, annualized to an Adjusted EBITDA amount for the ratio), the Partnership has approximately $26.4 million of unused capacity under the Amended and Restated Credit Agreement Revolver at

September 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 September 30, 2007, the weighted average interest rate on our outstanding debt balance was 8.24%. 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 September 30, 2007, were as follows:


	Principal
*($ in thousands)*	Amount
2007	$	—
2008		—
2009		—
2010		—
2011		561,131

	$	561,131

The Partnership was in compliance with the financial covenants under the Amended and Restated Credit Agreement as of September 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, as partial consideration for the Montierra Acquisition, the Partnership issued and transferred to the sellers 6,390,400 common units.

On May 3, 2007, 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 contemporaneously with the Laser Acquisition.

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

On July 31, 2007, as partial consideration for the EAC Acquisition, the Partnership issued and transferred to the seller 689,857 common units.

On July 31, 2007, as partial consideration for the Redman Acquisition, the Partnership issued and transferred to the seller 4,428,334 common units.

On July 31, 2007, the Partnership entered into a common unit purchase agreement to sell in a private placement 9,230,770 common units to third-party investors for total cash proceeds of approximately $204.0 million. The private placement closed contemporaneously with the EAC and Redman Acquisitions on July 31, 2007.

At September 30, 2007, there were 50,633,720 common units (exclusive of restricted unvested common units), 20,691,495 subordinated units (all subordinated units owned by Holdings) and 844,551 general partner units outstanding. In addition, there were 527,021 restricted unvested common units outstanding.

Subordinated units represent limited partner interests in the Partnership, and holders of subordinated units exercise the rights and privileges available to unitholders under the Partnership’s agreement of limited partnership. 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 common 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 common 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 common 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 or paid to the general partner or Holding on the general partner or subordinated units.

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

On November 8, 2007, the Partnership declared a cash distribution of $0.3675 per common unit including general partner and subordinated units) for the third quarter ending September 30, 2007. The distribution will be paid November 14, 2007 to all unitholders (including our general partner and Holdings) of record as of November 8, 2007.

NOTE 8. RELATED PARTY TRANSACTIONS

On July 1, 2006, the Partnership entered into a month-to-month contract for the sale of natural gas with an affiliate of Natural Gas Partners, under which the Partnership sells a portion of its gas supply. The Partnership has received a Letter of Credit related to this agreement. The Partnership recorded revenues of $6.5 million and $20.4 million for the three and nine month periods ended September 30, 2007 from the agreement, of which there was a receivable of $1.0 million outstanding at September 30, 2007.

The Partnership entered into an Omnibus Agreement with Eagle Rock Energy G&P, LLC, Holdings and the Partnership’s general partner on October 24, 2006, in connection with the initial public offering of the Partnership. The Omnibus Agreement 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. As of September 30, 2007, Eagle Rock Energy G&P, LLC has $17.4 million of outstanding checks paid on behalf of the Partnership. This amount is recorded to Due to Affiliate on the Partnership’s balance sheet in the Current Liabilities. As the outstanding checks are drawn against Eagle Rock Energy G&P, LLC cash accounts, the Partnership reimburses Eagle Rock Energy G&P, LLC.

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

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. 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, subject to adjustments. 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 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.

On July 31, 2007, Eagle Rock Energy Partners, L.P. 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”). Redman sellers and NGP received as consideration a total of 4,428,334 newly-issued Eagle Rock common units and $83.8 million in cash, subject to adjustments. One or more NGP private equity funds directly or indirectly owns a majority of the equity interests in Eagle Rock and the Redman entities. Because of the potential conflict of interest between the interests of the Company and the public unitholders of Eagle Rock, the Board of Directors authorized the Company’s Conflicts Committee to review, evaluate, and, if

determined appropriate, approve the Redman Acquisition. The Conflicts Committee, consisting of independent Directors of the Company, determined that the Redman Acquisition was fair and reasonable to Eagle Rock and its public unitholders and recommended to the Board of Directors of the Company that the transaction be approved and authorized. In determining the purchase consideration for the Redman Acquisition, the Conflicts Committee considered the valuation of the properties involved in the transaction, the valuation of the units to be offered as consideration in the transaction, and the cash flow of Redman. Based on the recommendation of the Conflicts Committee, the Board of Directors approved the transaction.

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 September 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			September 30,
Effective Date	Date		Amount		Rate			2007
01/03/2006		01/03/2011	$	100,000,000		4.9500	%	$	(889	)
01/03/2006		01/03/2011		100,000,000		4.9625			(832	)
01/03/2006		01/03/2011		50,000,000		4.8800			(309	)
01/03/2006		01/03/2011		50,000,000		4.8800			(309	)
09/18/2007		12/31/2010		75,000,000		4.6600			(29	)
09/18/2007		12/31/2010		75,000,000		4.6650			(41	)

For the three month periods ended September 30, 2007 and 2006, the Partnership recorded a fair value loss within interest expense of $8.5 million and $6.5 million, respectively. For the nine month periods ended September 30, 2007 and 2006, the Partnership recorded $1.5 million net loss and $2.6 million net gain, respectively. As of September 30, 2007 and December 31, 2006, the fair value of these contracts totaled an approximate $2.4 million liability and an approximate $1.2 million asset, 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.

In addition to the derivatives previously entered into related to our midstream business, we entered or assumed the following derivative transactions related to our upstream business in association with the Montierra, EAC and Redman acquisitions. Transactions shown with a floor price only are puts; all other are costless collars.

Price

Average Monthly

($/mmbtu or $/bbl)

Period

Commodity

Volumes

Index

Avg. Floor

Avg. Ceiling

Jan-Dec 2007

Gas

20,000 MMBtu

NYMEX

8.00

12.95

Jan-Dec 2007

Gas

15,000 MMBtu

NYMEX

7.00

10.40

Jan-Dec 2007

Gas

10,000 MMBtu

NYMEX

6.25

8.00

Jan-Dec 2007

Gas

40,000 MMBtu

NYMEX

8.00

12.11

Jan-Dec 2007

Gas

20,000 MMBtu

NYMEX

7.00

Jan-Dec 2007

Gas

40,000 MMBtu

NYMEX

7.00

Apr-Dec 2007

Gas

123,600 MMBtu

NYMEX

7.00

11.89

Jan-Dec 2007

Oil

500 Bbl

NYMEX WTI

60.00

75.00

Jan-Dec 2007

Oil

2,500 Bbl

NYMEX WTI

60.00

72.55

Jan-Dec 2007

Oil

500 Bbl

NYMEX WTI

60.00

75.00

Jan-Dec 2007

Oil

2,500 Bbl

NYMEX WTI

60.00

72.55

Jan-Dec 2007

Oil

2,000 Bbl

NYMEX WTI

60.00

75.15

Jan-Dec 2007

Oil

32,000 Bbl

NYMEX WTI

74.00

Jan-Dec 2007

Oil

4,000 Bbl

NYMEX WTI

65.00

Jan-Dec 2007

Oil

3,000 Bbl

NYMEX WTI

65.00

Jan-Dec 2007

Oil

5,000 Bbl

NYMEX WTI

60.00

79.95

Jul-Dec 2007

Oil

5,000 Bbl

NYMEX WTI

65.00

82.75

Jan-Dec 2008

Gas

30,000 MMBtu

NYMEX

6.25

11.15

Jan-Dec 2008

Gas

103,000 MMBtu

NYMEX

7.00

13.98

Jan-Dec 2008

Gas

30,000 MMBtu

NYMEX

7.50

12.01

Jan-Dec 2008

Gas

50,000 MMBtu

NYMEX

7.00

Jan-Dec 2008

Oil

6,000 Bbl

NYMEX WTI

60.00

71.65

Jan-Dec 2008

Oil

29,000 Bbl

NYMEX WTI

65.00

90.00

Jan-Dec 2008

Oil

4,000 Bbl

NYMEX WTI

60.00

77.22

Jan-Dec 2008

Oil

6,000 Bbl

NYMEX WTI

65.00

Jan-Dec 2008

Oil

5,000 Bbl

NYMEX WTI

60.00

83.75

Jan-Dec 2009

Gas

20,000 MMbtu

NYMEX

6.25

11.20

Jan-Mar 2009

Gas

92,700 MMBtu

NYMEX

7.50

13.75

Jan-May 2009

Gas

40,000 MMBtu

NYMEX

7.00

Jan-May 2009

Oil

7,000 Bbl

NYMEX WTI

60.00

80.75

Jan-Dec 2009

Oil

6,000 Bbl

NYMEX WTI

60.00

77.00

In addition to the upstream derivative transaction described above, we also entered into or assumed the following derivative transactions associated with our midstream business in conjunction with the EAC Acquisition. All of these derivatives are swaps.

Average Monthly

Price

Period

Commodity

Volumes

Index

($/gal)

Jul-Dec 2007

Propane

4,091 Bbl

OPIS MTB TET

1.0875

Jul-Dec 2007

Propane

5,906 Bbl

OPIS MTB non-TET

1.0775

Jul-Dec 2007

n-Butane

7,156 Bbl

OPIS MTB non-TET

1.2775

Jul-Dec 2007

i-Butane

3,600 Bbl

OPIS MTB non-TET

1.2950

Jan-Dec 2008

Propane

3,272 Bbl

OPIS MTB TET

1.0875

Jan-Dec 2008

Propane

6,076 Bbl

OPIS MTB non-TET

1.0775

Jan-Dec 2008

n-Butane

6,691 Bbl

OPIS MTB non-TET

1.2775

Jan-Dec 2008

i-Butane

3,367 Bbl

OPIS MTB non-TET

1.2950

Jan-Dec 2009

Propane

2,955 Bbl

OPIS MTB TET

1.0875

Jan-Dec 2009

Propane

5,486 Bbl

OPIS MTB non-TET

1.0775

Jan-Dec 2009

n-Butane

6,042 Bbl

OPIS MTB non-TET

1.2775

Jan-Dec 2009

i-Butane

3,040 Bbl

OPIS MTB non-TET

1.2950

On September 13, 2007 and pursuant to its stated strategy of mitigating its commodity price exposure and reducing the volatility in its cash flows, Eagle Rock entered into the following hedging transactions.

