Eagle Rock Energy Partners L P 10Q 2008 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_______________

FORM 10-Q

T QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2008

£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

Commission File No. 001-33016

_______________

EAGLE ROCK ENERGY PARTNERS, L.P.

(Exact Name of Registrant as Specified in Its Charter)

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

16701 Greenspoint Park Drive, Suite 200

Houston, Texas 77060

(Address of principal executive offices, including zip code)

(281) 408-1200

(Registrant’s telephone number, including area code)

_______________

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes R No £

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

Large accelerated filer £	Accelerated filer R
Non-accelerated filer £	Smaller Reporting Company £
(Do not check if a smaller reporting company)

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

The issuer had 50,824,031 common units outstanding as of August 7, 2008.

EAGLE ROCK ENERGY PARTNERS, L.P.

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements
	Unaudited Condensed Consolidated Balance Sheets as of June 30, 2008 and December 31, 2007	2
	Unaudited Condensed Consolidated Statements of Operations for the three months and six months ended June 30, 2008 and 2007	3
	Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2008 and 2007	4
	Unaudited Condensed Consolidated Statements of Members’ Equity for the six months ended June 30, 2008	5
	Notes to Unaudited Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	41
Item 4.	Controls and Procedures	43

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	46
Item 1A.	Risk Factors	46
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 3.	Defaults Upon Senior Securities	46
Item 4.	Submission of Matters to a Vote of Security Holders	46
Item 5.	Other Information	46
Item 6.	Exhibits	47

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

($ in thousands, except unit amounts)

	June 30, 2008			December 31, 2007

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	64,586		$	68,552
Accounts Receivable(1)		186,182			135,663
Risk management assets		4,528			—
Prepayments and other current assets		5,603			3,962
Total current assets		260,899			208,177
PROPERTY, PLANT AND EQUIPMENT — Net		1,315,440			1,207,130
INTANGIBLE ASSETS — Net		145,634			153,948
GOODWILL		30,513			29,527
OTHER ASSETS		12,497			11,145
TOTAL	$	1,764,983		$	1,609,927
LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	203,699		$	132,485
Due to affiliate		21,069			16,964
Accrued liabilities		16,893			9,776
Income taxes payable		316			723
Risk management liabilities		164,006			33,089
Total current liabilities		405,983			193,037
LONG-TERM DEBT		623,000			567,069
ASSET RETIREMENT OBLIGATIONS		16,773			11,337
DEFERRED INCOME TAXES		43,585			17,516
RISK MANAGEMENT LIABILITIES		259,985			94,200
COMMITMENTS AND CONTINGENCIES (Note 12)
MEMBERS’ EQUITY:
Common Unitholders(2)		398,886			617,563
Subordinated Unitholders(3)		23,556			112,360
General Partner(4)		(6,785	)		(3,155	)
Total members’ equity		415,657			726,768
TOTAL	$	1,764,983		$	1,609,927

(1)	Net of allowable for bad debt of $7,179 and $1,046 as of June 30, 2008 and December 31, 2007, respectively.
(2)	50,824,031 and 50,699,647 units were issued and outstanding as of June 30, 2008 and December 31, 2007, respectively. These amounts do not include unvested restricted common units granted under the Partnership’s long-term incentive plan of 787,947 and 467,062 as of June 30, 2008 and December 31, 2007, respectively.
(3)	20,691,495 units were issued and outstanding as of June 30, 2008 and December 31, 2007, respectively.
(4)	844,551 units were issued and outstanding as of June 30, 2008 and December 31, 2007, respectively.

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

($ in thousands, except per unit amounts)

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
REVENUE:
Natural gas, natural gas liquids, oil, condensate and sulfur sales	$	451,769		$	191,621		$	808,788		$	301,742
Gathering, compression processing fees		8,085			6,883			15,228			11,166
Mineral and royalty income		10,255			3,192			17,213			3,192
Commodity risk management losses		(283,973	)		(27,255	)		(329,620	)		(34,897	)
Other revenue		122			—			182			—
Total revenue		186,258			174,441			511,791			281,203
COSTS AND EXPENSES:
Cost of natural gas and natural gas liquids		353,558			164,364			629,389			255,000
Operations and maintenance		17,731			11,396			33,297			19,320
Taxes other than income		5,263			728			9,610			1,430
General and administrative		10,026			5,171			21,268			9,391
Other operating expense		6,214			—			6,214			1,711
Depreciation, depletion and amortization		26,457			14,149			52,202			25,779
Total costs and expenses		419,249			195,808			751,980			312,631
OPERATING LOSS		(232,991	)		(21,367	)		(240,189	)		(31,428	)
OTHER INCOME (EXPENSE):
Interest income		160			176			461			300
Other income		886			91			2,433			91
Interest expense, net		(6,974	)		(8,519	)		(16,078	)		(16,399	)
Interest rate risk management gains (losses)		11,245			6,803			(2,516	)		5,408
Other expense		(232	)		(711	)		(447	)		(1,003	)
Total other (expense) income		5,085			(2,160	)		(16,147	)		(11,603	)
LOSS BEFORE INCOME TAXES		(227,906	)		(23,527	)		(256,336	)		(43,031	)
INCOME TAX (BENEFIT) PROVISION		(886	)		256			(988	)		420
NET LOSS	$	(227,020	)	$	(23,783	)	$	(255,348	)	$	(43,451	)
NET LOSS PER COMMON UNIT — BASIC AND DILUTED:
Basic and diluted net loss:
Common units	$	(3.14	)	$	(0.28	)	$	(3.54	)	$	(0.55	)
Subordinated units	$	(3.14	)	$	(0.71	)	$	(3.54	)	$	(1.36	)
General partner units	$	(3.14	)	$	(0.71	)	$	(3.54	)	$	(1.36	)
Basic and diluted weighted average number outstanding:
Common units		50,762			30,613			50,731			25,680
Subordinated units		20,691			20,691			20,691			20,691
General partner units		845			845			845			845

See notes to unaudited condensed consolidated financial statements.

