Eagle Rock Energy Partners L P (EROC) 8-K Index to Financial Statement

EXHIBIT 99.2

INDEX TO FINANCIAL STATEMENT

Eagle Rock Energy GP, L.P. Consolidated Balance Sheet:
Report of Independent Registered Public Accounting Firm	2
Consolidated Balance Sheet as of December 31, 2008	3
Notes to Consolidated Balance Sheet	4

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Eagle Rock Energy GP, L.P. Houston, Texas

We have audited the consolidated balance sheet of Eagle Rock Energy GP, L.P. and subsidiaries (the “Partnership) as of December 31, 2008.  This consolidated financial statement is the responsibility of the Partnership’s management.  Our responsibility is to express an opinion on this consolidated financial statement based on our audit.

We conducted our audit in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement.  The Partnership is not required to have, nor were we engaged to perform and audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statement.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such consolidated balance sheet presents fairly, in all material respects, the financial position of the Partnership as of December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 3 to the consolidated balance sheet, the accompanying financial statement has been retrospectively adjusted for the adoption of Statement of Financial Accounting Standards No. 160, Noncontrolling Interests in Consolidated Financial Statement – an amendment of ARB No. 51 (“SFAS” No. 160”)

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

April 3, 2009

December 7, 2009 as to the effects of the adoption of SFAS 160 and the related disclosures in Note 3

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EAGLE ROCK ENERGY GP, L.P.

CONSOLIDATED BALANCE SHEET

AS OF DECEMBER 31, 2008

($ in thousands)

	December 31, 2008
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	17,916
Accounts receivable(1)		115,932
Risk management assets		76,769
Prepayments and other current assets		2,607
Total current assets		213,224
PROPERTY, PLANT AND EQUIPMENT —Net		1,357,609
INTANGIBLE ASSETS —Net		154,206
RISK MANAGEMENT ASSETS		32,451
OTHER ASSETS		15,571
TOTAL	$	1,773,061
LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	116,578
Due to affiliate		4,473
Accrued liabilities		19,565
Income taxes payable		1,559
Risk management liabilities		13,763
Total current liabilities		155,938
LONG-TERM DEBT		799,383
ASSET RETIREMENT OBLIGATIONS		19,872
DEFERRED TAX LIABILITY		42,349
RISK MANAGEMENT LIABILITIES		26,182
OTHER LONG TERM LIABILITIES		1,622
COMMITMENTS AND CONTINGENCIES (Note 13)
MEMBERS’ EQUITY:
Members’ deficit (2)		(3,714	)
Non-controlling interest		731,429
Total members’ equity		727,715
TOTAL	$	1,773,061

(1) Net of allowance for bad debt of $12,080.

(2) 844,551 units were issued and outstanding as of December 31, 2008.

See notes to consolidated balance sheet.

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EAGLE ROCK ENERGY GP, L.P.

NOTES TO CONSOLIDATED BALANCE SHEET

AS OF DECEMBER 31, 2008

NOTE 1. ORGANIZATION AND DESCRIPTION OF BUSINESS

Organization – Eagle Rock Energy GP, L.P. (the “Partnership”) is a Delaware limited partnership, which was formed on May 25, 2006 to be the general partner of Eagle Rock Energy Partners, L.P. and subsidiaries (“Eagle Rock Energy”).  The Partnership initially was capitalized for the sole purpose of forming and capitalizing Eagle Rock Energy.  The Partnership invested $20 in Eagle Rock Energy in exchange for a 2% general partner interest in Eagle Rock Energy.  The ownership interest in the Partnership at December 31, 2008, are comprised of a ..001% general partner interest held by Eagle Rock Energy G&P, LLC (the “General Partner”) and 99.999% limited partner interest held by Eagle Rock Holdings, L.P. (“Holdings”).  Eagle Rock Energy completed its initial public offering on October 24, 2006.

As of December 31, 2008, the Partnership owns a 1.09% general partner interest in Eagle Rock Energy, as well as incentive distribution rights, the ownership of which entitles the Partnership to receive incentive distributions if the amount that Eagle Rock Energy distributes with respect to any quarter exceeds levels specified in the Eagle Rock Energy agreement of limited partnership.  Eagle Rock Energy is a publicly traded Delaware limited partnership, formed in 2006 and engaged in various aspects of the energy industry.

Description of Business—Eagle Rock Energy is a growth-oriented limited partnership engaged in the business of gathering, compressing, treating, processing, transporting and selling natural gas, fractionating and transporting natural gas liquids, or NGLs, which Eagle Rock Energy calls its “Midstream” business; the business of acquiring, developing and producing interests in oil and natural gas properties, which Eagle Rock Energy calls its “Upstream” business; and the business of acquiring and managing fee minerals and royalty interests, which Eagle Rock Energy calls its “Minerals” business. Eagle Rock Energy’s natural gas pipelines gather natural gas from designated points near producing wells and transport these volumes to third-party pipelines, Eagle Rock Energy’s gas processing plants, utilities and industrial consumers. Natural gas transported to Eagle Rock Energy’s gas processing plants, either on Eagle Rock Energy’s pipelines or third party pipelines, is treated to remove contaminants and conditioned or processed into marketable natural gas and natural gas liquids. Eagle Rock Energy conducts its midstream operations within Louisiana and three geographic areas of Texas. Eagle Rock Energy’s Texas Panhandle Segment assets consist of assets acquired from ONEOK, Inc. on December 1, 2005, and include gathering and processing assets (“Texas Panhandle Segment”). Eagle Rock Energy’s East Texas/Louisiana assets include a non-operated 25% undivided interest in a processing plant as well as a non-operated 20% undivided interested in a connected gathering system the (“East Texas/Louisiana Segment”). On April 7, 2006, Eagle Rock Energy’s East Texas/Louisiana Segment completed the acquisition of a 100% interest in the Brookeland and Masters Creek processing plants in East Texas from Duke Energy Field Services and Swift Energy Corporation. On June 2, 2006, Eagle Rock Energy’s Texas Panhandle Segment completed the acquisition of 100% of Midstream Gas Services, L.P. from a Natural Gas Partners affiliate. On May 3, 2007, Eagle Rock Energy completed the acquisition of Laser Midstream Energy, L.P. (“Laser”) and certain of its subsidiaries (“Laser Acquisition”). The Laser assets include gathering systems and related compression and processing facilities in South Texas, East Texas, and North Louisiana, now a part of Eagle Rock Energy’s East Texas/Louisiana Segment and which created Eagle Rock Energy’s South Texas Segments.   On October 1, 2008, Eagle Rock Energy completed the acquisition of 100% of the outstanding units of Millennium Midstream Partners, L.P. (“MMP”) (see Note 4).   The MMP assets include natural gas gathering and related compression and processing facilities in West Texas, Central Texas, East Texas Southern Louisiana and the Gulf of Mexico that are now a part of Eagle Rock Energy’s East Texas/Louisiana Segment, South Texas Segment and which created Eagle Rock Energy’s Gulf of Mexico Segment.

With respect to Eagle Rock Energy’s Minerals Business, it completed the acquisition of certain fee minerals, royalties, overriding royalties and non-operated working interest properties from Montierra Minerals & Production, L.P. (“Montierra”) (a Natural Gas Partners VII, L.P. portfolio company) and NGP-VII Income Co-Investment Opportunities, L.P. (“Co-Invest”) (a Natural Gas Partners affiliate) (collectively, the “Montierra Acquisition”) on April 30, 2007 (see Note 4). As a result of this acquisition, Eagle Rock Energy’s mineral assets include royalty interests located in multiple producing trends across the United States. The assets include interests in mineral acres and interests in wells. On June 18, 2007, Eagle Rock Energy also completed the acquisition of certain assets owned by MacLondon Energy, L.P., which include additional interests in wells in which Eagle Rock Energy already owns a royalty interest as a result of the Montierra Acquisition.

On July 31, 2007, Eagle Rock Energy entered the upstream business when it completed the acquisition of Escambia Asset Co., LLC and Escambia Operating Co., LLC (“the Escambia Acquisition”). The assets subject to this transaction include operated wells in Escambia County, Alabama. The transaction also included two treating facilities, one natural gas processing plant and related gathering systems. Also 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). These transactions are collectively referred to as the “Redman Acquisition.”  The assets conveyed in the Redman Acquisition included operated and non-operated wells mainly located in East and South Texas.  On April 30, 2008, Eagle Rock Energy completed the acquisition of all of the outstanding capital stock of Stanolind Oil and Gas Corp. (owned directly or indirectly by one or more Natural Gas Partners private equity funds) (“Stanolind”)(see Note 4).  The Stanolind assets include operated oil and natural gas producing properties in the Permian Basin, primarily in Ward, Crane and Pecos Counties, Texas.

Basis of Presentation and Principles of Consolidation—The accompanying balance sheet includes assets, liabilities and member’s deficit of the Partnership consolidated with the assets, liabilities and member’s equity of Eagle Rock Energy.  The balance sheet of the Partnership is presented on a consolidated basis with Eagle Rock Energy based on the control of Eagle Rock Energy by the Partnership.  Intercompany accounts and transactions have been eliminated in the consolidated balance sheet.

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NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The accompanying consolidated balance sheet has 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 and liabilities related to these assets in its balance sheet.