To negate the economic impact of previously entered into, out-of-the-money collars for 2008 crude production, Eagle Rock sold floors and bought caps for a total cost of $9.1 million, as follows:

Average Monthly

Floor

Cap

Period

Commodity

Volumes

Index

($/Bbl)

Jan-Dec 2008

Crude oil

20,000 Bbl

NYMEX WTI

50.00

65.65

Jan-Dec 2008

Crude oil

20,000 Bbl

NYMEX WTI

50.00

65.70

Jan-Dec 2008

Crude oil

40,000 Bbl

NYMEX WTI

50.00

69.10

In addition, we entered into a WTI crude oil swap for 2008 on the same 80,000 barrels per month, as follows:

Average Monthly

Swap Price

Period

Commodity

Volumes

Index

($/Bbl)

Jan-Dec 2008

Crude oil

80,000 Bbl

NYMEX WTI

73.90

The combined impact of these two transactions was to raise Eagle Rock’s floor on those volumes by $23.90 per barrel while at the same time raising its cap by $6.51 per barrel (on a weighted-average basis) to its swap price of $73.90.

On the same date, Eagle Rock entered into the following crude oil swaps for 2009 and 2010 to help mitigate its upstream business’ commodity price exposure:

Average Monthly

Swap Price

Period

Commodity

Volumes

Index

($/Bbl)

Jan-Dec 2009

Crude oil

25,000 Bbl

NYMEX WTI

71.25

Jan-Dec 2010

Crude oil

25,000 Bbl

NYMEX WTI

70.00

Also on the same date, we entered into swap transactions to hedge a portion of our NGL commodity price exposure for the fourth quarter of 2007, as follows:

Average Monthly

Swap Price

Period

Commodity

Volumes

Index

($/gal)

Oct-Dec 2007

Ethane

40,000 Bbl

OPIS MTB non-TET

0.83375

Oct-Dec 2007

Propane

35,000 Bbl

OPIS MTB TET

1.2775

Oct-Dec 2007

n-Butane

16,000 Bbl

OPIS MTB non-TET

1.5275

Oct-Dec 2007

i-Butane

8,500 Bbl

OPIS MTB non-TET

1.5575

On September 25, 2007, Eagle Rock entered into additional swap transactions on ethane and propane volumes for 2008 and 2009, per the following table:

Average Monthly

Swap Price

Period

Commodity

Volumes

Index

($/gal)

Jan-Dec 2008

Ethane

25,000 Bbl

OPIS MTB non-TET

0.7200

Jan-Dec 2008

Propane

35,000 Bbl

OPIS MTB TET

1.1900

Jan-Dec 2009

Ethane

25,000 Bbl

OPIS MTB non-TET

0.6361

Jan-Dec 2009

Propane

15,000 Bbl

OPIS MTB TET

1.0925

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 nine month periods ended September 30, 2007, the Partnership recorded a gain on risk management instruments of $18.4 million and $19.9 million, respectively, representing a fair value (unrealized) gain of $20.5 million, amortization of put premiums of $2.0 million and net (realized) settlements loss from the Partnership of $0.1 million. As of September 30, 2007, the fair value liability of these contracts, including the put premiums, totaled approximately $11.5 million. As of December 31, 2006, the fair value loss of these contracts, including premiums, totaled $8.4 million.

NOTE 11. COMMITMENTS AND CONTINGENT LIABILITIES

Litigation — The Partnership is subject to several lawsuits which arise from time to time in the ordinary course of business, primarily related to the payments of liquids and natural gas proceeds in accordance with contractual terms. The Partnership has accruals of approximately $1.4 million and $1.5 million as of September 30, 2007 and December 31, 2006, respectively, related to these matters. The Partnership has been indemnified up to a certain dollar amount for many of these lawsuits. For the indemnified lawsuits, the Partnership has not established any accruals as the likelihood of these suits being successful against them is considered remote. If there ultimately is a finding against the Partnership in the indemnified cases, the Partnership would expect to make a claim against the indemnification up to limits of the indemnification. These matters are not expected to have a material adverse effect on our financial position, results of operations or cash flows.

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, (5) property and reservoir damage insurance for operated and non operated wells in upstream segment, and (6) corporate liability policies including Directors and Officers coverage and Employment Practice liability coverage. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operation.

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

Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing,

treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, the Partnership must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership’s combined results of operations, financial position or cash flows. At September 30, 2007 and December 31, 2006, the Partnership had accrued approximately $2.4 million and $0.3 million, respectively, 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 nine months ended September 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 mineral/royalty segment, one upstream segment and one functional (corporate) segment:

	(i)		Midstream – Texas Panhandle Segment:

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

	(ii)		Midstream – South Texas Segment:

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

	(iii)		Midstream – East Texas and Louisiana Segment:

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

	(iv)		Upstream Segment:

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

	(v)		Minerals Segment:

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

	(vi)		Corporate Segment:

			risk management and other corporate activities.

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


*($ in millions)*	Texas				East Texas and
Three months ended September 30, 2007	Panhandle		South Texas		Louisiana		Upstream		Minerals		Corporate			Total
Sales to external customers	$	130.3	$	64.3	$	48.5	$	19.1	$	6.0	$	8.7	^(a)	$	276.9
Segment gross profit (loss)(b)		33.4		2.7		10.1		19.1		6.0		8.7			80.0
Interest expense-net and other financing costs		—		—		—		—		—		18.9			18.9
Depreciation, depletion and amortization		10.7		0.9		3.3		6.9		3.3		—			25.1
Capital expenditures		7.2		0.8		5.7		—		—		—			13.7
Segment assets		584.0		62.3		290.6		470.9		160.8		94.2			1,662.8


					East Texas
*($ in millions)*	Texas				and
Three months ended September 30, 2006	Panhandle		South Texas		Louisiana		Upstream		Minerals		Corporate			Total
Sales to external customers	$	112.8	$	—	$	24.8	$	—	$	—	$	14.0	^(a)	$	151.6
Segment gross profit (loss)(b)		30.7		—		6.2		—		—		13.9			50.8
Depreciation, depletion and amortization		8.9		—		1.6		—		—		0.8			11.3
Interest expense-net and other financing costs		—		—		—		—		—		14.4			14.4
Capital expenditures		0.2		—		7.5		—		—		0.4			8.1
Segment assets		565.6		—		122.5		—		—		80.7			768.8


*($ in millions)*	Texas				East Texas and
Nine months ended September 30, 2007	Panhandle		South Texas		Louisiana		Upstream		Minerals		Corporate			Total
Sales to external customers	$	335.2	$	115.1	$	105.6	$	19.1	$	9.2	$	(26.2	)^(a)	$	558.0
Segment gross profit (loss)(b)		76.7		4.3		23.1		19.1		9.2		(26.2	)		106.2
Depreciation, depletion and amortization		30.2		1.3		7.0		6.9		4.9		0.6			50.9
Interest expense-net and other financing costs		1.4		—		—		—		—		30.4			31.8
Capital expenditures		29.7		2.1		24.1		—		—		0.5			56.4
Segment assets		584.0		62.3		290.6		470.9		160.8		94.2			1,662.8


*($ in millions)*	Texas				East Texas and
Nine months ended September 30, 2006	Panhandle		South Texas		Louisiana		Upstream		Minerals		Corporate			Total
Sales to external customers	$	324.9	$	—	$	59.0	$	—	$	—	$	(21.2	)^(a)	$	362.7
Segment gross profit (loss)(b)		80.8		—		14.3		—		—		(21.3	)		73.8
Depreciation, depletion and amortization		26.4		—		4.3		—		—		0.8			31.5
Interest expense-net and other financing costs		—		—		—		—		—		20.3			20.3
Capital expenditures		5.6		—		12.0		—		—		3.4			21.0
Segment assets		565.6		—		122.5		—		—		80.7			768.8


(a)		Represents realized and unrealized revenue risk management activities.

(b)		Segment Gross Profit is defined as operating revenues less the purchase of natural gas and NGLs expense, where applicable.

The following table reconciles Total Segment Gross Profit (loss) to net income (loss):


	Three Months		Three Months		Nine Months			Nine Months
	Ended		Ended		Ended			Ended
	September 30,		September 30,		September 30,			September 30,
*($ in millions)*	2007		2006		2007			2006
Total segment gross profit	$	80.0	$	50.8	$	106.2		$	73.8
Operations and maintenance		16.9		9.1		36.0			23.9
Taxes other than income		2.7		0.7		4.4			1.0
General and administrative		7.2		2.4		16.6			8.1
Other operating		0.2		—		1.9			—
Depreciation, depletion and amortization		25.1		11.2		50.9			31.5
Interest and other expense, net		18.1		14.3		29.6			20.2
State income tax provision		0.4		0.2		0.8			0.7

Net income (loss)	$	9.4	$	12.9	$	(34.0	)	$	(11.6	)

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 nine month periods ended September 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 September 30, 2007, the Partnership has a deferred state tax liability in the approximate amount of $1.2 million.

Through the Redman Acquisition, the Partnership acquired a corporation as part of the transaction. The related corporation structure could expose us to income taxes; however, the Partnership believes it has taken steps to minimize any future tax exposure on the corporation. At the time of closing, $1.0 million of deferred taxes was recorded related to book/tax differences for the related assets in the corporation.

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 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 employees and independent directors of the General Partner who provide services to the Partnership. Subsequently (but prior to September 30, 2007) 78,100 restricted common units were issued to certain employees and a new independent director (in connection with their acceptance of employment and directorship, respectively). The awards generally vest on the basis of one third of the award each year. During the restriction period, distributions associated with the granted awards will be distributed to the awardees. No options or phantom units have been issued to date.