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

($ in thousands)

	Six Months Ended June 30,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(255,348	)	$	(43,451	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		52,202			25,779
Amortization of debt issuance costs		436			872
Reclassifying financing derivative settlements		9,537			(100	)
Distribution from unconsolidated affiliates – return on investment		509			—
Equity in earnings of unconsolidated affiliates		(2,433	)		—
Equity-based compensation expense		2,718			792
Other		(825	)		(855	)
Changes in assets and liabilities — net of acquisitions:
Accounts receivable		(48,032	)		(24,943	)
Prepayments and other current assets		(901	)		223
Risk management activities		289,308			34,524
Accounts payable		65,571			28,328
Due to affiliates		4,105			—
Accrued liabilities		6,021			6,212
Other assets and liabilities		(224	)		738
Net cash provided by operating activities		122,644			28,119
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions, net of cash acquired		(81,289	)		(114,654	)
Additions to property, plant and equipment		(33,080	)		(37,993	)
Advances to affiliates		—			(10,665	)
Purchase of intangible assets		(1,011	)		(1,199	)
Other		—			22
Net cash used in investing activities ��		(115,380	)		(164,489	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of revolving credit facility		(50,069	)		(18,000	)
Proceeds from revolving credit facility		106,000			34,400
Proceeds (payments) on derivative contracts		(9,537	)		100
Proceeds from equity issuance		—			127,500
Distributions to members and affiliates		(57,624	)		(16,185	)
Net cash provided by (used in) financing activities		(11,230	)		127,815
NET CHANGE IN CASH AND CASH EQUIVALENTS		(3,966	)		(8,555	)
CASH AND CASH EQUIVALENTS — Beginning of period		68,552			10,581
CASH AND CASH EQUIVALENTS — End of period	$	64,586		$	2,026

SUPPLEMENTAL CASH FLOW DATA:
Interest paid — net of amounts capitalized	$	12,442		$	7,925
Investments in property, plant and equipment not paid	$	1,885		$	4,892
Acquisition of assets for equity	$	—		$	182,291

See notes to unaudited condensed consolidated financial statements.

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF MEMBERS’ EQUITY

FOR THE SIX MONTHS ENDED JUNE 30, 2008

($ in thousands, except unit amounts)

	General Partner Units		General Partner			Number of Common Units		Common Units			Number of Subordinated Units		Subordinated Units			Total

BALANCE —December 31, 2007		844,551	$	(3,155	)		50,699,647	$	617,563			20,691,495	$	112,360		$	726,768
Net loss		—		(2,987	)		—		(179,172	)		—		(73,189	)		(255,348	)
Distributions		—		(669	)		—		(40,557	)		—		(16,398	)		(57,624	)
Vesting of restricted units		—		—			124,384		—			—		—			—
Distribution to affiliates		—		—			—		(857	)		—		—			(857	)
Restricted unit expense		—		26			—		1,909			—		783			2,718
BALANCE — June 30, 2008		844,551	$	(6,785	)		50,824,031	$	398,886			20,691,495	$	23,556		$	415,657

See notes to unaudited condensed consolidated financial statements.

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2008

NOTE 1. ORGANIZATION AND DESCRIPTION OF BUSINESS

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

Basis of Presentation and Principles of Consolidation—The accompanying financial statements include assets, liabilities and the results of operations of the Partnership. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2007. That report contains a more comprehensive summary of the Partnership’s major accounting policies. In the opinion of management, the accompanying unaudited condensed consolidated financial statements contain all appropriate adjustments, all of which are normally recurring adjustments unless otherwise noted, considered necessary to present fairly the financial position of the Partnership and its consolidated subsidiaries and the results of operations and cash flows for the respective periods. Operating results for the three and six-month periods ending June 30, 2008 are not necessarily indicative of the results that may be expected for the year ending December 31, 2008.

Description of Business—The Partnership is a growth-oriented limited partnership engaged in the business of (i) gathering, compressing, treating, processing, transporting and selling natural gas, fractionating and transporting natural gas liquids, or NGLs, which the Partnership calls its “Midstream” business, (ii) acquiring, developing and producing interests in oil and natural gas properties, which the Partnership calls its “Upstream” business and (iii) acquiring and managing fee minerals and royalty interest in producing oil and gas wells located in multiple producing trends across the United States, which the Partnership calls its “Minerals” business. See Note 13 for a further description of the Partnership’s three business and the six accounting segments in which it reports.

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The accompanying condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. All intercompany accounts and transactions are eliminated in the consolidated financial statements.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Significant estimates are required for proved oil and natural gas reserves, which can affect the carrying value of oil and natural gas properties. The Partnership evaluates its estimates and assumptions on a regular basis. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates and such differences could be material.

The Partnership has provided a discussion of significant accounting policies in its annual report on Form 10-K for the year ended December 31, 2007. Certain items from that discussion are updated below.

Oil and Natural Gas Accounting Policies

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

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2008

Depletion of proved 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.

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

Unproved properties that are individually insignificant are amortized. Unproved properties that are individually significant are assessed for impairment on a property-by-property basis. If considered impaired, costs are charged to expense when such impairment is deemed to have occurred.

Significant Accounting Policies

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

The Partnership acquired goodwill as part of its acquisition of Redman Energy Holdings, L.P., and Redman Energy Holdings II, L.P. on July 31, 2007. During the six months ended June 30, 2008, goodwill increased by $1.0 million due to adjustments made to the Redman purchase price allocation. The Partnership will perform an impairment test for goodwill assets annually or earlier if indicators of potential impairment exist. The Partnership performed its annual goodwill impairment test in May 2008 and determined no impairment appeared evident. The Partnership’s goodwill impairment test involves a comparison of the fair value of each of its reporting units with their carrying value. The fair value is determined using discounted cash flows and other market-related valuation models. Certain estimates and judgments are required in the application of the fair value models. Since the date of the acquisition, no event occurred or circumstances changed that would more likely than not reduce the fair value of a reporting unit below its carrying value. If for any reason the fair value of the goodwill or that of any of the Partnership’s reporting units’ declines below the carrying value in the future, the Partnership may incur charges for the impairment.