The preparation of the balance sheet 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 balance sheet.  Significant estimates are required for proved oil and natural gas reserves, which can affect the carrying value of oil and natural gas properties. Eagle Rock Energy evaluates its estimates and assumptions on a regular basis. Eagle Rock Energy bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates and such differences could be material.

Oil and Natural Gas Accounting Policies

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

Depletion of producing oil and natural gas properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for acquisition costs using all proved reserves. Statement of Financial Accounting Standards (“SFAS”) No. 19, Financial Accounting and Reporting for Oil and Gas Producing Companies requires that acquisition costs of proved properties be amortized on the basis of all proved reserves, (developed and undeveloped) and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves.

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

Impairment of Oil and Natural Gas Properties

Eagle Rock Energy reviews its proved properties at the field level when management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future oil and natural gas reserves that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels. If the carrying amount of an asset exceeds the sum of the undiscounted estimated future net cash flows, Eagle Rock Energy recognizes impairment expense equal to the difference between the carrying value and the fair value of the asset, which is estimated to be the expected present value of discounted future net cash flows from proved reserves utilizing Eagle Rock Energy’s weighted average cost of capital. During the year ended December 31, 2008, Eagle Rock Energy reduced its proved properties by $107.0 million and $1.7 million in its Upstream and Minerals Segments, respectively, as a result of substantial declines in commodity prices in the fourth quarter.

Unproved leasehold costs are reviewed periodically and a loss is recognized to the extent, if any, that the cost of the property has been impaired. Unproved properties that are individually insignificant are amortized. Unproved properties that are individually significant are assessed for impairment on a property-by-property basis. If considered impaired, costs are charged to expense when such impairment is deemed to have occurred.

Property Retirement Obligations

Eagle Rock Energy is required to make estimates of the future costs of the retirement obligations of its producing oil and natural gas properties. This requirement necessitates that Eagle Rock Energy 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

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 Eagle Rock Energy principally consists of cash and cash equivalents and accounts receivable.

Eagle Rock Energy places its cash and cash equivalents with high-quality institutions and in money market funds. Eagle Rock Energy derives its revenue from customers primarily in the natural gas industry.  Industry concentrations have the potential to impact Eagle Rock Energy’s overall exposure to credit risk, either positively or negatively, in that Eagle Rock Energy’s customers could be affected by similar changes in economic, industry or other conditions. However, Eagle Rock Energy believes the credit risk posed by this industry concentration is offset by the creditworthiness of Eagle Rock Energy’s customer base. Eagle Rock Energy’s portfolio of accounts receivable is comprised primarily of mid-size to large domestic corporate entities.  The following is the activity within our allowance for doubtful accounts during the years ended December 31, 2008.

Year	Description	Balance at beginning of period		Charged to bad debt expense		Write-offs/adjustments charged to allowance		Balance at end of period
2008	Allowance for doubtful accounts receivable	$	1,046	$	11,136	$	102	$	12,080

 Of the $11.1 million added to Eagle Rock Energy’s allowance for doubtful accounts receivable during the year ended December 31, 2008, $10.7 relates to outstanding receivables from SemGroup, L.P. which filed for bankruptcy in July 2008.

Certain Other Concentrations—Eagle Rock Energy relies on natural gas producers for its Midstream Business’s natural gas and natural gas liquid supply, with the top two producers (by segment) accounting for 37.0% of its natural gas supply in the Texas Panhandle Segment, 24.4% of its natural gas supply in the East Texas/Louisiana Segment, 48.8% of its natural gas supply in the South Texas Segment and in the Gulf of Mexico Segment, one customer accounted for 90% of its natural gas supply for the month of December 2008. While there are numerous natural gas and natural gas liquid producers and some of these producers are subject to long-term contracts, Eagle Rock Energy may be unable to negotiate extensions or replacements of these contracts on favorable terms, if at all. If Eagle Rock Energy were to lose all or even a portion of the natural gas volumes supplied by these producers and was unable to acquire comparable volumes, Eagle Rock Energy’s results of operations and financial position could be materially adversely affected. These percentages are calculated based on MMBtus gathered during the month of December 2008.

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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, depletion and amortization. Eagle Rock Energy 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. Eagle Rock Energy calculates depreciation on the straight-line method over estimated useful lives of Eagle Rock Energy’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

Eagle Rock Energy capitalizes interest costs on major projects during extended construction time periods. Such interest costs are allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets.

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 assets. 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.  During the year ended December 31, 2008, Eagle Rock Energy reduced the carrying value of certain processing plants, pipelines and contracts in its Midstream business by $35.1 million due to the substantial decline in commodity prices in the fourth quarter.

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

Eagle Rock Energy acquired goodwill as part of its Redman Acquisition.  During the year ended December 31, 2008, goodwill increased by $1.4 million due to adjustments made to the Redman purchase price allocation.  Eagle Rock Energy performed its annual impairment test in May 2008 and determined that no impairment appeared evident. Eagle Rock Energy’s goodwill impairment test involves a comparison of the fair value of each of its reporting units with their carrying value. The fair value is determined using discounted cash flows and other market-related valuation models. Certain estimates and judgments are required in the application of the fair value models.  As a result of the reduction recorded to proved properties within Eagle Rock Energy’s Upstream Segment during the fourth quarter of 2008 which resulted from the substantial decline in commodity prices during the fourth quarter of 2008, Eagle Rock Energy performed an assessment of its goodwill and reduced its goodwill by $31.0 million, which reduced its goodwill amount to zero.

 Other Assets— As of December 31, 2008, other assets primarily consist of costs associated with: debt issuance costs, net of amortization ($4.2 million); business deposits to various providers and state or regulatory agencies ($0.5 million); and investment in unconsolidated affiliates ($9.3 million).

Within Eagle Rock Energy’s investments of unconsolidated non-affiliates, Eagle Rock Energy owns 13.2%, 5.0% and 5.0% of the common units of Ivory Working Interests, L.P., Buckeye Pipeline, L.P. and Trinity River, LLC, respectively. Eagle Rock Energy also owns a 50% joint venture in Valley Pipeline, LLC. These investments are accounted for under the equity method and as of December 31, 2008 are not considered material to Eagle Rock Energy’s financial position or results of operations.

Transportation and Exchange Imbalances—In the course of transporting natural gas and natural gas liquids for others, Eagle Rock Energy 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, 2008, Eagle Rock Energy had imbalance receivables totaling $0.3 million and imbalance payables totaling $2.8 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.

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.

Income Taxes—Provision for income taxes is primarily applicable to Eagle Rock Energy’s state tax obligations under the Revised Texas Franchise Tax (the “Revised Texas Franchise Tax”) and certain federal and state tax obligations of Eagle Rock Energy Acquisition Co., Inc., Eagle Rock Upstream Development Company, Inc., Eagle Rock Energy Acquisition Co. II, Inc. and Eagle Rock Upstream Development Company II, Inc., all of which are consolidated subsidiaries of Eagle Rock Energy. Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of the Partnership’s tax paying entities for financial reporting and tax purposes.

In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax. In May 2006, the State of Texas expanded its pre-existing franchise tax to include limited partnerships, limited liability companies, corporations and limited liability partnerships. As a result of the change in tax law, the Partnership’s and Eagle Rock Energy’s tax status in the State of Texas changed from non-taxable to taxable effective with the 2007 tax year.

Since the Partnership is structured as a pass-through entity, it is not subject to federal income taxes. As a result, its partners are individually responsible for paying federal and certain income taxes on their share of its taxable income. Since the Partnership does not have access to information regarding each partner’s tax basis, it cannot readily determine the total difference in the basis of its net assets for financial and tax reporting purposes.

In accordance with Financial Accounting Standards Board Interpretation 48, Accounting for Uncertainty in Income Taxes (“FIN 48”), the Partnership and Eagle Rock Energy must recognize the tax effects of any uncertain tax positions they may adopt, if the position taken by them is more likely than not sustainable. If a tax position meets such criteria, the tax effect to be recognized by them would be the largest amount of benefit with more than a 50% chance of being realized upon settlement. This guidance was effective January 1, 2007, and adoption of this guidance by the Partnership and Eagle Rock Energy had no material impact on the financial position, results of operations or cash flows. See Note 15 for additional information regarding its income taxes.

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. Eagle Rock Energy’s forward natural gas and crude oil 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, Eagle Rock Energy does have certain contracts which extend through the life of the dedicated production. The terms of these contracts generally preclude unplanned netting. Eagle Rock Energy 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. Eagle Rock Energy 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 Eagle Rock Energy 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 12 for a description of Eagle Rock Energy’s risk management activities.