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


	Number of
	Restricted			Weighted Average
	Units			FairValue
Outstanding at December 31, 2006		122,450		$	18.75
Granted		423,371		$	23.25
Vested		—
Forfeitures		(18,800	)	$	21.90

Outstanding at September 30, 2007		527,021		$	23.08

For the three and nine month periods ended September 30, 2007, non-cash compensation expense of approximately $0.8 million and $1.6 million, respectively, was recorded related to the granted restricted units. The terms of the October 2006 award agreements were amended during the current quarter to permit direct distributions to the holders of restricted unvested common units under such awarded award agreements during the unvested period, including the August 14, 2007. Prior to the amendment, distributions were made on the restricted unvested common units under these award agreements held by the Partnership, to be finally distributed to the holder or forfeited in keeping with (and on the same timing as) the fate of the underlying unit’s vesting or forfeiture, and, per the amendment, the two prior distributions (i.e., the fourth quarter 2006 prorated distribution and the first quarter 2007 minimum quarterly distribution) will continue to be held by the Partnership with the final disposition of said

distributions to be determined in the original manner prescribed for distributions. Restricted common units granted during 2007 already were entitled to receive direct distributions during their unvested periods. This modification resulted in a repricing of the unvested units from their original value of $18.75 to the unit price of $22.60 at the time of the amendment. This change affected approximately 109,750 unvested units (135 employees) and resulted in a $0.1 million increase in compensation for the third quarter.

As of September 30, 2007, unrecognized compensation costs related to the outstanding restricted units under our LTIP totaled approximately $9.9 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 nine months ended September 30, 2007 had a weighted average of $21.90. The remaining expense is to be recognized over a weighted average of 2.5 years.

NOTE 15. SUBSEQUENT EVENTS

On November 7 and 8, 2007, the Partnership entered into additional commodity hedge transactions, as described below:

Average Monthly

Price

Period

Commodity

Volumes

Index

$/MMBtu or $/Bbl

Jan-Dec 2008

Crude oil

30,000 Bbl

NYMEX WTI

89.50

Jan-Dec 2009

Crude oil

50,000 Bbl

NYMEX WTI

80.25

Jan-Dec 2010

Crude oil

10,000 Bbl

NYMEX WTI

78.35

Jan-Dec 2011

Crude oil

45,000 Bbl

NYMEX WTI

80.00

Jan-Dec 2012

Crude oil

40,000 Bbl

NYMEX WTI

80.30

Jan-Dec 2008

Natural gas

83,000 MMBtu

NYMEX

8.00

Jan-Dec 2009

Natural gas

85,000 MMBtu

NYMEX

8.35

Price

$/MMBtu or $/Bbl

Average Monthly

Floor

Cap

Period

Commodity

Volumes

Index

($/Unit)

Jan-Dec 2011

Crude oil

50,000 Bbl

NYMEX WTI

75.00

85.70

Jan-Dec 2012

Crude oil

50,000 Bbl

NYMEX WTI

75.30

86.00

Jan-Dec 2009

Natural gas

85,000 MMBtu

NYMEX

7.85

9.25

Jan-Dec 2010

Natural gas

110,000 MMBtu

NYMEX

7.70

9.10

Jan-Dec 2011

Natural gas

100,000 MMBtu

NYMEX

7.50

8.85

Jan-Dec 2012

Natural gas

90,000 MMBtu

NYMEX

7.35

8.65

In addition to entering into the derivative instruments described in the table above, we also bought back at no cost to the Partnership an option on a swap (“swaption”). Under that agreement, the other party had the right, but not the obligation, to enter into a swap with us for 26,000 Bbls of NYMEX WTI per month during the period from January to December 2009 at a strike price of $85.00.

Our recently acquired 40 MMcf/d throughput treating plant at Big Escambia Creek, Alabama, (“BEC Treating Plant”) is undergoing maintenance and repair work to remediate specific deferred maintenance issues associated with our sulfur exchanger. The work required disassembling the sulfur exchanger, replacing many tubes and repairing plate damage. As of November 15, 2007, the BEC Treating Plant has been down for approximately 20 days and is anticipated to be back up soon.

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

Overview

We are a Delaware limited partnership engaged in the business of (i) gathering, compressing, treating, processing, transporting and selling natural gas, fractionating and transporting natural gas liquids, or NGLs, which we call our “midstream” business, (ii) acquiring, developing and producing interests in oil and natural gas properties, which we call our “upstream” business, and (iii) acquiring and managing fee minerals and royalty interests across the United States, which we call our “minerals” business. The Partnership conducts its business in six segments, three within the midstream business, one that is the upstream business, one that is the minerals business, and one for corporate business.

The Partnership conducts, evaluates and reports on its midstream business within three distinct segments – the Texas Panhandle Segment, the South Texas Segment, and the East Texas and Louisiana Segment (formerly referred to by us as our Southeast Texas and North Louisiana Segment). The Partnership’s Texas Panhandle Segment consists of gathering and processing assets acquired from ONEOK, Inc. on December 1, 2005. The Partnership’s East Texas and Louisiana Segment consists of a non-operated 25% undivided interest in a processing plant and a non-operated 20% undivided interest in a connected gathering system, a 100% interest in the Brookeland and Masters Creek processing plants in East Texas, a 100% interest in the Roberts County processing plant and related gathering systems, and certain gathering systems and related compression and processing facilities in East Texas and North Louisiana. The Partnership’s South Texas Segment consists of gathering systems and related compression and processing facilities in South Texas.

The Partnership conducts, evaluates and reports on its upstream business as one segment. The Partnership’s Upstream Segment includes operated wells Escambia County, and the two treating facilities, one natural gas processing plant and related gathering systems that are inextricably intertwined with ownership and operation of the wells. The Upstream Segment also includes operated and non-operated wells that are located in East and South Texas.

Currently, based on Segment Gross Profit (as defined in Note 12 to our Unaudited Condensed Consolidated Financial Statements included in Part I – Item 1), our midstream business comprises approximately 65% of our business (with the Texas Panhandle Segment accounting for 47% of our business, the South Texas Segment accounting for 4% of our business, and the East Texas and Louisiana Segment accounting for 14% of our business), our upstream business comprises approximately 27% of our business, and our minerals business comprises approximately 8% of our business. We intend to acquire and construct additional assets in both our midstream and upstream businesses, and we intend to be opportunistic with potential acquisitions for our minerals business. We have an experienced management team dedicated to growing, operating and maximizing the profitability of our assets. Our management team is experienced in gathering and processing natural gas, operation of oil and natural gas properties and assets, and management of royalties and minerals.

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 – Midstream Segment

Our results of operations for our Texas Panhandle Segment, South Texas Segment, East Texas and Louisiana Segment 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 (by the nature of the commodity price risk) as fee-based, percent-of-proceeds, fixed recovery and keep-whole, described in greater detail as follows:

	•		Fee-Based Arrangements. Under these arrangements, we generally are paid a fixed cash fee per unit volume 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 September 30, 2007, these arrangements accounted for approximately 43% 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 September 30, 2007, these arrangements accounted for about 29% 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 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 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 September 30, 2007, these arrangements accounted for approximately 20% 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 improved 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 September 30, 2007, these arrangements accounted for about 8% of our natural gas volumes. Approximately 73% of these keep-whole arrangements have fee components.

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 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, consisting of a natural gas liquids exchange agreement and two 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.

Cimarex Energy. We are a party to a gas purchase agreement with Prize Operating Company (Cimarex Energy Co.), 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 Prize (Cimarex) and us.

Our Operations – Upstream Segment

The Upstream Segment consists of operated and non-operated working interests in producing and non-producing wells located primarily in Alabama, East Texas, and South Texas. We are the operator of a substantial portion of these interests. The significant assets in these regions are summarized in the following paragraphs.

Alabama– Substantially all of our upstream interests in Alabama are located in or near Escambia County, Alabama and were acquired in July 2007 in the EAC acquisition. We own 31 operated productive wells in three primary fields (Big Escambia, Flomaton, and Fanny Church) which produce from the Smackover formation. The fluids from these wells are sour, and the removal of the hydrogen sulfide results in the production of sulfur, which is sold. The Upstream Segment also includes several midstream assets in Alabama, including 2 hydrogen sulfide treatment facilities with 100 MMcf/d of capacity, one natural gas processing plant with 40 MMcf/d of capacity, and related gathering systems that are inextricably intertwined to our ownership of wells in Escambia County.

East Texas– Our East Texas upstream assets were acquired in July 2007 in the Redman Acquisition. We own 33 operated and 78 non-operated productive wells in East Texas. In East Texas, our interests are in four primary fields which produce from the Smackover formation: Northeast Edgewood, Ginger, Fruitvale, and Eustace. As is the case with the Escambia wells, the fluids from the Smackover formation contains significant concentrations of hydrogen sulfide which must be removed prior to sale.

South Texas– Our South Texas upstream assets were acquired in July 2007 in the Redman Acquisition. We own 12 operated productive wells in South Texas, all inside the Jourdanton Field, which produce from the Edwards formation, and we have identified 5 recompletion and 5 infill well opportunities in the Edwards zones.

The results of operations of these assets are dependent on the volumes of hydrocarbons we produce, the costs required to produce them, and the price for which we are able to sell them. In the cases of the Alabama and East Texas Smackover, production must undergo extensive processing before the products are saleable. In Alabama, we operate the Big Escambia treating facility and processing plants, and the Flomaton treating facility. Our ability to sell products from the Alabama fields is dependent upon our ability to successfully operate these facilities. In East Texas, production from the Smackover formation is gathered, processed and treated by Regency Gas Services. Our ability to sell products from these wells is dependent on Regency’s ability to operate their facilities.