Transportation and Exchange Imbalances—In the course of transporting natural gas and natural gas liquids for others, the Partnership’s midstream business may receive for redelivery different quantities of natural gas or natural gas liquids than the quantities actually delivered. These transactions result in transportation and exchange imbalance receivables or payables which are recovered or repaid through the receipt or delivery of natural gas or natural gas liquids in future periods, if not subject to cash out provisions. Imbalance receivables are included in accounts receivable and imbalance payables are included in accounts payable on the condensed 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 June 30, 2008, the Partnership had imbalance receivables totaling $0.7 million and imbalance payables totaling $5.3 million, respectively. For the midstream business, as of December 31, 2007, the Partnership had imbalance receivables totaling $0.2 million and imbalance payables totaling $2.7 million, respectively. Changes in market value and the settlement of any such imbalance at a price greater than or less than the recorded imbalance results in either an upward or downward adjustment, as appropriate, to the cost of natural gas and natural gas liquids sold.

Derivatives—Statement of Financial Accounting Statements (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended (“SFAS No. 133”), establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. SFAS No. 133 requires an entity to recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The Partnership uses financial instruments such as puts, swaps and other derivatives to mitigate the risks to cash flows resulting from changes in commodity prices and interest rates. The Partnership recognizes these financial instruments on its consolidated balance sheets at the instrument’s fair value with changes in fair value reflected in the consolidated statements of operations, as the Partnership has not designated any of these derivative instruments as hedges. The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as a financing activity in the statements of cash flows. See Note 11 for a description of the Partnership’s risk management activities.

Reclassifications—Certain prior period amounts have been reclassified to conform to current period presentation.

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2008

NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS

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

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

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

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS No. 141R”), which replaces SFAS 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 Partnership is currently evaluating the potential impact, if any, of the adoption of SFAS 141R on the Partnership’s financial statements.

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

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

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

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2008

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 for fiscal years beginning after December 15, 2008 and must be applied prospectively to intangible assets acquired after the effective date. The Partnership is currently evaluating the potential impact, if any, of FSP SFAS 142-3 on its financial statements.

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 is currently evaluating the potential impact, if any, of the adoption of SFAS 162 on its financial statements.

In June 2008, the FASB issued FSP No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (“FSP EITF 03-6-1”). FSP EITF 03-6-1 effects entities that accrue cash dividends on share-based payment awards during the awards’ service period when dividends do not need to be returned if the employees forfeit the awards. FSP EITF 03-6-1 is effective for fiscal years beginning after December 15, 2008 and earnings-per-unit calculations would need to be adjusted retroactively. The Partnership is currently evaluation the potential impact, if any of the adoption of FSP EITF 03-6-1 on its financial statements.

NOTE 4. ACQUISITIONS

On April 30, 2008, the Partnership completed the acquisition of all of the outstanding capital stock of Stanolind Oil and Gas Corp. (“Stanolind”), for an aggregate purchase price of $81.8 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 the Partnership and is the majority owner of the sole owner of Eagle Rock Energy G&P, LLC (the “Company”), which is the general partner of Eagle Rock Energy GP, L.P., which is the general partner of the Partnership. The Partnership funded the transaction from existing cash from operations as well as with borrowings under its existing credit facility. Stanolind owned and operated oil and natural gas producing properties in the Permian Basin, primarily in Ward, Crane and Pecos Counties, Texas.

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2008

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. The Partnership 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, the Partnership 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, the Partnership 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	$	110,691
Unproved properties		7,597
Cash and cash equivalents		537
Accounts receivable, net		2,517
Other current assets		710
Other assets		75
Accounts payable and accrued liabilities		(3,230	)
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		80,969
Distribution to NGP		857
Total consideration paid	$	81,826

The Partnership commenced recording results of operations on May 1, 2008. Pro forma income statement results for this acquisition would not have been materially different from the result presented by the Partnership with the condensed consolidated statement of operations.

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 owned 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 the Conflicts Committee, the Board of Directors approved the transaction.

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2008

NOTE 5. FIXED ASSETS AND ASSET RETIREMENT OBLIGATIONS

Fixed assets consisted of the following:

	June 30			December 31,
	2008			2007
	($ in thousands)

Land	$	1,154		$	1,153
Plant		191,588			181,689
Gathering and pipeline		550,139			541,247
Equipment and machinery		14,929			14,081
Vehicles and transportation equipment		3,782			3,657
Office equipment, furniture, and fixtures		1,023			1,023
Computer equipment		4,714			4,636
Corporate		126			126
Linefill		4,157			4,157
Proved properties		581,842			461,884
Unproved properties		73,634			66,023
Construction in progress		24,632			20,884
		1,451,720			1,300,560
Less: accumulated depreciation and amortization		(136,280	)		(93,430	)
Net fixed assets	$	1,315,440		$	1,207,130

Depreciation expense for the three and six months ended June 30, 2008 and for the three and six months ended June 30, 2007 was approximately $11.2 million, $22.0 million, $8.4 million and $16.0 million, respectively. Depletion expense for the three and six months ended June 30, 2008 and for the three and six months ended June 30, 2007 was approximately $10.6 million and $20.9 million, $1.5 million and $1.5 million, respectively.

The Partnership capitalizes interest costs on major projects during extended construction time periods. Such interest costs are allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. During the three and six months ended June 30, 2008 and 2007, the Partnership capitalized interest costs of approximately $0.2 million, $0.5 million, $0.3 million and $0.4 million, respectively.

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

Asset retirement obligations—December 31, 2007	$	11,337
Additional liability on newly constructed assets		204
Additional liability related to acquisitions		4,770
Accretion expense		462
Asset retirement obligations—June 30, 2008	$	16,773

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2008

NOTE 6. INTANGIBLE ASSETS

Intangible Assets—Intangible assets consist of right-of-ways and easements and acquired customer contracts, which the Partnership amortizes over the term of the agreement or estimated useful life. Amortization expense was approximately $4.7 million, $9.3 million, $4.2 million and $8.3 million for the three and six months ended June 30, 2008 and 2007, respectively. Estimated aggregate amortization expense for each of the five succeeding years is as follows: 2008—$18.0 million; 2009—$18.0 million; 2010—$17.1 million; 2011—$6.3 million; and 2012—$6.3 million. Intangible assets consisted of the following:

	June 30,			December 31,
	2008			2007
	($ in thousands)

Rights-of-way and easements—at cost	$	81,080		$	80,069
Customer contracts		108,772			108,772
		189,852			188,841
Less: accumulated amortization		(44,218	)		(34,893	)
Net intangible assets	$	145,634		$	153,948

The amortization period for our rights-of-way and easements is 20 years. The amortization period for contracts range from 5 to 20 years, and are approximately 8 years on average as of June 30, 2008.