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NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS No. 157”). This statement defines fair value, establishes a framework for measuring fair value, and expands disclosure about fair value measurements. The statement is effective for financial statements issued for fiscal years beginning after November 15, 2007.  SFAS No.157, as it relates to financial assets and financial liabilities, was effective for the Partnership on January 1, 2008 and had no material impact on its 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 was effective for the Partnership and Eagle Rock Energy as of January 1, 2008 and had no impact, as the Partnership elected not to fair value additional financial assets and liabilities.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS No. 141R”), which replaces SFAS No. 141.  SFAS 141R requires that all assets, liabilities, contingent consideration, contingencies and in-process research and development costs of an acquired business be recorded at fair value at the acquisition date; that acquisition costs generally be expensed as incurred; that restructuring costs generally be expensed in periods subsequent to the acquisition date; and that changes in accounting for deferred tax asset valuation allowances and acquired income tax uncertainties after the measurement period impact income tax expense.  SFAS No. 141R is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008, with the exception for the accounting for valuation allowances on deferred tax assets and acquired tax contingencies associated with acquisitions.  SFAS No. 141R amends SFAS No. 109, Accounting for Income Taxes, such that adjustments made to valuation allowances on deferred taxes and acquired tax contingencies associated with acquisitions that closed prior to the effective date of SFAS No. 141R would also apply the provisions of SFAS No. 141R.  The impact of the adoption of SFAS No. 141R on the Partnership’s consolidated balance sheet will depend on the nature and the extent of business combinations occurring after January 1, 2009.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51 (“SFAS No. 160”). SFAS No.160 requires that accounting and reporting for minority interests will be re-characterized as noncontrolling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. This Statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008.  SFAS No. 160 was effective for the Partnership as of January 1, 2009 and applied retrospectively to this consolidated balance sheet and as a result, the partnership recorded non-controlling interest of $731.4 million as a component of Members’ Equity.

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

In April 2008, the FASB issued FASB Staff Position (“FSP”) No. SFAS 142-3, Determination of the Useful Life of Intangible Assets (“FSP SFAS 142-3”).  FSP SFAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible Assets (“SFAS 142”).  The intent of FSP SFAS 142-3 is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141R (revised 2007), Business Combinations (“SFAS 141R”) and other applicable accounting literature.  FSP SFAS 142-3 is effective for financial statements issued forfiscal years beginning after December 15, 2008 and must be applied prospectively to intangible assets acquired after the effective date.  The impact of the adoption of FSP SFAS 142-3 on the Partnership’s consolidated balance sheet will depend on the nature and the extent of business combinations occurring after January 1, 2009. 

In May 2008, the FASB issued SFAS No. 162, Hierarchy of Generally Accepted Accounting Principles (“SFAS 162”).  This statement is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements of nongovernmental entities that are presented in conformity with GAAP.  This statement will be effective 60 days following the U.S. Securities and Exchange Commission’s approval of the Public Company Accounting Oversight Board amendment to AU Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.  The Partnership does not expect the adoption of SFAS 162 to have a material impact on its consolidated balance sheet.  

In December 2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting to revise the existing Regulation S-K and Regulation S-X reporting requirements to align with current industry practices and technological advances. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. In addition, the new disclosure requirements require a company to (a) disclose its internal control over reserves estimation and report the independence and qualification of its reserves preparer or auditor, (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserve audit and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than period-end prices. The provisions of this final ruling will become effective for disclosures in Partnership’s consolidated balance sheet for the year ended December 31, 2009.

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NOTE 4. ACQUISITIONS

2008 Acquistions

Stanolind Acquisition.  On April 30, 2008, Eagle Rock Energy completed the acquisition of all of the outstanding capital stock of Stanolind Oil and Gas Corp. (“Stanolind”), for an aggregate purchase price of $81.9 million, subject to working capital and other purchase price adjustments (the “Stanolind Acquisition”). One or more Natural Gas Partners’ (“NGP”) private equity funds, which directly or indirectly owned a majority of the equity interests in Stanolind, is an affiliate of Eagle Rock Energy and is the majority owner of the sole owner of Eagle Rock Energy G&P, LLC (the “Company”), which is the general partner of Eagle Rock Energy GP, L.P., which is the general partner of Eagle Rock Energy.  Eagle Rock Energy funded the transaction from borrowings under its existing credit facility as well as existing cash from operations.  Stanolind owned and operated oil and natural gas producing properties in the Permian Basin, primarily in Ward, Crane and Pecos Counties, Texas.

The purchase price was allocated on a preliminary basis to acquired assets and liabilities assumed based on their respective fair value as determined by management.  Eagle Rock Energy recorded the Stanolind 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, Eagle Rock Energy has recorded the interest attributable to the ownership of NGP in Stanolind at their carryover basis. Those interests not attributable to NGP have been recorded at their fair value.  As a result, Eagle Rock Energy recorded $0.9 million of the net cash paid in excess of the carryover basis as a distribution to NGP for the Stanolind acquisition.

The preliminary purchase price allocation is set forth below.

	($ in thousands)
Oil and gas properties:
Proved properties	$	110,747
Unproved properties		7,597
Cash and cash equivalents		537
Accounts receivable		4,561
Other assets		459
Accounts payable and accrued liabilities		(4,948	)
Risk management liabilities		(2,865	)
Deferred income taxes		(27,468	)
Asset retirement obligations		(4,770	)
Other long-term liabilities		(2,825	)
Total purchase price allocation		81,025
Distribution to NGP		857
Total Consideration Paid	$	81,882

    Eagle Rock Energy commenced recording results of operations with regard to Stanolind on May 1, 2008.  

Due to the potential conflict of interest between the interests of the Company and the public unitholders of Eagle Rock Energy, as a result of one or more NGP private equity funds directly or indirectly owning a majority of the equity interests in Eagle Rock Energy and Stanolind, the Board of Directors authorized the Company’s Conflicts Committee to review, evaluate, and, if determined appropriate, approve the Stanolind Acquisition. The Conflicts Committee, consisting of independent Directors of the Company, determined that the Stanolind 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 considering the fairness of the Stanolind acquisition, the Conflicts Committee considered the valuation of the assets and liabilities involved in the transaction and the cash flow of Stanolind. Based on the recommendation of management and the Conflicts Committee, the Board of Directors approved the transaction.

Millennium Acquisition.  On October 1, 2008, Eagle Rock Energy completed the acquisition of 100% of the outstanding units of Millennium Midstream Partners, L.P. (“MMP”) for an aggregate purchase price of $205.2 million, comprised of approximately $181.0 million in cash and 2,181,818 (recorded value of $24.2 million) common units, subject to post closing purchase price adjustments (the “Millennium Acquisition”).  The cash portion of the consideration was funded through borrowings of $176.4 million under Eagle Rock Energy’s Revolving Credit Facility made prior to September 30, 2008 and cash on hand.  MMP is in the natural gas gathering and processing business, with assets located in East, Central and West Texas and South Louisiana.  With respect to the South Louisiana assets acquired in the Millennium Acquisition, the Yscloskey and North Terrebonne facilities were flooded with three to four feet of water as a result of the storm surges caused by Hurricanes Ike and/or Gustav.  Eagle Rock Energy has reported, is preparing to file claims for, and expects to receive payment on physical damage and its business interruption insurance coverage related to Hurricane Ike and Gustav’s damage to these two facilities. The timing of collection of such insurance claims is unknown at this time.  The North Terrebonne facility came back on-line in November 2008 and the Yscloskey facility came back on-line in January 2009.  The former owners of MMP provided Eagle Rock Energy indemnity coverage for Hurricanes Ike and Gustav to the extent losses are not covered by insurance and established an escrow account of 1,818,182 common units and $0.6 million in cash available for Eagle Rock Energy to recover against for this purpose.  Prior to December 31, 2008, Eagle Rock Energy recovered 40,880 units and $0.3 million in cash from this escrow account.  As of March 6, 2009, Eagle Rock Energy has recovered an additional 65,841 common units and the remaining $0.3 million in cash from the escrow account.

The purchase price was allocated, excluding amounts held in escrow, on a preliminary basis to assets acquired and liabilities assumed, based on their respective fair value as determined by management with the assistance of K.E. Andrews & Company, a third-party valuation specialist.  The Millennium Acquisition was accounted for as a purchase in accordance with SFAS No. 141, Business Combinations (“SFAS No. 141).  The preliminary purchase price allocation is set forth below.

	($ in thousands)
Property, plant and equipment	$	189,753
Intangibles, right-of-way and contracts		28,371
Cash and cash equivalents		38
Accounts receivable		19,130
Other current assets		1,188
Derivatives		89
Other current liabilities		(24,650	)
Other current liabilities		(3,103	)
Asset retirement obligations		(2,490	)
Non-controlling interest		(1,346	)
Other liabilities		(1,749	)
	$	205,231

Eagle Rock Energy commenced recording results of operations with regard to MMP on October 2, 2008.

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NOTE 5. PROPERTY PLANT AND EQUIPMENT AND ASSET RETIREMENT OBLIGATIONS

Fixed assets consisted of the following (in thousands):

	December 31, 2008
Land	$	1,211
Plant		232,219
Gathering and pipeline		653,016
Equipment and machinery		18,672
Vehicles and transportation equipment		3,958
Office equipment, furniture, and fixtures		1,023
Computer equipment		4,714
Corporate		126
Linefill		4,269
Proved properties		515,452
Unproved properties		73,622
Construction in progress		39,498
		1,547,780
Less: accumulated depreciation, depletion and amortization		(190,171	)
Net property plant and equipment	$	1,357,609

During the year ended December 31, 2008, Eagle Rock Energy impaired its plants and gathering and pipeline assets and proved properties of $4.3 million, $19.5 million and $108.8 million, respectively, as a result of the substantial decline in commodity prices during the fourth quarter.