The operating and capital costs associated with our Upstream Segment are a function of our ability to design, construct, maintain, operate, and repair the wells and facilities under our control (see “Risks Related to Our Business” and “Quantitative and Qualitative Disclosures About Market Risk”). To accomplish this, we employ a staff of experienced engineering and operations personnel who are supervised by members of our management team. These costs are also a function of the costs of the goods and services we require to conduct these activities, and these costs are significantly beyond our control (see “Risks Related to Our Business”). Higher oil and natural gas commodity prices generally have the effect of increasing the demand for these goods and services, which can result in higher prices for them.

Substantially all of the products we sell are sold under contracts in which the sales prices reflect market prices. We currently do not sell any of our products under long-term fixed price arrangements. Therefore, the results of our operations are dependent upon market prices for the products we sell, and these prices are beyond our control (see “Risks Related to Our Business” and “Quantitative and Qualitative Disclosures About Market Risk”).

Our Operations – Minerals Segment

The Minerals Segment is comprised of mineral, royalty and overriding royalty interests that were acquired in the Montierra and MacLondon Acquisitions in April and June 2007, respectively. In addition, this segment also includes non-operated working interests in two wells that were acquired in the Montierra Acquisition and that continue to be tracked as part of the Minerals Segment for legacy reasons and for ease of administration. The Minerals Segment interests are a diversified set of fee mineral and royalty interests in over 5.6 million gross mineral acres (430,000 net mineral acres), and over 2,500 productive wells. These interests are located in 13 basins across 17 states in the United States.

The interests in the Minerals Segment are non-cost-bearing; we do not bear the costs of operating the existing wells or drilling new ones. The wells are operated by others who control the timing and occurrence of well workover, recompletion or drilling activity. In most instances, we do not own the executive rights of our mineral interests, so we also do not control the timing or terms of leasing activity on the interests, although we do receive a portion of the bonus and royalty income that derives from these activities.

The result of operations of the Minerals Segment is dependent on the quantity of hydrocarbons produced from the wells in which we own an interest, and the price for which the products are sold. Since our interests are non-cost-bearing, we receive the benefit of drilling and other production enhancement activities conducted by the operators of the wells at no cost to us. Because our position is highly diversified, drilling and other production enhancement activities are continually occurring on acreage in which we own an interest. We have observed that this can result in ongoing reserve and production replacement. We have termed this ongoing cost-free reserve and production replacement of our mineral and royalty interests as the “regeneration effect”.

Our results in the Minerals Segment are not directly affected by the costs of drilling and production activities, but higher costs that effect the exploration and production industry may have the effect of reducing drilling and workover activity levels, and this may reduce the regeneration effect that we observe.

As in the case of our Upstream segment, the results of the Minerals segment is subject to fluctuations in oil, natural gas and natural gas liquids prices (see “Risks Related to Our Business” and “Quantitative and Qualitative Disclosures About Market Risk”).

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

Minerals Volumes.Our Minerals Segment assets are comprised of royalty, overriding royalty, non-producing mineral, and a couple of legacy non-operating working interests, and therefore, we do not operate any of these properties. In order to maintain or increase our cash flows from our Minerals 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 the two wells in which we own legacy working interests). The level of drilling and recompletion activity conducted by the operators of our mineral 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 yielding us a cost-free “regeneration effect” on mineral and royalty interests. We monitor the additional production volumes that we realize from regeneration, and we use this information to make adjustments to our reserves estimates on a regular basis. These adjustments to our reserves (as a result of the regeneration effect) are important measures of the performance of our Minerals Segment.

Segment Gross Profit. We define Segment Gross Profit (in evaluating our Midstream business and its three segments) as total revenues of the applicable segment or whole, as applicable less cost of natural gas and NGLs and other cost of sales for the applicable segment or whole, as applicable. Our margins may be positively impacted to the extent the price of NGLs increase in relation to the price of natural gas and may be adversely impacted to the extent the price of NGLs decline in relation to the price of natural gas. We refer to the price of NGLs in relation to the price of natural gas as the fractionation spread. Because of the hedging program of our commodity risk, we have been able to develop overall favorable fractionation spreads within a range and we believe our unit margins will not be subject to significant downward fluctuations if commodity prices were to change in an unfavorable relationship.

Risk Management. We conduct risk management activities to mitigate the effect of commodity price and interest rate fluctuations on our cash flows. Our primary method of risk management in this respect is entering into derivative contracts. To execute and evaluate the performance of these activities, we have formed a Risk Management Committee which is comprised of several members of our senior management team and other key employees. In addition to establishing the procedures and controls associated with risk management activities, this committee meets regularly to review the hedge portfolio and make recommendations for additional hedges. They routinely estimate the potential effect of price and interest rate fluctuations on the expected future cash flows associated with our existing operations, and they evaluate whether the hedges sufficiently mitigate the effect of these fluctuations.

Midstream 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.

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

Minerals Operating Expenses. We do not incur any operating costs associated with our Minerals Segment due to the non-cost-bearing nature of the mineral and royalty assets.

Adjusted EBITDA. We define Adjusted EBITDA as net income (loss) plus income tax provision, interest-net (including both realized and unrealized interest rates risk management activities), depreciation, depletion and amortization expense, other operating expense, other non-cash operating and general and administrative expenses (including non-cash compensation related to our equity-based compensation program) less non-realized revenues risk management instrument gain (loss) activities and other income/(expense). Adjusted EBITDA is useful in determining our ability to sustain or increase distributions. By excluding unrealized derivative gains (losses), a non-cash charge which represents the change in fair market value of our executed derivative instruments and is independent of our assets’ performance or cash flow generating ability, we believe Adjusted EBITDA reflects more accurately our ability to generate cash sufficient to pay interest costs, support our level of indebtedness, make cash distributions to our unitholders and general partner and finance our maintenance capital expenditures. We further believe that Adjusted EBITDA also describes more accurately the underlying performance of our operating assets by isolating the performance of our operating assets from the impact of an unrealized, non-cash measure designed to describe the fluctuating inherent value of a financial asset. Similarly, by excluding the impact of non-recurring discontinued operations, Adjusted EBITDA provides users of our financial statements a more accurate picture of our current assets’ cash generation ability, independently from that of assets which are no longer a part of our operations.

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

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 in 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 certain entities and fee minerals, royalties and working interest properties from Montierra Minerals & Production, L.P. and NGP-VII Income Co-Investment Opportunities L.P.

On April 30, 2007, we completed the acquisition of (by direct acquisition or acquisition of certain entities) certain fee minerals, royalties and working interest properties from Montierra Minerals & Production, L.P. and NGP-VII Income Co-Investment Opportunities, L.P. (the “Montierra Acquisition”). Montierra and Co-Invest received as consideration, subject to adjustment, 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, as of the date of the Montierra Acquisition, of approximately 4.5 billion cubic feet of natural gas and 3.5 million barrels of crude oil.

Acquisition of Laser Entities

On May 3, 2007, we acquired all of the non-corporate interests of Laser Midstream Energy, LP and certain subsidiaries (the “Laser Acquisition”). Laser received as consideration, subject to adjustment, a total 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”). MacLondon received as consideration a total of 789,474 common units, subject to adjustment.

Acquisition of Escambia Entities

On July 31, 2007, we completed the acquisition of Escambia Asset Co., LLC and Escambia Operating Company, LLC (the “EAC Acquisition”). The sellers received as consideration, subject to adjustment, a total of $224.0 million in cash and 689,857 in Eagle Rock Energy common units. The assets subject to this transaction included 31 operated productive wells in Escambia County, Alabama with net production of approximately 3,300 Boepd and proved reserves at the time of acquisition of approximately 11.8 MMBoe, of which 93% is proved developed producing. The transaction also included two treating facilities with 100 MMcf/d of capacity, one natural gas processing plant with 40 MMcf/d of capacity and related gathering systems.

Acquisition of Redman Entities (and certain related assets)

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”). Redman received as consideration, subject to adjustment, 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 Acquisition included 45 operated and 78 non-operated productive wells mainly located in East and South Texas with a net production of 1,810 Boepd and combined proved reserves at the time of acquisition of 8.1 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 first three quarters of 2007 to our critical accounting policies as 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.

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. The impairment expense is included in depreciation, depletion and amortization on the consolidated statement of operations.

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 and nine month periods ended September 30, 2007 and 2006:


	Three Months						Nine Months
	Ended September 30,						Ended September 30,
*($ in thousands)*	2007			2006			2007			2006
Sales of natural gas, NGLs, condensate and oil sales	$	253,056		$	132,907		$	554,797		$	373,001
Compression, gathering and processing		7,723			4,549			19,271			10,495
Minerals and royalty income		6,009			—			9,201			—
Gain/(loss) on realized risk management instrument		(177	)		(449	)		4,324			122
Gain/(loss) on unrealized risk management instrument		8,865			14,480			(30,533	)		(21,331	)
Other income		1,388			109			1,007			436

Total operating revenue		276,864			151,596			558,067			362,723

Purchase of natural gas and NGLs		196,839			100,723			451,838			288,881


Total segment gross profit(a)		80,025			50,873			106,229			73,842

Operating and maintenance expense		16,883			9,094			36,017			23,892
Taxes other than income		2,746			651			4,364			1,045
General and administrative expense		7,196			2,446			16,587			8,063
Other operating expense		220			—			1,931			—
Depreciation, depletion and amortization		25,105			11,244			50,883			31,459
Interest-net, including realized risk management instrument		10,490			7,730			27,079			22,892
(Gain)/loss on unrealized risk management interest rate instrument		8,429			6,600			3,555			(2,639	)
Other (income)/expense		(767	)		—			(879	)		—
Income tax provision		352			236			772			744


Net income (loss)	$	9,371		$	12,872		$	(34,080	)	$	(11,614	)


Adjusted EBITDA(b)	$	45,155		$	24,202		$	81,407		$	62,173


(a)		Defined as operating revenues less the purchase of natural gas and NGLs expense. Operating revenues include both realized and unrealized revenue risk management activities.