NOTE 7. LONG-TERM DEBT

As of June 30, 2008 and December 31, 2007, the Partnership had $623.0 million and $567.1 million, respectively, outstanding under its $800 million secured revolving credit facility (“Revolving Credit Facility”). As of June 30, 2008, the Partnership was in compliance with the financial covenants under its Revolving Credit Facility.

Subsequent to June 30, 2008, the Partnership exercised $100 million of its $200 million accordion feature under the Revolving Credit Facility, which increased the total commitment to $900 million.

NOTE 8. MEMBERS’ EQUITY

At June 30, 2008, there were 50,824,031 common units, 20,619,495 subordinated units (all subordinated units owned by Holdings) and 844,551 general partner units outstanding. In addition, there were 787,947 unvested restricted common units outstanding at June 30, 2008.

Subordinated units represent limited liability interests in the Partnership, and holders of subordinated units exercise the rights and privileges available to unitholders under the limited liability partnership agreement. Subordinated units, during the subordination period, will generally receive quarterly cash distributions only when the common units have received a minimum quarterly distribution of $0.3625 per unit. Subordinated units will convert into common units on a one-for-one basis when the subordination period ends. The subordination period will end on the first business day after the Partnership has earned and paid at least $1.45 (the minimum quarterly distribution on an annualized basis) on each outstanding limited partner unit and general partner unit for any three consecutive, non-overlapping four quarter periods on or after September 30, 2009. Alternatively, the subordination period will end on the first business day after the Partnership earned and paid at least $0.5438 per quarter (150% of the minimum quarter distribution, which is $2.175 on an annualized basis) on each outstanding limited partner unit and general partner unit for any four consecutive quarters ending on or after September 30, 2007.

In addition, the subordination period will end upon the removal of the Partnership’s general partner other than for cause if the units held by the Partnership’s general partner and its affiliates are not voted in favor of such removal.

On February 6, 2008, the Partnership declared its fourth quarter 2007 cash distribution to its unitholders of record as of February 11, 2008. The distribution amount per common unit was $0.3925, or approximately $28.5 million. The distribution was paid on February 15, 2008.

On April 30, 2008, the Partnership declared a cash distribution of $0.40 per unit, or approximately $29.1 million, for the first quarter ended March 31, 2008. The distribution was paid May 15, 2008, for unitholders of record as of May 9, 2008.

On July 29, 2008, the Partnership declared a cash distribution of $0.41 per unit for the second quarter ended June 30, 2008. The distribution will be paid on August 14, 2008, for unitholders of record as of August 8, 2008.

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2008

NOTE 9. RELATED PARTY TRANSACTIONS

On July 1, 2006, the Partnership entered into a month-to-month contract for the sale of natural gas with an affiliate of NGP, under which the Partnership sells a portion of its gas supply. The Partnership recorded revenues of $8.3 million, $16.0 million, $8.2 million and $13.9 million for the three and six months ended June 30, 2008 and 2007, respectively, from the agreement, of which there was a receivable of $2.2 and $5.5 million outstanding at June 30, 2008 and December 31, 2007, respectively. The Partnership has received a letter of credit as a financial assurance of payment related to this agreement.

In addition, during the three and six months ended June 30, 2008 and June 30, 2007, the Partnership incurred $1.7 million, $3.0 million, $1.6 million and $2.9 million in expenses with related parties, of which there was an outstanding accounts payable balance of $0.6 million and $0.5 million as of June 30, 2008 and December 31, 2007, respectively.

Related to its investments in unconsolidated subsidiaries, during the three and six months ended June 30, 2008, the Partnership recorded income of $0.9 million and $2.4 million, respectively, of which there was no outstanding account receivable balance of as of June 30, 2008 and December 31, 2007, respectively.

As of June 30, 2008 and December 31, 2007, Eagle Rock Energy G&P, LLC had $21.1 million and $17.0 million, respectively, of outstanding checks paid on behalf of the Partnership. This amount was recorded as Due to Affiliate on the Partnership’s balance sheet in current liabilities. As the checks are drawn against Eagle Rock Energy G&P, LLC’s cash accounts, the Partnership reimburses Eagle Rock Energy G&P, LLC.

During the three months ended June 30, 2008, the Partnership incurred approximately $0.6 million for services performed by Stanolind Field Services (“SFS”), which are assets controlled by NGP and certain employees of the Partnership. As of June 30, 2008, the Partnership had a payable to SFS of $0.3 million.

NOTE 10. FAIR VALUE OF FINANCIAL INSTRUMENTS

Effective January 1, 2008, the Partnership 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). The Partnership utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk inherent in the inputs to the valuation technique. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy give the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurements). The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:

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

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

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2008

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 June 30, 2008, the Partnership has fair valued its interest rate swaps and commodity derivative instruments (see Note 11), which includes crude oil, natural gas and natural gas liquids (“NGLs”). The Partnership has classified the inputs to measure the fair value of its interest rate swap, crude oil derivatives and natural gas derivatives as Level 2. For its NGL derivatives, the Partnership has classified the inputs related to its NGL derivatives that mature in less than one year as Level 2, but it has classified the inputs for the NGL derivatives that mature beyond one year as Level 3 as the NGL market is considered to be less liquid beyond one year’s time. The following table discloses the fair value of the Partnership’s derivative instruments as of June 30, 2008:


	Level 1		Level 2		Level 3		Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	4,520	$	—	$	4,520
Natural gas derivatives		—		8		—		8
Total	$	—	$	4,528	$	—	$	4,528

Liabilities:
Crude oil derivatives	$	—	$	315,763	$	—	$	315,763
Natural gas derivatives		—		22,010		—		22,010
NGL derivatives		—		37,163		36,856		74,019
Interest rate derivatives		—		12,199		—		12,199
Total	$	—	$	387,135	$	36,856	$	423,991

As of June 30, 2008, risk management current assets in the Condensed Consolidated Balance Sheet include an investment premium of $4.5 million, net of amortization.