Asset Retirement Obligations—Eagle Rock Energy recognizes asset retirement assets for its oil and gas working interests in accordance with FASB Statement No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”). SFAS 143 applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. SFAS 143 requires that Eagle Rock Energy record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Eagle Rock Energy recognizes asset retirement obligations for its midstream assets in accordance with FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143 (“FIN 47”). FIN 47 clarified that the term “conditional asset retirement obligation”, as used in SFAS No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional upon a future event that may or may not be within its 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, Eagle Rock Energy is 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 the liability for asset retirement obligations is as follows (in thousands):

	2008
Asset retirement obligations—January 1	$	11,337
Additional liability on newly constructed assets		204
Additional liability related to acquisitions		7,260
Revisions		—
Accretion expense		1,071
Asset retirement obligations—December 31	$	19,872

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NOTE 6. INTANGIBLE ASSETS

Intangible assets consist of right-of-ways and easements and acquired customer contracts, which Eagle Rock Energy amortizes over the term of the agreement or estimated useful life. Estimated aggregate amortization expense for each of the five succeeding years is as follows: 2009—$22.9 million; 2010—$21.9 million; 2011—$11.2 million; 2012—$11.2 million; and 2013—$10.1 million. Intangible assets consisted of the following (in thousands):

	December 31, 2008
Rights-of-way and easements—at cost	$	89,203
Less: accumulated amortization		(11,437	)
Contracts		119,743
Less: accumulated amortization		(43,303	)
Net intangible assets	$	154,206

The amortization period for Eagle Rock Energy’s rights-of-ways and easements is 20 years. The amortization period for contracts range from 5 to 20 years, and are approximately 8 years on average as of December 31, 2008.  During the year ended December 31, 2008, Eagle Rock Energy impaired its right-of-way and easements and contracts of $3.7 million and $7.6 million, respectively, as a result of the substantial decline in commodity prices during the fourth quarter.

NOTE 7. LONG-TERM DEBT

Long-term debt consisted of (in thousands):

	December 31, 2008
Revolver	$	799,383
Total debt		799,383
Less: current portion		—
Total long-term debt	$	799,383

On December 13, 2007, Eagle Rock Energy entered into a new senior secured revolving credit facility (the “Revolving Credit Facility”) with aggregate commitments of $800 million. During the year ended December 31, 2008, Eagle Rock Energy exercised $180 million of its $200 million accordion feature of the Revolving Credit Facility, which increased the total commitment to $980 million.  The Revolving Credit Facility was entered into with a syndicate of commercial and investment banks, led by Wachovia Capital Markets, LLC and Bank of America Securities LLC as joint lead arrangement agents and joint book runners. The Revolving Credit Facility provides for $980 million aggregate principal amount of revolving commitments and has a maturity date of December 13, 2012. The Revolving Credit Facility provides Eagle Rock Energy with the ability to potentially increase the total amount of revolving commitments by an additional $20 million to a total of $1 billion.  Subsequently, as a result of Lehman Brothers’ bankruptcy filing, the amount of available commitments was reduced by the unfunded portion of Lehman Brother’s commitment in an amount of approximately $9.1 million to a total of $970.9 million.

Upon entering into the Revolving Credit Facility, Eagle Rock Energy drew approximately $567 million from the revolving commitments to repay its then outstanding indebtedness under its previously existing credit facility of approximately $561 million and pay accrued interest of approximately $6 million. In connection with the closing of the Revolving Credit Facility, Eagle Rock Energy incurred debt issuance costs of $4.3 million.  During the year ended December 31, 2008, Eagle Rock Energy incurred an additional $0.8 million of debt issuance costs in connection with exercising the accordion feature of the Revolving Credit Facility.  As of December 31, 2008 the unamortized amount of debt issuance cost was $4.2 million.

The Revolving Credit Facility includes a sub-limit for the issuance of standby letters of credit for a total of $200 million. At December 31, 2008, Eagle Rock Energy had $0.2 million of outstanding letters of credit.

In certain instances defined in the Revolving Credit Facility, Eagle Rock Energy’s outstanding debt is subject to mandatory repayments and/or is subject to a commitment reduction for asset and property sales, reductions in borrowing base and for insurance/condemnation proceeds.

The Revolving Credit Facility contains various covenants which limit Eagle Rock Energy’s ability to grant liens, make certain loans and investments; make certain capital expenditures outside Eagle Rock Energy’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 Eagle Rock Energy’s assets. Additionally, the Revolving Credit Facility limits Eagle Rock Energy’s ability to incur additional indebtedness with certain exceptions and purchase money indebtedness and indebtedness related to capital or synthetic leases not to exceed 2.5% of tangible net worth.

The Revolving Credit Facility also contains covenants, which, amount other things, require Eagle Rock Energy, on a consolidated basis, to maintain specified ratios or conditions as follows:

• Consolidated EBITDA (as defined) to Consolidated Interest Expense (as defined) of not less than 2.5 to 1.0;

• Total Funded Indebtedness (as defined) to Adjusted Consolidated EBITDA (as defined) of not more than 5.0 to 1.0 (5.25 to 1.0 for the three quarters following a material acquisition); and

• Borrowing Base Indebtedness (as defined) not to exceed the Borrowing Base (as defined) as re-determined from time to time.

Eagle Rock Energy’s credit facility accommodates, through the use of a  borrowing base for its Upstream Business and traditional cash-flow based covenants for its Midstream and Minerals Businesses, the allocation of indebtedness to either its Upstream Business (to be measured against the borrowing base) or to its Midstream and Minerals Businesses (to be measured against the cash-flow based covenant).  At December 31, 2008, Eagle Rock Energy was in compliance with its covenants under the credit facility. Eagle Rock Energy’s interest coverage ratio, as defined in the credit agreement (i.e., Consolidated EBITDA divided by Consolidated Interest Expense), was 6.6 as compared to a minimum interest coverage covenant of 2.5, and its leverage ratio, as defined in the credit agreement (i.e., Total Funded Indebtedness divided by Adjusted Consolidated EBITDA), was 3.7 as compared to a maximum leverage ratio of 5.0 times (5.25 times until March 31, 2009 due to the Millennium Acquisition).  As of December 31, 2008, the borrowing base for Eagle Rock Energy’s Upstream Business was determined at $206 million.  As a result of the current commodity price environment and depressed economic activity, which will negatively impact Eagle Rock Energy’s financial results going forward, Eagle Rock Energy expects that its borrowing base will be re-determined in early April 2009 to a lower amount (resulting in a higher allocation of indebtedness to its Midstream and Minerals Businesses) and a rise in its leverage ratio in 2009.  This may cause Eagle Rock Energy to take steps to reduce its leverage or enhance its Adjusted Consolidated EBITDA, as defined in its credit facility.

Based upon the above mentioned ratios and conditions as calculated as of December 31, 2008, Eagle Rock Energy has approximately $171.5 million of unused capacity under the Revolving Credit Facility at December 31, 2008 on which Eagle Rock Energy pays a 0.3% commitment fee per year.

At Eagle Rock Energy’s election, its outstanding indebtedness bears interest on the unpaid principal amount either at a base rate plus the applicable margin (currently 0.75% per annum based on Eagle Rock Energy’s total leverage ratio and utilization of its borrowing base as part of its total indebtedness); or at the Adjusted Eurodollar Rate plus the applicable margin (currently 1.75% per annum based on Eagle Rock Energy’s total leverage ratio and utilization of its borrowing base as part of its total indebtedness). At December 31, 2008, the weighted average interest rate on its outstanding debt balance was 5.76%.

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-, six-, nine- or twelve months, as selected by Eagle Rock Energy. Eagle Rock Energy pays a commitment fee equal to (1) the average of the daily differences between (a) the revolver commitments and (b) the sum of the aggregate principal amount of all outstanding loans times (2) 0.30% per annum, based on its current leverage ratio and borrowing base utilization. Eagle Rock Energy 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 where any conditions for drawing could then be met and determined as of the close of business on any date of determination). Additionally, Eagle Rock Energy 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 obligation under the Revolving Credit Facility are secured by first priority liens on substantially all for Eagle Rock Energy’s assets, including a pledge of all of the capital stock of each of its subsidiaries.

Scheduled maturities of long-term debt as of December 31, 2008, were as follows:

	Principal Amount
	($ in thousands)
2009	$	—
2010		—
2011		—
2012		799,383
	$	799,383

Eagle Rock Energy was in compliance with the financial covenants under the Revolving Credit Facility as of December 31, 2008. If an event of default existed under the Amended Revolving Credit Facility, the lenders would be able to accelerate the maturity of the Revolving Credit Facility and exercise other rights and remedies.

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NOTE 8. NON-CONTROLLING INTEREST

               Non-controlling interest represents third-party and related party ownership interests in the net assets of the Partnership.  For financial reporting purposes, the assets and liabilities of the Partnership are consolidated with those of its own, with third-party investor’s ownership in its consolidated balance sheet amounts shown as non-controlling interest.  The following table shows the components of non-controlling interest at December 31, 2008 (in thousands):

Limited partners of Eagle Rock Energy
Non-affiliates of Eagle Rock Energy	$	466,848
Affiliates of Eagle Rock Energy		264,581
	$	731,429

Eagle Rock Energy has declared a cash distribution for each quarter since its initial public offering. The table below summarizes these distributions.