(b)		Defined as net income (loss) plus income tax provision, interest-net (including both realized and unrealized interest rates risk management activities), depreciation, depletion and amortization expense, other operating expense, other non-cash operating and general and administrative expenses (including non-cash compensation related to our equity-based compensation program) less non-realized revenues risk management instrument gain (loss) activities and other income/(expense). Other operating expense for 2007 includes legal arbitration settlement recorded in 2007 that relates to Panhandle Segment assets before the Partnership owned them, executive separation cost and delay fees related to registration rights on certain unitholders.

The following table reconciles Total Segment Gross Profit to net income (loss):


	Three Months					Nine Months
	Ended September 30,					Ended September 30,
	2007			2006		2007			2006
*($ in thousands)*
Total segment gross profit:	$	80,025		$	50,873	$	106,229		$	73,842
*Less:*
Operations and maintenance expense		16,883			9,094		36,017			23,892
Taxes other than income		2,746			651		4,364			1,045
General and administrative expense		7,196			2,446		16,587			8,063
Other operating expense		220			—		1,931			—
Depreciation, depletion and amortization		25,105			11,244		50,883			31,459
Interest-net including realized risk management instrument		10,490			7,730		27,079			22,892
Gain/(loss) on unrealized risk management interest related instrument		8,429			6,600		3,555			(2,639	)
Other (income)/expense		(767	)		—		(879	)		—
Income tax provision		352			236		772			744

Net income (loss)	$	9,371		$	12,872	$	(34,080	)	$	(11,614	)

The following table reconciles Adjusted EBITDA to net income (loss):


	Three Months					Nine Months
	Ended September 30,					Ended September 30,
	2007			2006		2007			2006
*($ in thousands)*
Adjusted EBITDA:	$	45,155		$	24,202	$	81,407		$	62,173
*Less:*
Income tax provision		352			236		772			744
Other (income)/expense		(767	)		—		(879	)		—
(Gain)/loss on unrealized risk management interest related instrument		8,429			6,600		3,555			(2,639	)
Interest-net including realized risk management instrument		10,490			7,730		27,079			22,892
Depreciation, depletion and amortization		25,105			11,244		50,883			31,459
Other operating expense		220			—		1,931			—
Restricted units non-cash amortization expense		820			—		1,613			—
*Plus:*
Gain/(loss) revenue risk management instruments-unrealized		8,865			14,480		(30,533	)		(21,331	)


Net income (loss)	$	9,371		$	12,872	$	(34,080	)	$	(11,614	)

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

Financial results for the quarter ended September 30, 2007 included activities of the Montierra (acquired April 30, 2007), Laser (May 3, 2007), MacLondon (June 18, 2007), Redman (July 31, 2007), and EAC (July 31, 2007) business combinations. The timing of these acquisitions affects the comparison between quarters.

Operating revenues for sales of natural gas, NGLs, condensate and oil for the third quarter of 2007 increased by $120.2 million, representing a 90% increase from the third quarter of 2006 due primarily to the addition of natural gas, oil, NGLs and condensate revenues from the assets acquired during the current year, increased volumes on the Tyler County pipeline extension and Red Deer plant placed in service in 2007 and improved NGL and condensate pricing by comparison to the third quarter of 2006.

Compression, gathering and processing for third quarter 2007 is $7.7 million as compared to $4.5 million for the third quarter 2006, or an increase of 70%. This increase reflects primarily the increase in fee contracts for gas compression and conditioning as well as the inclusion of the assets acquired in the Laser Acquisition completed in the current year and the impact of the completion of the Red Deer plant and Tyler County Pipeline extension in 2007.

Realized risk management activities for the three-month period ended September 30, 2007 resulted in a $0.2 million loss compared to $0.4 million loss for the three-month period ended September 30, 2006. Unrealized risk management activities for the September 2007 quarter resulted in an $8.9 million gain versus a $14.5 million gain in the September 2006 quarter. The results of these risk management activities reflect the movement in future period prices during the applicable quarter on open derivative positions as well as amortization in the applicable quarter for put premiums as the underlying options expire. As the forward price curves for our hedged commodities shift in relation to caps, floors, swap and strike prices at which we have executed our derivative instrument(s), the fair value of such instrument(s) change(s) through time. The mark-to-market net unrealized gain 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.

Mineral and royalty income from our Minerals Segment contributed $6.0 million to operating revenue during the September 2007 quarter as a result of the Montierra and MacLondon Acquisitions during the second quarter, 2007.

Purchase of natural gas and NGLs increased by $96.1 million, representing a 95% increase from the third quarter of 2006. This increase is primarily a result of the addition of gas purchase contracts from the Laser Acquisition completed in second quarter, 2007 and the increase in natural gas and natural gas liquids prices and volumes in the current quarter as compared to last year’s third quarter.

Total Segment Gross Profit increased to $80.0 million for the current quarter compared to $50.9 million for the third quarter of 2006. The increase is primarily the result of this year’s acquisitions, higher commodity prices and volumes in the third quarter of 2007, and the contributions of the Red Deer plant and Tyler County Pipeline extension in the third quarter of 2007.

Operations and maintenance expense increased in the current quarter by $7.8 million compared to the third quarter of 2006, representing an 86% increase. This increase is primarily on account of the addition of operations of the newly-acquired midstream and upstream assets and higher operating costs for the Texas Panhandle Segment primarily due to the completion of the Red Deer plant and the higher maintenance expense.

Taxes other than income taxes are $2.7 million for the current quarter, up 321% as compared to $0.7 million for the third quarter of 2006. The increase in taxes is largely from the severance and production taxes associated with the additional assets from our 2007 acquisitions in the Upstream and Mineral Segments and also from additional property taxes on Midstream Segment assets acquired in the Laser Acquisition in 2007.

General and administrative expenses also increased $4.7 million, 194%, primarily from the addition of infrastructure to support the acquisitions, 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. The current quarter activities also included expenses related to partnership units, registration rights filings, and higher employee incentive amounts.

The increase of $13.9 million in depreciation, depletion and amortization (including depletion of $9.7 million) for current year’s quarter, a 123% increase over last year’s third quarter, is primarily from the addition during 2007 of a substantial amount of capital assets, including the Red Deer plant and Tyler County Pipeline extension, assets from the Laser and Montierra Acquisitions and assets in the Upstream and Mineral Segments.

Interest-net (including realized risk management instrument) primarily reflects 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 $2.8 million, is from increased funded debt and a higher add-on on rate.

Unrealized risk management interest rate instrument for the September 2007 quarter of $8.4 million net loss 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.

Other income is $0.8 million and primarily represents equity in earnings of unconsolidated non-affiliate during the period that was part of the Montierra Acquisition.

State income taxes recorded during the September 2007 quarter of approximately $0.4 million reflects the Texas Margin Tax (see Note 13) and was recorded as a deferred tax liability. This amounts compares to $0.2 million recorded in September, 2006 quarter.

Nine Months Ended September 30, 2007 Compared with Nine Months Ended September 30, 2006

Financial results for the nine months ended September 30, 2007 included activities of the Montierra (acquired April 30, 2007), Laser (May 3, 2007), MacLondon (June 18, 2007), Redman (July 31, 2007), and EAC (July 31, 2007) business combinations. The timing of these acquisitions affects the comparison between quarters.

Operating revenues for sales of natural gas, NGLs, condensate and oil sales for the nine months ended September 30, 2007 increased by $181.8 million, representing a 49% increase from the nine months ended September 30, 2006 due primarily to the addition of natural gas, NGLs, condensate and oil revenues from the assets acquired during the current year, a full nine months of the Brookeland and MGS acquisitions (acquired during 2006), increased volumes on the Tyler County Pipeline extension and Red Deer plant completed in 2007 and improved NGL and condensate pricing with respect to the first nine months of 2006. Partially offsetting these favorable impact of revenue for the nine months ended September 30, 2007, as compared to the nine months ended September 30, 2006, was the unscheduled maintenance shutdown and turnaround of two large processing plants in the Texas Panhandle Segment.

Compression, gathering and processing for nine months ended September 30, 2007 is $19.3 million as compared to $10.5 million for the nine months ended September 30, 2006. The increase is largely from the assets acquired in the Laser Acquisition in 2007 and increase fee agreements from the Tyler County Pipeline extension and Red Deer projects completed in 2007.

Realized risk management activities for nine months ended September 30, 2007 resulted in a gain of $4.3 million compared to $0.1 million for the nine months ended September 30, 2006. Unrealized risk management activities for the nine months ended September 30, 2007 resulted in a loss of $30.5 million compared to a loss of $21.3 million in the nine months ended September 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 favorable 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.

Mineral and royalty income from our Minerals Segment contributed $9.2 million during the nine months ended September 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 $163.0 million, 56% increase, reflecting primarily the addition of Laser’s gas purchase contracts during the second quarter of 2007, inclusion of a full nine months of the Brookeland and MGS acquisitions and the increase in natural gas liquids in the current period as compared to last year.

Total Segment Gross Profit increased to $106.2 million for the nine months ended September 30, 2007 compared to $73.8 million for the nine months ended September 30, 2006. The increase is primarily from the positive addition of the acquisitions in 2007, inclusion of the Brookeland and MGS acquisitions for a full nine months, the completion of the Tyler County Pipeline extension and Red Deer Plant in 2007 and improved pricing in NGLs and condensate.

Operations and maintenance expense increased in the nine months ended September 30, 2007 by $12.1 million compared to the nine months ended September 30, 2006, primarily from the operations of the Laser, Redman and EAC acquisitions, as well as higher costs in the second quarter 2007 in our Texas Panhandle Segment primarily related to the unscheduled maintenance shutdown and turnaround of two of our large processing plants during the first six months of 2007 and the start up of the Red Deer plant.

Taxes other than income for the current nine-month period is $4.4 million as compared to $1.0 million for the nine months period of 2006. The increase is primarily due to the severance/production taxes related to the EAC and Redman acquisitions as well as the Mineral segment acquisitions.