The following table sets forth a reconciliation of changes in the fair value of the Level 3 NGL derivatives during the three months ended June 30, 2008 (in thousands):

Net liability balances as of April 1, 2008	$	27,454
Transfers from Level 3 to Level 2		(4,873	)
Unrealized gains		14,275
Net liability balances as of June 30, 2008	$	36,856

The following table sets forth a reconciliation of changes in the fair value of the Level 3 NGL derivatives during the six months ended June 30, 2008 (in thousands):

Net liability balances as of January 1, 2008	$	36,695
Transfers from Level 3 to Level 2		(10,730	)
Unrealized gains		10,891
Net liability balances as of June 30, 2008	$	36,856

The Partnership values its Level 3 NGL derivatives using forward curves, volatility curves, volatility skew parameters, interest rate curves and model parameters.

Realized and unrealized losses related to the interest rate derivatives are recorded as part of interest expense, net in the Condensed Consolidated Statements of Operations. Realized and unrealized losses and premium amortization related to the Partnership’s commodity derivatives are recorded as a component of revenue in the Condensed Consolidated Statements of Operations.

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.

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2008

The carrying amount of cash equivalents is believed to approximate their fair values because of the short maturities of these instruments. As of June 30, 2008, the debt associated with the revolving credit agreement bore interest at floating rates. As such, carrying amounts of this debt instrument approximates fair value.

NOTE 11. RISK MANAGEMENT ACTIVITIES

Interest Rate Derivative Instruments—To mitigate its interest rate risk, the Partnership entered into various interest rate swaps. These swaps convert the variable-rate interest obligations into a fixed-rate interest obligation. The purpose of entering into this swap is to eliminate interest rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments through the end of 2010.

Commodity Derivative Instruments—The prices of crude oil, natural gas and NGLs are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors which are beyond the Partnership’s control. In order to manage the risks associated with the future prices of crude oil, natural gas and NGLs, the Partnership engages in risk management activities that take the form of commodity derivative instruments. Currently these activities are governed by the general partner, which today typically prohibits speculative transactions and limits the type, maturity and notional amounts of derivative transactions. The Partnership has implemented a risk management policy which will allow management to execute crude oil, natural gas and NGL hedging instruments in order to reduce exposure to substantial adverse changes in the prices of these commodities. The Partnership continually monitors and ensures compliance with this risk management policy through senior level executives in our operations, finance and legal departments. The Partnership has not entered into any new derivatives in the second quarter of 2008, other than assuming those derivatives in the Stanolind acquisition discussed below.

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

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

As a result of the Stanolind acquisition, the Partnership assumed the following derivative transactions (derivatives shown with a floor price only are puts; all other derivatives are costless collars):

				Price ($ per MMbtu or $ per Bbl)
Period	Commodity	Average Volumes per Month	Index	Average Floor	Average Ceiling
Jul-Dec 2008	Oil	10,000 Bbl	NYMEX WTI	60.00
Jul-Dec 2008	Oil	11,500 Bbl	NYMEX WTI	95.00	105.20
Jan-Dec 2009	Oil	10,000 Bbl	NYMEX WTI	93.00	100.85
Jan-Dec 2010	Oil	9,000 Bbl	NYMEX WTI	90.00	99.80
Jul-Sept 2008	Gas	20,000 MMbtu	WEST TEXAS (WAHA)	8.50	9.55
Oct-Dec 2008	Gas	20,000 MMbtu	WEST TEXAS (WAHA)	8.50	9.45
Jan-Mar 2009	Gas	20,000 MMbtu	WEST TEXAS (WAHA)	9.00	9.85
Apr-Jun 2009	Gas	20,000 MMbtu	WEST TEXAS (WAHA)	7.50	7.95
Jul-Sept 2009	Gas	20,000 MMbtu	WEST TEXAS (WAHA)	7.50	8.60
Oct-Dec 2009	Gas	20,000 MMbtu	WEST TEXAS (WAHA)	7.50	8.90

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2008

NOTE 12. COMMITMENTS AND CONTINGENCIES

Litigation—The Partnership is subject to several lawsuits which arise from time to time in the ordinary course of business. The Partnership has accruals of approximately $1.5 million and $1.5 million as of June 30, 2008 and December 31, 2007, respectively, related to these matters. The Partnership has been indemnified up to a certain dollar amount for certain of these lawsuits. For the indemnified lawsuits, the Partnership has not established any accruals as the likelihood of these suits being successful against them is considered remote. If there ultimately is a finding against the Partnership in the indemnified cases, the Partnership would expect to make a claim against the indemnification up to limits of the indemnification. These matters are not expected to have a material adverse effect on our financial position, results of operations or cash flows of the Partnership.

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

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

Environmental—The operation and ownership of (a) midstream assets such as pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products and (b) upstream assets such as operated and non-operated interests in oil and gas properties is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these assets, the Partnership must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of drilling oil and gas wells, planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership’s combined results of operations, financial position or cash flows. At June 30, 2008 and December 31, 2007, the Partnership had accrued, on an undiscounted basis, approximately $5.3 million and $2.4 million, respectively, for environmental matters.

TCEQ Matters—In late June 2008, the Texas Commission on Environmental Quality (“TCEQ”) issued a Notice of Enforcement (“NOE”) to a subsidiary of the Partnership, TCEQ ID No.: CF-0068-J (the “First NOE”) and an NOE to a subsidiary of the Partnership (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 during routine investigations of our Cargray facilities in the Texas Panhandle. In response, the Partnership took prompt corrective action with respect to all of the matters addressed in each NOE. The TCEQ has great discretion to assess administrative penalties, in a range of $0 to $10,000 per day, and the allegations underpinning each NOE involve a time period that runs over one year. The TCEQ has not yet made a final determination with respect to whether, in each case, it will assess an administrative penalty (or the amount of such penalty, if assessed).

Retained Revenue Interest—Certain assets of the Partnership’s Upstream Segment are subject to retained revenue interests. These interests were established under purchase and sale agreements that were executed by the Partnership’s predecessors in title. The terms of these agreements entitle the owners of the retained revenue interests to a portion of the revenues received from the sale of the hydrocarbons above specified base oil and natural

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2008

gas prices. These retained revenue interests do not represent a real property interest in the hydrocarbons. The Partnership’s reported revenues are reduced to account the retained revenue interests on a monthly basis.