Quarter Ended	Distribution per Unit			Record Date	Payment Date
December 31, 2006+	$	0.2679	(1)	Feb. 7, 2007	Feb. 15, 2007
March 31, 2007+	$	0.3625		May 7, 2007	May 15, 2007
June 30, 2007+	$	0.3625		Aug. 8, 2007	Aug. 14, 2007
September 30, 2007	$	0.3675		Nov. 8, 2007	Nov. 14, 2007
December 31, 2007	$	0.3925		Feb. 11, 2008	Feb. 14, 2008
March 31, 2008	$	0.4000		May 9, 2008	May 15, 2008
June 30, 2008	$	0.4100		Aug. 8, 2008	Aug. 14, 2008
September 30, 2008	$	0.4100		Nov. 7, 2008	Nov. 14, 2008
December 31, 2008	$	0.4100		Feb. 10, 2009	Feb. 13, 2009

(1) Represents a prorated distribution to the common unitholders from the IPO date of October 24, 2006 through December 31, 2006.

+ The distribution per unit represents distributions made only on common units.

At December 31, 2008, there were 53,043,767 common units (exclusive of restricted unvested common units and common units held in escrow related to the Millennium Acquisition) and 20,691,495 subordinated units (all subordinated units are owned by Holdings) of Eagle Rock Energy outstanding.  In addition, there were 905,486 restricted unvested common units outstanding.

Subordinated units represent limited partner interests in Eagle Rock Energy, and holders of subordinated units exercise the rights and privileges available to unitholders under Eagle Rock Energy’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 Eagle Rock Energy’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 Eagle Rock Energy agreement have been met.

NOTE 9. MEMBERS’ EQUITY

At December 31, 2008, member’s deficit consisted of the Partnership’s initial $1,000 capitalization adjusted for the Partnership’s share of the losses and other equity transactions of Eagle Rock Energy.  As of December 31, 2008, there are 844,551 general partner units outstanding.

NOTE 10. RELATED PARTY TRANSACTIONS

On July 1, 2006, Eagle Rock Energy entered into a month-to-month contract for the sale of natural gas with an affiliate of Natural Gas Partners, under which Eagle Rock Energy sells a portion of its gas supply.  In July 2008, the company to which Eagle Rock Energy sells its natural gas was sold by the affiliate of NGP and thus ceased being a related party.

In addition, during the years ended December 31, 2008 and 2007, Eagle Rock Energy incurred expenses with other related parties of which there was an outstanding accounts payable balance of $0.7 million as of December 31, 2008.  During the year ended December 31, 2008, Eagle Rock Energy generated revenue from other related parties of which no amounts are outstanding as of December 31, 2008.

During the year ended December 31, 2008, Eagle Rock Energy leased office space from Montierra and was also reimbursed by Montierra for services performed by its employees on behalf of Montierra.  As of December 31, 2008, Eagle Rock Energy has an outstanding receivable balance of $0.3 million due from Montierra and an outstanding payable balance of $0.7 million due to Montierra.

During the year ended December 31, 2008, Eagle Rock Energy incurred expenses for services performed by Stanolind Field Services (“SFS”), which are assets controlled by NGP and certain individuals, including one employee of Eagle Rock Energy G&P, LLC.  As of December 31, 2008, Eagle Rock Energy had an outstanding payable balance due to SFS of $0.1 million.

Eagle Rock Energy entered into an Omnibus Agreement with Eagle Rock Energy G&P, LLC, Holdings and Eagle Rock Energy’s general partner on October 24, 2006, in connection with the initial public offering of Eagle Rock Energy. The Omnibus Agreement requires Eagle Rock Energy to reimburse Eagle Rock Energy G&P, LLC for the payment of certain expenses incurred on Eagle Rock Energy’s behalf, including payroll, benefits, insurance and other operating expenses, and provides certain indemnification obligations.

Eagle Rock Energy does not directly employ any persons to manage or operate our business. Those functions are provided by the general partner of the Partnership’s general partner. Eagle Rock Energy reimburses the general partner of the Partnership’s general partner for all direct and indirect costs of these services under the Omnibus Agreement.

In connection with the closing of Eagle Rock Energy’s initial public offering, on October 24, 2006, it entered into a registration rights agreement with Eagle Rock Holdings, L.P. in connection with its contribution to Eagle Rock Energy of all of its limited and general partner interests in Eagle Rock Pipeline. In the registration rights agreement, Eagle Rock Energy 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. The registration rights agreement is still in effect and Eagle Rock Energy is in compliance with all obligations of the agreement.

On April 30, 2008, Eagle Rock Energy completed the acquisition of all of the outstanding capital stock of Stanolind, for an aggregate purchase price of $81.8 million. One or more NGP private equity funds, which directly or indirectly owned a majority of the equity interests in Eagle Rock and Stanolind.  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 Stanolind Acquisition. The Conflicts Committee, consisting of independent Directors of the Company, determined that the Stanolind 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 Stanolind 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 Stanolind. Based on the recommendation of the Conflicts Committee, the Board of Directors approved the transaction.

As of December 31, 2008, the General Partner had $4.5 million of outstanding checks paid on behalf of Eagle Rock Energy. This amount was recorded as Due to Affiliate on Eagle Rock Energy’s balance sheet in current liabilities. As the checks are drawn against the General Partner’s cash accounts, Eagle Rock Energy reimburses the General Partner.

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NOTE 11. FAIR VALUE OF FINANCIAL INSTRUMENTS

Effective January 1, 2008, Eagle Rock Energy adopted SFAS No. 157, as discussed in Note 3, which, among other things, requires enhanced disclosures about assets and liabilities carried at fair value.

As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).  Eagle Rock Energy utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk inherent in the inputs to the valuation technique.  SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurements).  The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:

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

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

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

As of December 31, 2008, Eagle Rock Energy has recorded its interest rate swaps and commodity derivative instruments (see Note 11), which includes crude oil, natural gas and natural gas liquids (“NGLs”), at fair value. Eagle Rock Energy has classified the inputs to measure the fair value of its interest rate swap, crude oil derivatives and natural gas derivatives as Level 2.  Because the NGL market is considered to be less liquid and thinly traded, Eagle Rock Energy has classified the inputs related to its NGL derivatives as Level 3. The following table discloses the fair value of Eagle Rock Energy’s derivative instruments as of December 31, 2008:

	Level 1		Level 2			Level 3		Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	87,329		$	—	$	87,329
Natural gas derivatives		—		7,875			—		7,875
NGL derivatives		—		—			14,016		14,016
Total	$	—	$	95,204		$	14,016	$	109,220
Liabilities:
Interest rate swaps	$	—	$	(39,945	)	$	—	$	(39,945	)

As of December 31, 2008, risk management current assets and risk management long-term assets in the Consolidated Balance Sheet include investment premiums of $13.3 million and $1.7 million, respectively.

The following table sets forth a reconciliation of changes in the fair value of the Level 3 NGL derivatives during the year ended December 31, 2008 (in thousands):

Net liability balances as of January 1, 2008	$	(52,793	)
Settlements		16,098
Unrealized gains		50,711
Net asset balances as of December 31, 2008	$	14,016

Eagle Rock Energy values its Level 3 NGL derivatives using forward curves, volatility curves, volatility skew parameters, interest rate curves and model parameters.

The carrying amount of cash equivalents is believed to approximate their fair values because of the short maturities of these instruments.   The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments.  As of December 31, 2008, the debt associated with the Credit Agreement bore interest at floating rates. As such, carrying amounts of this debt instrument approximates fair value.

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NOTE 12. RISK MANAGEMENT ACTIVITIES

To mitigate its interest rate risk, Eagle Rock Energy entered into various interest rate swaps. These swaps convert the variable-rate term loan into a fixed-rate obligation. The purpose of entering into these swaps is to eliminate interest rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense.

On December 4, 2008, Eagle Rock Energy executed a series of interest rate hedge transactions by which it extended the term on its existing interest rate swaps with a then notional amount of $450 million. The expiration dates on these swaps were extended from December 31, 2010 (for swaps with a notional value of $150 million), and January 3, 2011 (for swaps with a notional value of $300 million) to December 31, 2012. In addition, Eagle Rock Energy blended the existing swap rates with the then prevailing interest rate swap rate for the period January 2011 through December 2012 (“blend and extend” strategy). This resulted in its weighted average three month LIBOR swap rate on its existing swaps decreasing from approximately 4.84% to approximately 4.16%.

In addition, on December 5, 2008, Eagle Rock Energy executed an incremental interest rate swap on a notional amount of $150 million with an expiration of December 31, 2012 at a three month LIBOR swap rate of 2.56%. This additional transaction further reduced its weighted average three month LIBOR swap rate to approximately 3.76%.

The table below summarizes the terms, amounts received or paid and the fair values of the various interest rate swaps:

Effective Date	Expiration Date	Notional Amount		Fixed Rate			Fair Value December 31, 2008
	($ in thousands, except notional amount)
09/30/2008	12/31/2012	$	150,000,000		4.020	%	$	(11,398	)
09/30/2008	12/31/2012		150,000,000		4.295			(12,900	)
10/03/2008	12/31/2012		150,000,000		4.170			(12,199	)
12/31/2008	12/31/2012		150,000,000		2.560			(3,448	)
							$	(39,945	)

As of December 31, 2008, the fair value of these contracts totaled an approximate $39.9 million liability.