General and administrative expenses also increased by $8.5 million primarily from the addition of infrastructure to support the acquisitions during 2007, 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, increased employee incentive amounts and increased related insurance expense.

Other operating expense reflects the arbitration award recorded during the first nine 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 and $0.2 million charge for delay charges in registration rights for certain common units. In addition, approximately $0.3 million relates to a separation expense accrual recorded during the current quarter.

Increase of $19.4 million in depreciation, depletion and amortization for nine months ended September 30, 2007 is primarily from the impact of the 2007 acquisitions including $11.8 million of depletion expense incurred in 2007 from the upstream and mineral segments acquisitions. Also, there is associated depreciation on construction projects completed and placed in service since September 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 $4.2 million, is from increased funded debt, increased overall base interest rate and a higher add-on on rate.

Other income is $0.9 million and represents primarily equity in earnings of unconsolidated non-affiliate that was part of the Montierra Acquisition.

Unrealized risk management interest related instrument for the nine months ended September 30, 2007 of $3.6 million net gain 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 nine months ended September 30, 2007 quarter of approximately $0.8 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 initiating remediation efforts at certain sites in the Texas

Panhandle and expect to conclude our efforts in 2008 or 2009. The costs 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 September 30, 2007. 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 $0.5 million to $0.9 million in costs and improvements 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. The policy has a $5.0 million limit subject to a $0.5 million deductible. We expect to renew this policy on an annual basis at a cost of around $400,000 per year, payable in the December prior to each renewal year, including December, 2007.

Certain assets of the Partnership’s upstream segment that were obtained as part of the Redman Acquisition are the subject of pre-existing soil contamination and are currently being remediated and others are subject to ongoing monitoring for groundwater contamination and negative results from the monitoring, if reported, may necessitate remediation of groundwater contamination, for which the Partnership has accrued reserves in the amount of $0.3 million. In addition, certain assets of the Partnership’s upstream segment that were obtained as part of the EAC Acquisition are either the subject of pre-existing soil contamination or groundwater contamination and are currently excavating or otherwise remediating the soil contamination and pumping, treating and re-injecting groundwater to address the groundwater contamination, or are subject to ongoing monitoring for groundwater contamination and may necessitate remediation of groundwater contamination or soil contamination, for which the Partnership has accrued reserves in the amount of $1.8 million.

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, upstream, or mineral assets 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

From January 1, 2006 through September 30, 2007, there have been several key events that have had major impacts on our cash flows. They are:

	•		the construction and installation of 1.7 miles of 10-inch diameter and 12.6 miles of 12-inch diameter natural gas pipeline called our Tyler County Pipeline Extension project, completed in March 2007 at a cost of $24.2 million, plus the expansion of this pipeline system, called our Tyler County Pipeline Phase II project at an incremental cost of $2.8 million, completed in October 2007;

	•		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 which the sellers received $4.7 million in cash and 1,125,416 units in Eagle Rock Pipeline, L.P. (which converted to 809,329 of our common units at the time of our IPO);

	•		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 which the sellers received 6,390,400 of our common units, subject to adjustment, and the extinguishment of $6.0 million 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 which the sellers received $110.0 million in cash and 1,407,895 of our common units, subject to adjustment;

	•		the acquisition of certain fee minerals, royalties and non-operated working interest properties from MacLondon Energy, L.P. on June 18, 2007 for 789,474 of our common units, subject to adjustment;

	•		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;

	•		the refurbishment and installation of a 20 MMcf/d processing facility located in Roberts County, Texas called our Red Deer Processing Plant, at a cost of $17.4 million and put in service on June 21, 2007.

	•		the acquisition of Escambia Asset Co, LLC and Escambia Operating Co, LLC on July 31, 2007, for which the sellers in the transaction received approximately $224.0 million in cash and 689,857 in Eagle Rock common units, subject to adjustment;

	•		the acquisition of Redman Energy Holdings, L.P. and Redman Energy Holdings II, L.P. and certain assets owned by NGP Income Co-Investment Opportunities Fund II, L.P. on July 31, 2007, for which the sellers in the transaction received as consideration a total of 4,428,334 newly-issued Eagle Rock common units and $83.8 million in cash, subject to adjustment; and

	•		the private placement of 9,230,770 common units among a group of institutional investors for total cash proceeds of approximately $204.0 million on July 31, 2007. The proceeds from the private offering were used to partially fund the cash portion of the purchase price of the EAC and Redman Acquisitions.

On February 7, 2007, Eagle Rock Energy declared a cash distribution of $0.3625 per common 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 general partner or Holdings (on the general partner units or subordinated units) 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.

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 common unitholders who acquired common units in either the Montierra Acquisition or the Laser Acquisition. No distribution was made to the general partner or Holdings (on the general partner units or subordinated units) for the quarter.

On July 31, 2007, Eagle Rock Energy completed three acquisitions in its midstream and upstream businesses – the EAC and Redman Acquisitions. In the aggregate, the EAC and Redman Acquisitions resulted in the payment of $307.8 million in cash, including working capital adjustments, and the issuance of 5,905,922 newly-issued common units, subject to adjustment. Additionally, Eagle Rock Energy completed the private placement of 9,230,770 common units to third-party investors, for total cash proceeds of approximately $204.0 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 $106.0 million from its revolver 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 common unit for the second quarter ending June 30, 2007. The distribution was paid August 14, 2007 to common unitholders of record as of August 8, 2007, not including common unitholders who acquired common units in the MacLondon, EAC or Redman Acquisitions (see Note 4). No distribution was made to the general partner or Holdings (on the general partner units or subordinated units) for the quarter.

On November 8, 2007, the Partnership declared a cash distribution of $0.3675 per unit for the third quarter ended September 30, 2007. The distribution was paid November 14, 2007 to all unitholders of record as of November 8, 2007, including the general partner and Holdings (on the general partner units and subordinated units, respectively).

Working Capital.Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. As of September 30, 2007, working capital was (current liabilities exceeded current assets) $53.2 million as compared to a $12.1 million (positive) balance as of December 31, 2006.

The net increase in working capital of $53.2 million from December 31, 2006 to September 30, 2007, resulted primarily from the following factors:

	•		cash balances and marketable securities, net of Due to Affiliate increased overall by $56.5 million and was impacted primarily from the working capital balances acquired in the acquisitions during the year, from the results of operations, timing of capital expenditures payments, financing activities including our debt activities as well as members’ equity distributions. The Due to Affiliate liability of $17.4 million as of September 30, 2007 is owed to Eagle Rock Energy G&P, LLC;

	•		trade accounts receivable increased by $78.4 million primarily from the receivables activities from the acquisitions completed during the 2007 year;

	•		risk management net working capital balance increased by a net $0.4 million as a result of the changes in the mark-to-market unrealized positions and fair value changing of the option premiums;

	•		accounts payable increased by $81.0 million from December 31, 2006 primarily as a result of the payables activities from the acquisitions during the current year, activities and timing of payments, including capital expenditures activities; and

	•		accrued liabilities increase of $12.8 million primarily reflects unbilled expenditures related primarily to capital expenditures and activities from the acquisitions during the year.

Cash Flows Nine Months 2007 Compared to Nine Months 2006

Cash Flows from Operating Activities.Increase of $36.8 million for the nine months ended September 30, 2007 as compared to the nine months ended September 30, 2006 is the result of increased working capital of $39.2 million between periods plus higher depreciation, depletion and amortization of $19.4 million, offset partially by an increase in net loss of $22.5 million. The increase in the non-cash charge of depreciation, depletion and amortization is largely from the acquisitions during 2007.

Cash Flows Used in Investing Activities.Cash flow used in investing activities for the nine months ended September 30, 2007 as compared to the nine months ended September 30, 2006 increased $341.3 million. The increase is largely from the cash portion of the acquisitions in 2007 of $326.4 million and higher capital expenditures of $31.1 million (largely the completion of the Tyler County Pipeline extension and the Red Deer processing plant). These are offset by overall cash acquired in the 2007 acquisitions of $23.8 million.

Cash Flows Provided by (Used in) Financing Activities.Cash flow provided by financing activities for the nine months ended September 30, 2007 was $455.2 million compared to a source of cash of $74.4 million for the nine months ended September 30, 2006. The increase in the source of cash is primarily from the proceeds from equity issuance of $331.5 million, increase in net proceeds from revolver and long term debt of $166.9 million (primarily related to the acquisitions during 2007). Partially offsetting these increases in sources of cash were an increase of distributions in 2007 by $24.1 million and an increase of contributed equity in 2007 from members of $98.6 million.

Capital Requirements

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

As an operator of upstream assets and as a working interest owner, our capital requirements have increased to maintain those properties and to replace depleting resources. We anticipate that we will meet these requirements through cash generated from operations, equity issuances, or debt incurrance; 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 $67.6 million in total in 2007 on our existing assets. As of September 30, 2007, we have spent approximately $54.9 million primarily in the Tyler County Pipeline extension, Red Deer Processing Plant project, and various well connections and maintenance capital (in both our Upstream and Midstream Segments).

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

	•		growth capital expenditures, which are made to acquire additional assets to increase our business, to expand and upgrade existing systems and facilities or to construct or acquire similar systems or facilities, or grow our production in our upstream business; or

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

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

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

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 September 30, 2007, we had $299.3 million outstanding under the term loan, $261.9 million outstanding under the revolver and $12.4 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 $26.4 million of unused capacity under the agreement as of September 30, 2007.

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

Debt Covenants. At September 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 September 30, 2007. All of the $561.1 million of term loans outstanding on September 30, 2007 are scheduled for interest rate resets on one, two, or three-month intervals. Interest rates were last reset for all amounts outstanding on September 30, 2007.