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

Other Commitments—The Partnership utilizes assets under operating leases for its corporate office, certain rights-of way and facilities locations, vehicles and other equipment. Rental expense, including leases with no continuing commitment, amounted to approximately $1.2 million $2.5 million, $0.3 million and $0.5 million for the three and six months ended June 30, 2008 and June 30, 2007, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term.

NOTE 13. SEGMENTS

Based on the Partnership’s approach to managing its assets, the Partnership believes its operations consist of three geographic segments in its midstream business, one upstream segment, one mineral segment and one functional (corporate) segment:

(i)

Midstream—Texas Panhandle Segment:

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

(ii)

Midstream—South Texas Segment:

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

(iii)

Midstream—East Texas/Louisiana Segment: gathering, processing and marketing of natural gas and related NGL transportation in East Texas and Louisiana;

(iv)

Upstream Segment:

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

(v)

Minerals Segment:

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

(vi)

Corporate Segment:

risk management and other corporate activities.

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2008

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

Midstream Segments Three Months Ended June 30, 2008	Texas Panhandle Segment		South Texas Segment		East Texas / Louisiana Segment		Total Midstream Segments
($ in millions)
Sales to external customers	$	183.5	$	132.7	$	97.8	$	414.0
Cost of natural gas and natural gas liquids		140.3		129.5		83.8		353.6
Operating costs and other expenses		8.7		0.5		3.8		13.0
Depreciation, depletion, and amortization		10.9		0.9		3.0		14.8
Operating income	$	23.6	$	1.8	$	7.2	$	32.6
Capital Expenditures	$	6.5	$	0.2	$	4.0	$	10.7
Segment Assets	$	582.4	$	97.0	$	265.3	$	944.7

Three Months Ended June 30, 2008	Total Midstream Segments		Upstream Segment		Minerals Segment		Corporate Segment			Total Segments
($ in millions)
Sales to external customers	$	414.0	$	45.9	$	10.3	$	(284.0	)(a)	$	186.2
Cost of natural gas and natural gas liquids		353.6		—		—		—			353.6
Operating costs and other expenses		13.0		9.4		0.5		16.2			39.1
Depreciation, depletion, and amortization		14.8		10.0		1.5		0.2			26.5
Operating income (loss)	$	32.6	$	26.5	$	8.3	$	(300.4	)	$	(233.0	)
Capital Expenditures	$	10.7	$	10.3	$	—	$	0.1		$	21.1
Segment Assets	$	944.7	$	588.8	$	148.2	$	83.3		$	1,765.0

Midstream Segments Three Months Ended June 30, 2007	Texas Panhandle Segment		South Texas Segment		East Texas / Louisiana Segment		Total Midstream Segments
($ in millions)
Sales to external customers	$	110.1	$	50.8	$	37.6	$	198.5
Cost of natural gas and natural gas liquids		86.1		49.2		29.1		164.4
Operating costs and other expenses		8.7		0.2		2.9		11.8
Depreciation, depletion, and amortization		10.0		0.4		2.0		12.4
Operating income	$	5.3	$	1.0	$	3.6	$	9.9
Capital Expenditures	$	12.1	$	0.8	$	3.6	$	16.5
Segment Assets	$	581.8	$	75.5	$	277.7	$	935.0

Three Months Ended June 30, 2007	Total Midstream Segments		Upstream Segment		Minerals Segment		Corporate Segment			Total Segments
($ in millions)
Sales to external customers	$	198.5	$	—	$	3.2	$	(27.3	)(a)	$	174.4
Cost of natural gas and natural gas liquids		164.4		—		—		—			164.4
Operating costs and other expenses		11.8		—		.3		5.2			17.3
Depreciation, depletion, and amortization		12.4		—		1.5		0.2			14.1
Operating income (loss)	$	9.9	$	—	$	1.4	$	(32.7	)	$	(21.4	)
Capital Expenditures	$	16.5	$	—	$	—	$	0.1		$	16.6
Segment Assets	$	935.0	$	—	$	162.2	$	44.7		$	1,141.9

________________________________________

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

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2008

Midstream Segments Six Months Ended June 30, 2008	Texas Panhandle Segment		South Texas Segment		East Texas / Louisiana Segment		Total Midstream Segments
($ in millions)
Sales to external customers	$	339.8	$	231.1	$	168.3	$	739.2
Cost of natural gas and natural gas liquids		260.4		225.1		143.9		629.4
Operating costs and other expenses		16.5		1.2		7.3		25.0
Depreciation, depletion, and amortization		21.6		1.9		5.9		29.4
Operating income	$	41.3	$	2.9	$	11.2	$	55.4
Capital Expenditures	$	13.4	$	0.6	$	6.1	$	20.1
Segment Assets	$	582.4	$	97.0	$	265.3	$	944.7

Six Months Ended June 30, 2008	Total Midstream Segments		Upstream Segment		Minerals Segment		Corporate Segment			Total Segments
($ in millions)
Sales to external customers	$	739.1	$	85.0	$	17.2	$	(329.6	)(a)	$	511.8
Cost of natural gas and natural gas liquids		629.4		—		—		—			629.4
Operating costs and other expenses		25.0		17.0		0.9		27.5			70.4
Depreciation, depletion, and amortization		29.4		18.3		4.1		0.4			52.2
Operating income (loss)	$	55.4	$	49.7	$	12.2	$	(357.5	)	$	(240.2	)
Capital Expenditures	$	20.1	$	13.2	$	—	$	0.2		$	33.5
Segment Assets	$	944.7	$	588.8	$	148.2	$	83.3		$	1,765.0

Midstream Segments Six Months Ended June 30, 2007	Texas Panhandle Segment		South Texas Segment		East Texas / Louisiana Segment		Total Midstream Segments
($ in millions)
Sales to external customers	$	205.0	$	50.8	$	57.1	$	312.9
Cost of natural gas and natural gas liquids		161.7		49.2		44.1		255.0
Operating costs and other expenses		16.0		0.2		4.2		20.4
Depreciation, depletion, and amortization		19.8		0.4		3.7		23.9
Operating income	$	7.5	$	1.0	$	5.1	$	13.6
Capital Expenditures	$	22.5	$	0.8	$	15.9	$	39.2
Segment Assets	$	581.8	$	75.5	$	277.7	$	935.0