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

During 2005 and 2006, Eagle Rock Energy entered into the following risk management activities in connection with risks in its midstream business (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 57,000 Bbls per month and 54,000 Bbls per month for 2009, and 2010, respectively; and

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

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 derivatives 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.

Eagle Rock Energy entered or assumed the following derivative transactions related to Eagle Rock Energy’s Upstream Business in association with the Montierra, EAC and Redman acquisitions during the year ended December 31, 2007. Transactions shown with a floor price only are puts; all other are costless collars (excluding transactions that settled in previous periods).

		Average Monthly Volumes		Price ($/mmbtu or $/bbl)
Period	Commodity		Index	Avg. Floor	Avg. Ceiling
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

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In addition to the upstream derivative transaction described above, Eagle Rock Energy also entered into or assumed the following derivative transactions associated with its Midstream Business in conjunction with the Escambia Acquisition (excluding transactions that settled in previous periods). All of these derivatives are swaps.

Period	Commodity	Average Monthly Volumes	Index	Price ($/gal)
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, Eagle Rock entered into the following crude oil swaps for 2009 and 2010 to help mitigate its upstream business’ commodity price exposure:

Period	Commodity	Average Monthly Volumes	Index	Swap Price ($/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

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

Period	Commodity	Average Monthly Volumes	Index	Swap Price ($/gal)
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

On November 7 and 8, 2007, Eagle Rock Energy entered into additional commodity hedge transactions (excluding transactions settled in previous periods), as described below:

Period	Commodity	Average Monthly Volumes	Index	Swap Price ($/Bbl)
Jan-Dec 2010	Crude oil	10,000Bbl	NYMEX WTI	78.35
Jan-Dec 2011	Crude oil	45,000Bbl	NYMEX WTI	80.00
Jan-Dec 2012	Crude oil	40,000 Bbl	NYMEX WTI	80.30
Jan-Dec 2009	Natural Gas	85,000 MMBtu	NYMEX	8.35

Period	Commodity	Average Monthly Volumes	Index	Floor ($/Bbl)	Cap $/Bbl
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 tables above, Eagle Rock Energy also bought back at no cost to Eagle Rock Energy an option on a swap (“swaption”) during the year ended December 31, 2007. Under that agreement, the other party had the right, but not the obligation, to enter into a swap with Eagle Rock Energy for 26,000 Bbls of NYMEX WTI per month during the period from January to December 2009 at a strike price of $85.00.

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During the year ended December 31, 2008, Eagle Rock Energy assumed the following derivative transactions related to its Upstream and Midstream Businesses in association with the Stanolind and Millennium acquisitions during the year ended December 31, 2008. Transactions shown with a floor price only are puts; all other are costless collars (excluding transactions that settled in previous periods).

		Average Monthly Volumes		Price ($/mmbtu or $/bbl)
Period	Commodity		Index	Avg. Floor	Avg. Ceiling
Jan-Mar 2009	Gas	20,000 MMBtu	NYMEX	9.00	9.85
Apr-Jun 2009	Gas	20,000 MMBtu	NYMEX	7.50	7.95
Jul-Sep 2009	Gas	20,000 MMBtu	NYMEX	7.50	8.60
Jan-May 2009	Gas	40,000 MMBtu	NYMEX	7.50	8.90
Jan-Dec 2009	Oil	10,000 Bbl	NYMEX WTI	93.00	105.20
Jan-Dec 2010	Oil	9,000 Bbl	NYMEX WTI	90.00	99.80

Eagle Rock Energy entered into the following transactions associated with its Midstream Business during the year ended December 31, 2008.  For the crude oil puts that were acquired, Eagle Rock Energy paid premiums totaling $3.3 million.  The natural gas collars were costless transactions that were entered into in order to reduce Eagle Rock Energy’s exposure to potential natural gas increases.  For these collars, Eagle Rock Energy sold floors and bought caps to offset previous derivative transactions and these collars were necessary because of a change in Eagle Rock Energy’s expected net natural gas position (excluding transactions that settled in previous periods).

		Average Monthly Volumes		Price ($/mmbtu or $/bbl)
Period	Commodity		Index	Avg. Floor	Avg. Ceiling
Jan-Mar 2009	Gas	92,700 MMBtu	NYMEX	8.80	13.75
Jan-Dec 2009	Oil	7,000 Bbl	NYMEX WTI	90.00
Jan-Dec 2009	Oil	5,000 Bbl	NYMEX WTI	100.00
Jan-Dec 2009	Oil	6,000 Bbl	NYMEX WTI	90.00
Jan-Dec 2009	Oil	5,000 Bbl	NYMEX WTI	100.00

On October 31, 2008, Eagle Rock Energy entered into following transaction:

Period	Commodity	Average Monthly Volumes	Index	Swap Price ($/Bbl)
Jan-Dec 2009	Crude oil	50,000 Bbl	NYMEX WTI	100.00

The above swap was part of a transaction in which Eagle Rock Energy reset two existing crude oil swaps.  The first swap was reset from $73.90 to $100 on 80,000 barrels per month for the months of November and December 2008 (this swap is excluded from the table because it has already settled).  The cost of this reset swap was $4.1 million.  The second swap was reset from $80.25 to $100 per barrel on 50,000 barrels per month for calendar year 2009.  The cost to reset this swap was $11.7 million.

On November 25, 2008, Eagle Rock Energy entered into the following swap transactions on natural gas volumes for 2009 per the following table:

Period	Commodity	Average Monthly Volumes	Index	Swap Price ($/Bbl)
Jan-Dec 2009	Gas	70,000 MMbtu	NYMEX WTI	6.685
Jun-Dec 2009	Crude oil	70,000 MMbtu	NYMEX WTI	6.885

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

Eagle Rock Energy 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.  As of December 31, 2008, the fair value of these contracts, including derivative costs, totaled $109.2 million.

On January 8, 2009, Eagle Rock Energy executed a series of hedging transactions that involved unwinding certain existing derivative contracts and entering into new derivative contracts.  See Note 17 for further discussion of these transactions.

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NOTE 13. COMMITMENTS AND CONTINGENT LIABILITIES

Litigation—Eagle Rock Energy is subject to several lawsuits which arise from time to time in the ordinary course of business, such as the interpretation and application of contractual terms related to the calculation of payment for liquids and natural gas proceeds. Eagle Rock Energy has accruals of approximately $0.1 million as of December 31, 2008, related to these matters. Eagle Rock Energy has been indemnified up to a certain dollar amount for two of these lawsuits. For the indemnified lawsuits, Eagle Rock Energy 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 Eagle Rock Energy in the indemnified cases, Eagle Rock Energy 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 its financial position.

Insurance—Eagle Rock Energy covers its operations and assets with insurance which management believes is consistent with that in force for other companies engaged in similar commercial operations with similar type properties.  This insurance includes: (1) commercial general liability insurance covering liabilities to third parties for bodily injury, property damage and pollution arising out of Eagle Rock Energy operations; (2) workers’ compensation liability coverage for employees to required statutory limits; (3) automobile liability insurance covering liability to third parties for bodily injury and property damage arising out of the operation of all owned, hired and non-owned vehicles by its employees on company business; (4) property insurance covering the replacement cost of all owned real and personal property, including coverage for losses due to boiler and machinery breakdown, earthquake, flood and consequent business interruption/extra expense; (5) control of well/operator’s extra expense insurance for operated and non operated wells in the Upstream Segment; and (6) corporate liability insurance including coverage for Directors and Officers and Employment Practices liabilities.  In addition, Eagle Rock Energy maintains excess liability insurance providing limits in excess of the established primary limits for commercial general liability and automobile liability insurance.

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

Regulatory Compliance—In the ordinary course of business, Eagle Rock Energy is subject to various laws and regulations. In the opinion of management, Eagle Rock Energy 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, Eagle Rock Energy 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 Eagle Rock Energy’s combined results of operations, financial position or cash flows. At December 31, 2008, Eagle Rock Energy had accrued approximately $8.6 million for environmental matters.

In June 2008, the Texas Commission on Environmental Quality (“TCEQ”) issued a Notice of Enforcement (“NOE”) to one of Eagle Rock Energy’s subsidiaries, TCEQ ID No.: CF-0068-J (the “First NOE”) and another NOE to another of its subsidiaries (TCEQ ID No.: CF-0070-W) (the “Second NOE”).  Both the First NOE and the Second NOE were the result of findings made by the TCEQ’s Amarillo Region Office as a result of routine inspections of Eagle Rock Energy’s Cargray facilities in the Texas Panhandle.  These NOEs were consolidated into one docket during negotiations between Eagle Rock Energy and the TCEQ. On October 28, 2008, Eagle Rock Energy executed an Agreed Order resolving with the TCEQ the two NOE matters by, among other things, payment of an administrative penalty and Supplemental Environmental Project payment which, in the aggregate, were less than $10,000. Eagle Rock Energy considers these matters concluded.