($ in millions)	Payments Due by Period
Contractual Obligations	Total		2007		2008		2009		2010-2011		Thereafter
Long-term debt (including interest)(1)	$	760.3	$	38.2	$	43.9	$	43.9	$	634.3	$	0.0
Operating leases		5.8		0.9		0.9		0.9		0.7		2.4
Purchase obligations(2)		—		—		—		—		—		—

Total contractual obligations	$	766.1	$	39.1	$	44.8	$	44.8	$	635.0	$	2.4


(1)		Assumes average base interest rate of 4.84%, including impact of current interest rate swaps, 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 September 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 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 upstream, mineral and midstream operations. In our Midstream Segment, our activities produce a long position in natural gas liquids and condensate, but produce a short position in natural gas a s a result of our Fixed Recovery and Keep Whole arrangements. We expect this condition to persist for the foreseeable future. In our Upstream and Minerals Segments, we have a long position in crude oil,, natural gas, natural gas liquids and sulfur. From a risk management perspective, we manage the risk associated with the total portfolio. Therefore, we net the Midstream Segment’s short natural gas position against the Upstream and Minerals Segments’ long natural gas position. This results in a net long natural gas position, and this net position is what we manage through our risk management activities. 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 that risk. These hedges are only intended to mitigate the risk associated with our 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 (propane and heavier), have generally been well-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.

Disclosure Controls

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 September 30, 2007, to provide reasonable assurance the information required to be disclosed by us in the reports we file or submit under the Exchange Act of 1934, as amended, are 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.

Internal Control over Financial Reporting

In anticipation of becoming subject to the provisions of Section 404 of the Sarbanes-Oxley Act of 2002, we initiated in late 2006 and continue in 2007, an evaluation and program of documentation, implementation and testing of internal control over financial reporting. This program will continue through 2007, culminating with our initial Section 404 certification and attestation in early 2008. As of September 30, 2007, we have evaluated the effectiveness of our system of internal control over financial reporting, as well as changes therein, in compliance with Rule 13a-15 of the SEC’s rules under the Securities Exchange Act and have filed the certifications with this report required by Rule 13a-14.

In the course of that evaluation, we found no fraud, whether or not material, that involved management or other employees who have a significant role in our internal control over financial reporting and no material weaknesses. There have been no changes in our internal controls over financial reporting that occurred during the three months ended September 30, 2007, that have materially affected, or are reasonably likely to affect materially, our internal controls over financial reporting.

Restatement of Second Quarter Financial Statements

As disclosed previously on our current report on Form 8-K filed with the Commission on October 26, 2007, we were required to restate our financial statements for the quarter ended June 30, 2007, to correct accounting errors for revenue treatment relating to certain contracts and intra-segment transactions discovered in our second quarter 2007 financial statement information relating to certain of our subsidiaries acquired from Laser Midstream Energy, L.P. (“Laser”) during the second quarter of 2007. Our management determined that the accounting errors resulted in an overstatement of our 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. In connection with this restatement and in connection with the preparation and filing of a quarterly report on Form 10-Q/A, filed with the Commission on November 2, 2007 to effect this restatement, our management conducted a review of our internal controls as of June 30, 2007 and as of September 30, 2007. In both cases, our management, including our Chief Executive Officer and our Chief Financial Officer, concluded that our internal controls were effective as of those dates.

In coming to the conclusion that our internal controls were effective despite the required restatement, our Chief Executive Officer and Chief Financial Officer concluded that the revenue treatment errors resulting in the restatement of our financial statements for the quarter ended June 30, 2007, were isolated incidents relating solely to the acquired Laser subsidiaries and did not result from poor design or a general breakdown of the overall internal controls of Eagle Rock. In reaching this conclusion, management determined that the accounting errors had no adverse effect on our previously reported operating income, net loss, members’ equity, or cash flows for the affected period, which remained accurate as initially reported. We have instructed our accounting personnel at the acquired Laser subsidiaries on the appropriate review process and accounting treatment for these contracts and similar intra-segment transactions.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

Where we deem it prudent, we have established balance sheet reserves for estimated litigation costs and settlement awards. We also 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, the trading price of our common units could decline and you could lose all or part of your investment.

Certain risks apply to both our midstream business and our upstream business. To the extent any risk applies to one or the other, we have indicated the specific risk in the appropriate risk factor.

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 upstream 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 decide 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 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 three types of contractual arrangements that expose our cash flows to increases and decreases in the price of natural gas and NGLs: percentage-of-proceeds, fixed recovery 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 fixed recovery 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. 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. 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 September 30, 2007, our two largest suppliers were affiliates of Chesapeake Energy Corporation and Prize Operating Company, accounting for approximately 12% and 8% 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.

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 noncompliance 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.

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 $100.0 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 limited industry and geographic diversification in our midstream operations and in our upstream operated properties, 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 fee mineral and royalty upstream properties are well diversified geographically, all of our midstream assets are located in the Texas Panhandle, southeast and south Texas and Louisiana and all of our upstream operated properties are located in east and south Texas and Alabama. Due to our limited 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 midstream business 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.

Risks Inherent in an Investment in Us

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to make cash distributions to holders of our common units and subordinated units at the initial distribution rate under our cash distribution policy.

In order to make our cash distributions at our initial distribution rate of $0.3625 per common unit per complete quarter, or $1.45 per common unit per year, we will require available cash of approximately $26.0 million per quarter, or $104.2 million per year, based on the common units, restricted units under our Long Term Incentive Plan and subordinated units outstanding as of October 15, 2007. We may not have sufficient available cash from operating surplus each quarter to enable us to make cash distributions at the initial distribution rate under our cash distribution policy. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

	•		the fees we charge and the margins we realize for our services;

	•		the prices and level of production of and demand for, oil, natural gas, NGLs and condensate that we and others produce;

	•		the volume of natural gas we gather, treat, compress, process, transport and sell, the volume of NGLs we transport and sell, and the volume of oil and natural gas we and others produce;

	•		our operators’ and other producers’ drilling activities and success of such programs;

	•		the level of competition from other upstream and midstream energy companies;

	•		the level of our operating and maintenance and general and administrative costs;

	•		the relationship between oil, natural gas and NGL prices; and

	•		prevailing economic conditions.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

	•		the level of capital expenditures we make;

	•		the cost of acquisitions;

	•		our debt service requirements and other liabilities;

	•		fluctuations in our working capital needs;

	•		our ability to borrow funds and access capital markets;

	•		restrictions contained in our debt agreements; and

	•		the amount of cash reserves established by our general partner.

The amount of cash we have available for distribution to holders of our common units and subordinated units depends primarily on our cash flow and not solely on profitability.

The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

Assuming our ownership structure as of October 15, 2007, the amount of available cash we need to pay the minimum quarterly distribution for four quarters on our outstanding common units and restricted units under our Long Term Incentive Plan is $74.2 million. In addition, $1.2 million is a full distribution on our general partner units, and a full distribution on our subordinated units is $30.0 million, totaling $105.4 million with the full distribution on

outstanding common units and restricted units. The amount of our available cash generated during the year ended December 31, 2005 and the twelve months ended December 31, 2006 would not have been sufficient to allow us to pay the full minimum quarterly distribution on our common units and subordinated units for those periods; however, it would have been sufficient to allow us to pay the full minimum quarterly distribution on all of our common units.

We may not have sufficient available cash from operating surplus each quarter to enable us to make cash distributions at the initial distribution rate under our cash distribution policy.

Eagle Rock Holdings, L.P., owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner has conflicts of interest, which may permit it to favor its own interests.

Eagle Rock Holdings, L.P., owns and controls our general partner. Holdings is owned and controlled by the NGP Investors. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owners, the NGP Investors. Conflicts of interest may arise between the NGP Investors and their affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:

	•		neither our partnership agreement nor any other agreement requires the NGP Investors to pursue a business strategy that favors us;

	•		our general partner is allowed to take into account the interests of parties other than us in resolving conflicts of interest;

	•		the NGP Investors and its affiliates are not limited in their ability to compete with us;

	•		our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;

	•		our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and reserves, each of which can affect the amount of cash that is distributed to unitholders;

	•		our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units;

	•		our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

	•		our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

	•		our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;

	•		our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units;

	•		our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and

	•		our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

Affiliates of our general partner are not limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets, drilling opportunities or businesses which in turn could adversely affect our results of operations and cash available for distribution to our unitholders.

Affiliates of our general partner are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, affiliates of our general partner may acquire, construct or dispose of additional midstream, upstream or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets.

Cost reimbursements due to our general partner and its affiliates for services provided, which will be determined by our general partner, will be substantial and will reduce our cash available for distribution.

Prior to making distribution on our common units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf. These expenses will include all costs incurred by our general partner and its affiliates in managing and operating us, including costs for rendering corporate staff and support services to us, and there is no limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets, and not against our general partner or its assets. Our general partner therefore may cause us to incur indebtedness or other obligations that are nonrecourse to it. The partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

We expect that we will distribute all of our available cash to our unitholders. As a result, we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

In addition, because we distribute all of our available cash, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or our amended and restated credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.

Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units and subordinated units.

Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owners. Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner or otherwise free of fiduciary duties to us and our unitholders, including determining how to allocate corporate opportunities among us and our affiliates. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include:

	•		its limited call right;

	•		its voting rights with respect to the units it owns;

	•		its registration rights; and

	•		and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

Our partnership agreement restricts the remedies available to holders of our common units and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement:

	•		provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action in good faith, and our general partner will not be subject to any other or different standard imposed by our partnership agreement, Delaware law or any other law, rule or regulation or at equity;

	•		provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, and our partnership agreement specifies that the satisfaction of this standard requires that our general partner must believe that the decision is in the best interests of our partnership;

	•		provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

	•		provides that our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our unitholders if the resolution of a conflict is:

	•		approved by the conflicts committee of our general partner, although our general partner is not obligated to seek such approval;

	•		approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

	•		on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

	•		fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

In connection with a situation involving a conflict of interest, any determination by our general partner involving the resolution of the conflict of interest must be made in good faith, provided that, if our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general partner or its board of directors, and will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of Eagle Rock Energy G&P, LLC, the general partner of our general partner, chosen by the members of Eagle Rock Energy G&P, LLC. Furthermore, if the unitholders were dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its

affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

Control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our general partner or Eagle Rock Energy G&P, LLC, from transferring all or a portion of their respective ownership interest in our general partner or Eagle Rock Energy G&P, LLC to a third party. The new owners of our general partner or Eagle Rock Energy G&P, LLC would then be in a position to replace the board of directors and officers of Eagle Rock Energy G&P, LLC with its own choices and thereby influence the decisions taken by the board of directors and officers.