Six Months Ended June 30, 2007	Total Midstream Segments		Upstream Segment		Minerals Segment		Corporate Segment			Total Segments
($ in millions)
Sales to external customers	$	312.9	$	—	$	3.2	$	(34.9	)(a)	$	281.2
Cost of natural gas and natural gas liquids		255.0		—		—		—			255.0
Operating costs and other expenses		20.4		—		0.3		11.2			31.9
Depreciation, depletion, and amortization		23.9		—		1.5		0.3			25.7
Operating income (loss)	$	13.6	$	—	$	1.4	$	(46.4	)	$	(31.4	)
Capital Expenditures	$	39.2	$	—	$	—	$	0.3		$	39.5
Segment Assets	$	935.0	$	—	$	162.2	$	44.7		$	1,141.9

_______________________________________

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

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2008

NOTE 14. INCOME TAXES

Provision for Income Taxes – The Partnership’s provision for income taxes relates to (i) state taxes for the Partnership and (ii) federal taxes for Eagle Rock Energy Acquisition Co., Inc. (successor entity to certain entities acquired in the Redman acquisition) and Eagle Rock Energy Acquisition II, Inc. (successor entity to entities related to the Stanolind acquisition) and their wholly-owned corporations, Eagle Rock Upstream Development Company, Inc and Eagle Rock Upstream Development Company II, Inc., which are subject to federal income taxes (the “C Corporations.

As a result of the taxable income from the underlying partnerships owned by the C Corporations described above, net operating losses of $0.3 million and $0.4 million were used during the three and six months ended June 30, 2008, respectively, which resulted in a partial release of the valuation allowances established for net operating losses at December 31, 2007.

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

Deferred taxes - As of June 30, 2008, the net deferred tax liability was $43.6 million compared to $17.5 million as of December 31, 2007 and is primarily attributable to book and tax basis differences of the entities subject to federal income taxes discussed above. The increase during 2008 is mainly due to deferred tax liabilities related to federal income taxes of Eagle Rock Energy Acquisition Co. II, Inc. and Eagle Rock Upstream Development II, Inc. our wholly-owned corporations which are subject to federal income taxes. Eagle Rock Upstream Development II, Inc. was formerly known as Stanolind Oil and Gas Corp. and was acquired in the form of a corporation as part of the Stanolind acquisition during the second quarter of 2008. Temporary differences were created by the Stanolind acquisition. These temporary differences result in a net deferred tax liability which will be reduced as allocation of depreciation and depletion in proportion to the assets contributed brings the book and tax basis closer together over time. This deferred tax liability was recognized in conjunction with the purchase accounting for the Stanolind acquisition.

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

Texas Franchise Tax - On May 18, 2006, the State of Texas enacted revisions to 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 corporations. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits.

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

NOTE 15. EQUITY-BASED COMPENSATION

The general partner of the general partner for Eagle Rock Energy Partners, L.P., approved a long-term incentive plan (“LTIP”), as amended, for its employees, directors and consultants who provide services to the Partnership covering an aggregate of 2,000,000 common units to be granted either as options, restricted units or phantom units. During the restriction period, distributions associated with the granted awards will be distributed to the awardees. No options or phantom units have been issued to date.

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2008

A summary of the restricted common units’ activity for the six months ended June 30, 2008, is provided below:

	Number of Restricted Units			Weighted Average Fair Value per Unit
Outstanding at December 31, 2007		467,062		$	23.01
Granted		471,250		$	16.79
Vested		(124,384	)	$	23.27
Forfeitures		(25,981	)	$	21.95
Outstanding at June 30, 2008		787,947		$	19.29

The total grant date fair value of restricted units that vested during the six months ended June 30, 2008 was $2.9 million.

For the three and six months ended June 30, 2008 and June 30, 2007, non-cash compensation expense of approximately $1.6 million, $2.7 million, $0.2 million and $0.6 million respectively, was recorded related to the granted restricted units.

As of June 30, 2008, unrecognized compensation costs related to the outstanding restricted units under our LTIP totaled approximately $14.5 million. The remaining expense is to be recognized over a weighted average of 2.3 years.

NOTE 16. EARNINGS PER UNIT

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

The Partnership issued restricted common units at multiple times in its history, including a number of awards made at the time of the initial public offering, October 24, 2006. These units vest ratably over the course of approximately three years and the units, once vested, are treated as common units for all purposes. The unvested units (at all periods while unvested) have been considered in the diluted common unit weighted average number in periods of net income, but have been excluded in periods of net losses.

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2008

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
	(in thousands, except for per unit amounts)

Net loss	$	(227,020	)	$	(23,783	)	$	(255,348	)	$	(43,451	)

Net loss allocated to:
Common units	$	(159,343	)	$	(8,580	)	$	(179,172	)	$	(14,249	)
Subordinated units	$	(65,023	)	$	(14,607	)	$	(73,189	)	$	(28,057	)
General partner units	$	(2,654	)	$	(596	)	$	(2,987	)	$	(1,145	)

Weighted average unit outstanding during period:
Common units		50,762			30,613			50,731			25,680
Subordinated units		20,691			20,691			20,691			20,691
General partner units		845			845			845			845
Basic and Diluted Earnings Per Unit:
Common units	$	(3.14	)	$	(0.28	)	$	(3.54	)	$	(0.55	)
Subordinated units	$	(3.14	)	$	(0.71	)	$	(3.54	)	$	(1.36	)
General partner units	$	(3.14	)	$	(0.71	)	$	(3.54	)	$	(1.36	)

NOTE 17. OTHER OPERATING EXPENSE

In July 2008, SemGroup, L.P. and certain of its subsidiaries (“SemGroup”) filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. The Partnership has historically sold portions of its condensate production from its Texas Panhandle and East Texas midstream systems to SemGroup. As a result of the bankruptcy, the Partnership is taking a $6.2 million bad debt charge in the second quarter of 2008, which is included in “Other Operating Expense” in the consolidated statement of operations. During July 2008, the Partnership sold additional condensate to SemGroup in the range of approximately $5.0 million to $6.0 million, which it expects to take as a bad debt charge during the three months ended September 30, 2008. The Partnership stopped all sales to SemGroup as of August 1, 2008. Other operating expenses for the six months ended June 30, 2007 consisted of an arbitration settlement of $1.4 million and a severance payout to a former executive of $0.3 million.