On September 29, 2008, the TCEQ issued another NOE to one of Eagle Rock Energy’s subsidiaries concerning the environmental compliance of its Red Deer Gas Plant; TCEQ ID No.: RH-0004-B (the “Third NOE”). The allegations in the Third NOE are also the result of findings made by the TCEQ’s Amarillo Region Office as a result of a routine inspection.  In response, Eagle Rock Energy’s subsidiary took certain steps to come into compliance, and provided substantial documentation, some of which is corrective in nature, to the TCEQ. Eagle Rock Energy also contested certain allegations. On December 5, 2008, TCEQ issued a proposed Agreed Order to Eagle Rock Energy, offering settlement by, among other things, payment of an administrative penalty. On February 13, 2009, Eagle Rock Energy executed this Agreed Order, paying an administrative penalty and Supplemental Environmental Project payment which, in the aggregate, were $46,072. Eagle Rock Energy considers this matter concluded.

Eagle Rock Energy has voluntarily undertaken a self-audit of its compliance with air quality standards, including permitting in the Texas Panhandle Segment as well as a majority of its other Midstream Business locations and some of its Upstream Business locations. This auditing has been and is being undertaken pursuant to the Texas Environmental, Health and Safety Audit Privilege Act, as amended. Eagle Rock Energy has begun making the disclosures to the TCEQ as a result of the completion of the first of these self audits, and it is addressing in due course the deficiencies that it disclosed therein.  Eagle Rock Energy does not foresee at this time any impediment to its successful conclusion of these audits and the resulting corrective effort.

Since 2008, Eagle Rock Energy has received additional NOEs and a notice of violation from the TCEQ related to air compliance matters in the Texas Panhandle Segment.  One of the NOEs has been resolved for $2,575. Eagle Rock Energy expects to receive additional NOEs or NOVs from the TCEQ from time to time throughout 2009.  Though the TCEQ has the discretion  to adjust penalties and settlements upwards based on a compliance history containing multiple, successive NOEs, Eagle Rock Energy does not expect that the resolution of any existing NOE or any future similar NOE will vary significantly from the administrative penalties and agreed settlements experienced by it to date.

Retained Revenue Interest—Certain assets of Eagle Rock Energy’s Upstream Segment are subject to retained revenue interests.  These interests were established under purchase and sale agreements that were executed by Eagle Rock Energy’s predecessors in title.  The terms of these agreements entitle the owners of the retained revenue interests to a portion of the revenues received from the sale of the hydrocarbons above specified base oil and natural gas prices.  These retained revenue interests do not represent a real property interest in the hydrocarbons.  

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

Other Commitments—Eagle Rock Energy 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 for leases with escalation clauses is recognized on a straight-line basis over the initial lease term. At December 31, 2008, commitments under long-term non-cancelable operating leases for the next five years are as follows: 2009—$1.7 million; 2010—$0.8 million; 2011—$0.7 million; 2012—$0.6 million; and 2013—$0.6 million.

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NOTE 14. SEGMENTS

Based on Eagle Rock Energy’s approach to managing its assets, Eagle Rock Energy believes its operations consist of four 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/Louisiana Segment:

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

(iv) Midstream—Gulf of Mexico Segment:

Gathering and processing of natural gas; and fractionation, transportation and marketing of NGLs in South Louisiana, Gulf of Mexico and inland waters of Texas;

(v) Upstream Segment:

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

(vi) 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

           (vii)       Corporate Segment: risk management and other corporate activities.

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

Year Ended December 31, 2008	Texas Panhandle Segments		South Texas Segment		East Texas/ Louisiana Segment		Gulf of Mexico Segment		Total Midstream Segments
	($ in millions)
Segment Assets	$	543.5	$	97.3	$	368.6	$	80.1	$	1,089.5

Year Ended December 31, 2008	Total Midstream Segments		Upstream Segment		Minerals Segment		Corporate Segment		Total Segments
	($ in millions)
Segment Assets	$	1,089.5	$	398.0	$	143.9	$	141.7	$	1,773.1

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NOTE 15. INCOME TAXES

Income tax relate primarily to federal and state income taxes for Eagle Rock Energy and federal income taxes for Eagle Rock Acquisition Co., Inc., Eagle Rock Upstream Development Company, Inc., Eagle Rock Acquisition Co. II, Inc., and Eagle Rock Upstream Development Company II, Inc., Eagle Rock Energy’s wholly owned corporations, which are subject to federal income taxes.  Eagle Rock Upstream Development Company, Inc. was formerly known as Redman Energy Corporation and was acquired in the form of a corporate entity as part of the Redman Acquisition in July 2007 and Eagle Rock Upstream Development Company II, Inc, was formerly known as Stanolind Oil and Gas Corp. and was acquired in the form of a corporate entity as part of the Stanolind Acquisition in April 2008.  In addition, with the amendment of the Texas Franchise Tax in 2006, Eagle Rock Energy became a taxable entity in the state of Texas.

Significant components of deferred tax liabilities and deferred tax assets are as follows (in thousands):

	December 31, 2008
Deferred Tax Assets:
Net operating loss carryovers	$	3,616
Current year adjustment to net operating loss carryforwards		(2,444	)
Statutory depletion carryover		1,842
AMT credit carryforward		140
Unrealized hedging transactions		—
Total deferred tax		3,154
Less: Valuation allowance		(3,154	)
Net Deferred Tax Assets		—
Deferred Tax Liabilities:
Property, plant equipment & amortizable assets		(2,621	)
Unrealized hedging transactions		(765	)
Book/tax differences from partnership investment		(38,963	)
Total Deferred Tax Liabilities		(42,349	)
Total Net Deferred Tax Liabilities	$	(42,349	)
Current portion of total net deferred tax liabilities	$	—
Long-term portion of total net deferred tax liabilities	$	(42,349	)

Eagle Rock Energy had net operating loss carryforwards and depletion deduction carryforwards of $1.2 million at December 31, 2008. These losses expire in various years between 2008 and 2028 and are subject to limitations on their utilization. Eagle Rock Energy records a valuation allowance to reduce its deferred tax assets to the amount of future tax benefit that is more likely than not to be realized. The valuation allowance was $3.1 million at December 31, 2008. Of the $3.1 million valuation allowance at December 31, 2008, none is for timing differences from hedging transactions which impact the Texas Margins Tax and $3.0 million is from net operating loss carryovers from the C Corporations and $0.1 is from AMT credit carryforwards from the C corporations.  Eagle Rock Energy expects to pay minimal federal taxes for the foreseeable future and this valuation allowance serves to eliminate the recognized tax benefit associated with carryovers of our corporate entities to an amount that will, more likely than not, be realized.

The largest single component of Eagle Rock Energy’s deferred tax liabilities is related to federal income taxes of the C Corporations described above.  Book/tax differences were created by the Redman and Stanolind Acquisitions. These book/tax temporary differences result in a net deferred tax liability of $39.0 million at December 31, 2008, which will be reduced as allocation of depletion in proportion to the assets contributed brings the book and tax basis closer together over time. This deferred tax liability was recognized in conjunction with the purchase accounting adjustments for long term assets.

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

Although the bill states that the Revised Texas Franchise Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. Due to the enactment of the Revised Texas Franchise Tax, Eagle Rock Energy recorded a net deferred tax liability of $3.4 million.

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

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NOTE 16. EQUITY-BASED COMPENSATION

Eagle Rock Energy G&P, LLC the general partner of the general partner for Eagle Rock Energy, approved a long-term incentive plan (LTIP), as amended, for its employees, directors and consultants who provide services to Eagle Rock Energy covering an aggregate of 2,000,000 common units to be granted either as options, restricted units or phantom units.  During the year ended December 31, 2008, Eagle Rock Energy granted 741,150 restricted common units.  The restricted units granted in 2008 were valued at the market price as of the date issued. The weighted average fair value of the units granted during the year ended December 31, 2008 was $14.89. 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 unit activity for the year ended December 31, 2008, is provided below:

	Number of Restricted Units			Weighted Average Fair Value
Outstanding at December 31, 2007		467,062		$	23.01
Granted		741,150		$	14.86
Vested		(162,302	)	$	22.69
Forfeitures		(140,424	)	$	19.09
Outstanding at December 31, 2008		905,486		$	17.00

The total grant date fair value of restricted units that vested during the year ended December 31, 2008 was $3.7 million.

As of December 31, 2008, unrecognized compensation costs related to the outstanding restricted units under its LTIP totaled approximately $13.3 million. The remaining expense is to be recognized over a weighted average of 2 years.

In addition to equity awards involving units of Eagle Rock Energy, Eagle Rock Holdings, L.P., which is controlled by NGP, in the past has from time to time granted equity in Holdings to certain employees working on behalf of Eagle Rock

Energy, some of which are named executive officers.  During 2008, Holdings granted 417,000 “Tier I” incentive interests in the aggregate to six Eagle Rock employees.  One of these employees subsequently forfeited 200,000 of the interests upon his resignation from Eagle Rock in 2008.  The Tier I incentive interests entitle the holder to share in the cash distributions of Holdings upon achieving a certain payout target, which was reached in 2006.  Holdings also granted 33,415 “Tier III” incentive units during 2008 (20,000 of which were subsequently forfeited in 2008).  These units have not achieved their payout target and as such have no impact to compensation.