We may issue additional units without limited partner approval, which would dilute ownership interests.

Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

	•		our unitholders’ proportionate ownership interest in us will decrease;

	•		the amount of cash available for distribution on each unit may decrease;

	•		because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

	•		the ratio of taxable income to distributions may increase;

	•		the relative voting strength of each previously outstanding unit may be diminished; and

	•		the market price of the common units may decline.

Affiliates of our general partner, certain private investors and employees, may sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.

Management of Eagle Rock Energy G&P, LLC, the general partner of our general partner and the NGP Investors and their affiliates (both through their interests in Eagle Rock Holdings and Montierra), certain private investors, including the selling unitholders, and certain employees of Eagle Rock Energy G&P, LLC hold, as of October 15, 2007, an aggregate of 37,196,956 common units, including 527,021 common units which are subject to an overall three-year vesting requirement, and 20,691,495 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. The sale of these units in the public markets could have an adverse impact on the price of the common units or on any trading market that may develop. In addition, we have entered into registration rights agreements with certain of these investors, including Holdings, which require us to file with the SEC registration statements registering for resale to the public a substantial majority of these units.

Our general partner has a limited call right that may require limited partners to sell their units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, the limited partners may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Limited partners may also incur a tax liability upon a sale of units. As of October 15, 2007, our general partner and its affiliates owned approximately 17.6% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units, our general partner and its affiliates will own approximately 46.6% of our outstanding common units.

Liability of a limited partner may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. Limited partners could be liable for any and all of our obligations as a general partner if:

	•		a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

	•		the right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

The price of our common units may fluctuate significantly.

Prior to October 24, 2006, there was no public market for the common units. The lack of a liquid market in our common units may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

The market price of our common units may be influenced by many factors, some of which are beyond our control, including:

	•		our quarterly distributions;

	•		our quarterly or annual earnings or those of other companies in our industry;

	•		loss of a large customer;

	•		announcements by us or our competitors of significant contracts or acquisitions or change in management;

	•		changes in accounting standards, policies, guidance, interpretations or principles;

	•		general economic conditions;

	•		the failure of securities analysts to cover our common units or changes in financial estimates by analysts;

	•		future sales of our common units; and

	•		other factors described in these “Risk Factors.”

We will incur increased costs as a result of being a publicly traded partnership.

We have little history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses that we did not incur as a private company. In addition, the Sarbanes-Oxley Act of 2002, as well as new rules subsequently implemented by the SEC and the NASDAQ Global Market, have required changes in corporate governance practices of publicly traded companies. We expect these new rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors, create additional board committees and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly traded company reporting requirements. We

also expect these new rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance and it may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for our general partner to attract and retain qualified persons to serve on its board of directors or as executive officers. We estimate that we incur approximately $3.0 million of incremental costs per year associated with being a publicly traded partnership; however, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.

Tax Risks to Common Unitholders

The tax efficiency of our partnership structure depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service were to treat us as a corporation or if we become subject to a material amount of entity-level taxation for state tax purposes, it would reduce the amount of cash available for distribution.

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, which we refer to as the IRS, on this or any other tax matter affecting us.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates. Distributions would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to the limited partners. Because a tax would be imposed upon us as a corporation, our cash available for distribution would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. We will, for example, be subject to a new entity level tax on the portion of our income that is generated in Texas beginning in our tax year ending December 31, 2007. Specifically, the Texas tax will be imposed at a maximum effective rate of 0.7% of our gross income apportioned to Texas. Imposition of such a tax on us by Texas, or any other state, will reduce the cash available for distribution. The partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this report or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

Limited partners may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, limited partners will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if no cash distributions were

received from us. Limited partners may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

Tax gain or loss on disposition of our common units could be more or less than expected.

If a limited partner sells common units, the limited partner will recognize a gain or loss equal to the difference between the amount realized and the tax basis in those common units. Prior distributions to a limited partner in excess of the total net taxable income allocated for a common unit, which decreased the limited partner’s tax basis in that common unit, will, in effect, become taxable income to the limited partner if the common unit is sold at a price greater than their tax basis in that common unit, even if the price received is less than the original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if a limited partner sells units, the limited partner may incur a tax liability in excess of the amount of cash received from the sale.

Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income. If a limited partner is a tax-exempt entity or a foreign person, the limited partner should consult a tax advisor before investing in our common units.

We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to the limited partners. It also could affect the timing of these tax benefits or the amount of gain from sales of common units and could have a negative impact on the value of our common units or result in audit adjustments to tax returns of our limited partners.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income.

Limited partners will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our common units.

In addition to federal income taxes, a limited partner will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if the limited partner does not live in any of those jurisdictions. A limited partner will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, a limited partner may be subject to penalties for failure to comply with those requirements. We own assets and conduct business in several states. Many of these states currently impose a personal income tax. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is a limited partner’s responsibility to file all United States federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units.

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

The information required for this item is provided in Note 4 — Acquisitions and Note 7 - Members’ Equity, included in the Notes to the Unaudited Consolidated Financial Statements 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, 18,800 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		Contribution and Sale Agreement By and Among Eagle Rock Energy Partners, L.P., Redman Energy Holdings, L.P. and Certain Other Parties Named Therein, dated July 11, 2007 (incorporated by reference to Exhibit 2.4 of the registrant’s registration statement on Form S-1 (File No. 333-144938)).

2.2		Contribution and Sale Agreement By and Among Eagle Rock Energy Partners, L.P., Redman Energy Holdings II, L.P. and Certain Other Parties Named Therein, dated July 11, 2007 (incorporated by reference to Exhibit 2.5 of the registrant’s registration statement on Form S-1 (File No. 333-144938)).

2.3		Asset Contribution Agreement By and Among NGP Co-Investment Opportunities Fund II, L.P. and Eagle Rock Energy Partners, L.P., dated July 11, 2007 (incorporated by reference to Exhibit 2.6 of the registrant’s registration statement on Form S-1 (File No. 333-144938)).

2.4		Purchase, Sale and Contribution Agreement Between AmGu Holdings LLC, as seller, and Eagle Rock Energy Partners, L.P., as purchaser, dated July 11, 2007 (incorporated by reference to Exhibit 2.7 of the registrant’s registration statement on Form S-1 (File No. 333-144938)).

4.1		Registration Rights Agreement dated July 31, 2007, among Eagle Rock Energy Partners, L.P. and the purchasers listed thereto (incorporated by reference to Exhibit 4.6 of the registrant’s registration statement on Form S-1 (File No. 333-144938)).

10.1		Common Unit Purchase Agreement By and Among Eagle Rock Energy Partners, L.P. and The Purchasers Named Therein, dated July 11, 2007 (incorporated by reference to Exhibit 10.15 of the registrant’s registration statement on Form S-1 (File No. 333-144938)).

10.2		Severance Agreement with former executive officer (incorporated by reference to Exhibit 10.16 of the registrant’s registration statement on Form S-1 (File 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 Richard W. FitzGerald 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 Richard W. FitzGerald pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and 18 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 16, 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

		By: /s/ Richard W. FitzGerald Richard W. FitzGerald Senior Vice President, Chief Financial Officer and Treasurer
		(Duly Authorized and Principal Financial Officer)

EAGLE ROCK ENERGY PARTNERS, L.P.

EXHIBIT INDEX

2.1		Contribution and Sale Agreement By and Among Eagle Rock Energy Partners, L.P., Redman Energy Holdings, L.P. and Certain Other Parties Named Therein, dated July 11, 2007 (incorporated by reference to Exhibit 2.4 of the registrant’s registration statement on Form S-1 (File No. 333-144938)).

2.2		Contribution and Sale Agreement By and Among Eagle Rock Energy Partners, L.P., Redman Energy Holdings II, L.P. and Certain Other Parties Named Therein, dated July 11, 2007 (incorporated by reference to Exhibit 2.5 of the registrant’s registration statement on Form S-1 (File No. 333-144938)).

2.3		Asset Contribution Agreement By and Among NGP Co-Investment Opportunities Fund II, L.P. and Eagle Rock Energy Partners, L.P., dated July 11, 2007 (incorporated by reference to Exhibit 2.6 of the registrant’s registration statement on Form S-1 (File No. 333-144938)).

2.4		Purchase, Sale and Contribution Agreement Between AmGu Holdings LLC, as seller, and Eagle Rock Energy Partners, L.P., as purchaser, dated July 11, 2007 (incorporated by reference to Exhibit 2.7 of the registrant’s registration statement on Form S-1 (File No. 333-144938)).

4.1		Registration Rights Agreement dated July 31, 2007, among Eagle Rock Energy Partners, L.P. and the purchasers listed thereto (incorporated by reference to Exhibit 4.6 of the registrant’s registration statement on Form S-1 (File No. 333-144938)).

10.1		Common Unit Purchase Agreement By and Among Eagle Rock Energy Partners, L.P. and The Purchasers Named Therein, dated July 11, 2007 (incorporated by reference to Exhibit 10.15 of the registrant’s registration statement on Form S-1 (File No. 333-144938)).

10.2		Severance Agreement with former executive officer (incorporated by reference to Exhibit 10.16 of the registrant’s registration statement on Form S-1 (File 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 Richard W. FitzGerald 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 Richard W. FitzGerald pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350.

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. sophomore Good

Eagle Rock Energy Partners L P (EROC) Inactive 10-Q2007 Q3 Quarterly report

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