Eagle Rock Energy has no discretion in granting any awards at the Holdings level.  The Tier I incentive interests are intended to provide additional motivation for the grantees to create value at Holdings, in part through their actions to increase the value of Eagle Rock Energy.  Because the incentive interests represent an interest in the future profits of Holdings, and receive distributions only from the cash flow at Holdings, the incentive interests create no burden on, or dilution to, the returns on Eagle Rock Energy’s common units.  On the contrary, the incentive units are solely a burden on, and dilutive to, the returns of the equity owners of Holdings, including NGP as the substantial majority owner of Holdings.  Despite this, under the guidance of U.S. Securities and Exchange Commission Staff Accounting Bulletin Topic 1.B: “Allocation Of Expenses And Related Disclosure In Financial Statements Of Subsidiaries, Divisions Or Lesser Business Components Of Another Entity,” Eagle Rock Energy recorded a portion of the value of the incentive units as compensation expense in Eagle Rock Energy’s financial statements.  This allocation is based on management’s estimation of the total value of the incentive unit grant and of the grantee’s portion of time dedicated to Eagle Rock Energy.  Eagle Rock recorded a non-cash compensation expense of $1,665,831 based on management’s estimates related to the Tier I incentive unit grants made by Holdings in 2008.

NOTE 17.   SUBSEQUENT EVENTS

On January 8, 2009, Eagle Rock Energy executed a series of hedging transactions that involved the unwinding of a portion of existing “in-the-money” 2011 and 2012 WTI crude oil swaps and collars, and the unwinding of two “in-the-money” 2009 WTI crude oil collars. With these transactions, and an additional $13.9 million of cash, Eagle Rock Energy purchased a 2009 WTI crude oil swap on 60,000 barrels per month beginning January 1, 2009 at $97 per barrel. Both the unwound hedges and new hedges relate to expected volumes in Eagle Rock Energy’s Midstream and Minerals Segments.

In addition to the hedging transactions discussed above, Eagle Rock Energy also entered into a 125,000 MMBtu per month Henry Hub natural gas swap at $6.65/MMBtu on January 19, 2009 for its 2009 fiscal year, a 170,000 MMBtu per month Henry Hub natural gas swap at $6.14/MMBtu on February 17, 2009 for its 2010 fiscal year, a 45,000 barrel per month WTI crude oil swap at $53.55 per barrel on February 17, 2009 for its 2010 fiscal year and a 40,000 barrel per month WTI crude oil swap at $51.40 per barrel on February 19, 2009 for its 2010 fiscal year.

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NOTE 18. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil and Natural Gas Reserves

Users of this information should be aware that the process of estimating quantities of proved and proved developed oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure the reported reserve estimates represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made.

Estimates of proved developed reserves as of December 31, 2008, were based on estimates made by Eagle Rock Energy’s independent engineers, Cawley, Gillespie & Associates, Inc (“Cawley Gillespie”). In 2008, Cawley Gillespie was engaged by and provided their reports to Eagle Rock Energy’s senior management team.  In order to enhance its controls regarding reserve reporting, Eagle Rock Energy recently modified the charter of the Audit Committee to include the right to engage the independent engineers, in consideration of management’s recommendations.  For 2009, management has recommended, and the Audit Committee has approved its continued engagement with Cawley Gillespie.

In January 2009, the SEC issued new rules for reserves reporting.  These rules are not currently effective, and the SEC has specifically prohibited early adoption of them.  Eagle Rock Energy will adopt them in its 2009 annual report, however.  The new rules include several significant changes, such as the use of average (rather than year-end), the optional inclusion of probable and possible reserves, and the option to include price sensitivities.

Eagle Rock Energy makes representations to the independent engineers that it has provided all relevant operating data and documents, and in turn, it reviews the reserve reports provided by the independent engineers to ensure completeness and accuracy. The Chief Executive Officer makes the final decision on booked proved reserves by incorporating the proved reserves from the independent engineers’ reports.

Eagle Rock Energy’s relevant management controls over proved reserve attribution, estimation and evaluation include:

• Controls over and processes for the collection and processing of all pertinent operating data and documents needed by the independent reservoir engineers to estimate Eagle Rock Energy’s proved reserves; and

• Engagement of well qualified and independent reservoir engineers for review of its operating data and documents and preparation of reserve reports annually in accordance with all SEC reserve estimation guidelines.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. Reserve data represent estimates only and should not be construed as being exact. Moreover, the standardized measure should not be construed as the current market value of the proved oil and natural gas reserves or the costs that would be incurred to obtain equivalent reserves. A market value determination would include many additional factors including (a) anticipated future changes in natural gas and crude oil prices, production and development costs, (b) an allowance for return on investment, (c) the value of additional reserves, not considered proved at present, which may be recovered as a result of further exploration and development activities, and (d) other business risk.

The following table illustrates Eagle Rock Energy’s estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by Cawley, Gillespie and Associates. Natural gas liquids are included in oil reserves. Oil and natural gas liquids are based on the December 31, 2008 West Texas Intermediate posted price of $44.60 per barrel and are adjusted by lease for quality, transportation fees, and regional price differentials. Gas prices are based on a December 31, 2008 Henry Hub spot market price of $5.63 per MMBtu and are adjusted by lease for energy content, transportation fees, and regional price differentials. All prices are held constant in accordance with SEC guidelines.   All of Eagle Rock Energy’s reserves are located in the United States.

	Proved Reserves
	Oil (MBbls)			Gas (MMcf)			Natural Gas Liquids (MBbls)
Proved reserves, January 1, 2008		10,081			44,643			5,743
Extensions and discoveries		189			3,566			45
Purchase of minerals in place		3,513			8,157			1,432
Production		(988	)		(5,400	)		(508	)
Sale of minerals in place		—			—			—
Revision of previous estimates		(2,789	)		(6,378	)		(1,073	)
Proved reserves, December 31, 2008		10,006			44,588			5,639
	Proved Developed Reserves
	Oil (MBbls)			Gas (MMcf)			Natural Gas Liquids (MBbls)
December 31, 2008		10,568			40,908			5,391

In 2008, Eagle Rock Energy experienced significant negative revisions to its proved reserves.  These revisions can be attributed to technical factors and economic factors.  Revisions due to economic factors are primarily due to the dramatic decline in commodity prices that occurred between December 31, 2007 and December 31, 2008.  Eagle Rock Energy estimates that approximately 3,782 mboe of the 2008 negative reserve revisions can be attributed to price changes.

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Capitalized Costs Relating to Oil and Natural Gas Producing Activities

The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization (in thousands) at December 31, 2008.

	December 31, 2008
Evaluated properties	$	593,520
Unevaluated properties—excluded from depletion		73,622
Gross oil and gas properties		667,142
Accumulated depreciation, depletion, amortization		(52,771	)
Impairment		(108,758	)
Net oil and gas properties	$	505,613

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

Costs incurred in property acquisition, exploration and development activities were as follows (in thousands) for the years ended December 31, 2008 and 2007:

	2008
Property acquisition costs, proved	$	110,747
Property acquisition costs, unproved		7,597
Exploration and extension well costs		1,610
Development costs		12,294
Total costs	$	132,248

Eagle Rock Energy’s exploration and extension well costs are primarily related to low risk drilling around its existing fields.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following information has been developed utilizing SFAS 69, Disclosures about Oil and Gas Producing Activities, (SFAS 69) procedures and is based on oil and natural gas reserves estimated by the Company’s independent reserves engineer. It can be used for some comparisons, but should not be the only method used to evaluate Eagle Rock Energy or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flow be viewed as representative of the current value of Eagle Rock Energy.

Eagle Rock Energy believes that the following factors should be taken into account when reviewing the following information:

• future costs and selling prices will probably differ from those required to be used in these calculations;

• due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations; and

• a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues.

Under the Standardized Measure, future cash inflows were estimated by applying year-end oil and natural gas prices to the estimated future production of year-end proved reserves. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor. Use of a 10% discount rate and year-end prices are required by SFAS 69.

In Eagle Rock Energy’s Standardized Measure calculations it has excluded the future revenues that would be associated with the sales of sulfur since it is not a hydrocarbon and SFAS 69 does not allow for the inclusion of non-hydrocarbon revenues.  Also, it has included the expected impact of the retained revenue interests as a revenue reduction.

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The Standardized Measure is as follows (in thousands) as of December 31, 2008:

	December 31, 2008
Future cash inflows	$	788,154
Future production costs		(322,931	)
Future development costs		(60,189	)
Future net cash flows before income taxes		405,034
Future income tax benefit		1,895
Future net cash flows before 10% discount		406,929
10% annual discount for estimated timing of cash flows		(197,185	)
Standardized measure of discounted future net cash flows	$	209,744

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for Eagle Rock Energy’s proved oil and natural gas reserves for the year ended December 31, 2008 (in thousands).

	2008
Beginning of year	$	556,960
Sale of oil and gas produced, net of production costs		(127,125	)
Net changes in prices and production costs		(293,537	)
Extensions, discoveries and improved recovery, less related costs		8,842
Previously estimated development costs incurred during the period		(12,294	)
Net changes in future development costs		11,766
Revisions of previous quantity estimates		(49,546	)
Purchases of property		45,239
Sales of property		—
Accretion of discount		50,531
Net changes in income taxes		1,033
Other		17,875
End of year	$	209,744