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

The following management discussion and analysis of financial condition and results of operations should be read in conjunction with our unaudited condensed consolidated financial statements, and the notes thereto, appearing elsewhere in this report, as well as the Consolidated Financial Statements, Risk Factors and Management’s Discussion and Analysis of Financial Condition and Results of Operations presented in our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the Securities and Exchange Commission. For a description of oil and natural gas terms, see such Annual Report.

Overview

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

•

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

•

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

•

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

We report on our businesses in six accounting segments (see Note 13).

We conduct, evaluate and report on our Midstream Business within three distinct segments—the Texas Panhandle Segment, the East Texas/Louisiana Segment (previously known prior to the filing of our Annual Report as our Southeast Texas and North Louisiana Segment), and South Texas Segment. Our Texas Panhandle Segment consists of gathering and processing assets in the Texas Panhandle. Our East Texas/Louisiana Segment consists of gathering and processing assets in East Texas/Louisiana. Our South Texas Segment consists of gathering systems and related compression and processing facilities in South Texas.

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

We conduct, evaluate and report on our Minerals Business as one segment. Our Minerals Segment consists of certain fee minerals, royalties and overriding royalties located in multiple producing trends across the United States.

The final segment that we report is our Corporate Segment, in which we account for our commodity hedging activity and our general corporate costs.

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

Acquisitions

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

Stanolind Acquisition - On April 30, 2008, we completed the acquisition of all of the outstanding capital stock of Stanolind Oil and Gas Corp. (“Stanolind”), for an aggregate purchase price of $81.8 million, subject to working capital and other purchase price adjustments (the “Acquisition”). We funded the transaction from existing cash from operations, as well as with borrowings under our existing secured revolving credit facility. Stanolind operates crude oil and natural gas producing properties in the Permian Basin of West Texas, primarily in Ward, Crane and Pecos Counties.

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

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

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

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

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

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

Prior to the above 2007 acquisitions the Partnership was solely a midstream company. The Montierra and MacLondon acquisitions provided the Partnership’s entry into the minerals business and the EAC and Redman acquisitions provided the Partnership’s entry into the upstream business.

Presentation of Financial Information

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

How We Evaluate Our Operations

Our management uses a variety of financial and operational measurements to analyze our performance. We view these measurements as important factors affecting our profitability and review these measurements on a monthly basis for consistency and trend analysis. These measures include volumes, margin, operating expenses and Adjusted EBITDA (more fully described later under “Non-GAAP Financial Measures”) on a company-wide basis.

General Trends and Outlook

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

Cautionary Note Regarding Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, include certain “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “continue,” “estimate,” “forecast,” “may,” “will,” or similar expressions help identify forward-looking statements. Although we believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that these objectives will be reached. Actual results may differ materially from any results projected, forecasted, estimated or expressed in forward-looking statements because many of the factors which determine these results are subject to uncertainties and risks, difficult to predict, and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the Securities and Exchange Commission on April 1, 2008.

Summary of Consolidated Operating Results

Below is a summary table of our consolidated operating results for the three and six months ended June 30, 2008 and June 30, 2007, respectively. Operating results for our individual operating segments are presented in tables in this Item 2.

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
	($ in thousands)
Revenue:
Sales of natural gas, NGLs, oil, condensate and sulfur	$	451,769		$	191,621		$	808,788		$	301,742
Gathering and treating services		8,085			6,883			15,228			11,166
Minerals and royalty income		10,255			3,192			17,213			3,192
Realized commodity derivative gains (losses)		(27,708	)		1,502			(40,283	)		4,501
Unrealized commodity derivative losses ...		(256,265	)		(28,757	)		(289,337	)		(39,398	)
Other		122			—			182			—
Total revenue		186,258			174,441			511,791			281,203
Cost of natural gas and natural gas liquids		353,558			164,364			629,389			255,000
Expenses:
Operating and maintenance		17,731			11,396			33,297			19,320
Taxes other than income		5,263			728			9,610			1,430
General and administrative		10,026			5,171			21,268			9,391
Other operating expense		6,214			—			6,214			1,711
Depreciation, depletion, and amortization		26,457			14,149			52,202			25,779
Total costs and expenses		419,249			195,808			751,980			312,631
Operating loss		(232,991	)		(21,367	)		(240,189	)		(31,428	)
Other income (expense):
Interest income		160			176			461			300
Other income		886			91			2,433			91
Interest expense, net		(6,974	)		(8,519	)		(16,078	)		(16,399	)
Unrealized interest rate derivatives gains		13,689			6,485			29			4,874
Realized interest rate derivative gains (losses)...		(2,444	)		318			(2,545	)		534
Other expense		(232	)		(711	)		(447	)		(1,003	)
Total other income (expense)		5,085			(2,160	)		(16,147	)		(11,603	)
Loss before taxes		(227,906	)		(23,527	)		(256,336	)		(43,031	)
Income tax (benefit) provision		(886	)		256			(988	)		420
Net loss	$	(227,020	)	$	(23,783	)	$	(255,348	)	$	(43,451	)
Adjusted EBITDA(a)	$	57,504		$	22,159		$	110,282		$	36,252

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

For the three months ended June 30, 2008, based on operating income of our non-Corporate segments, our midstream business comprised approximately 48.3% of our business (with the Texas Panhandle Segment accounting for 35.0% of our business, the South Texas Segment accounting for 2.7% of our business, and the East Texas/Louisiana Segment accounting for 10.6% of our business), our upstream business comprised approximately 39.5% of our business, and our minerals business comprised approximately 12.2% of our business. For the six months ended June 30, 2008, based on operating income of our non-Corporate segments, our midstream business comprised approximately 47.3% of our business (with the Texas Panhandle Segment accounting for 35.3% of our business, the South Texas Segment accounting for 2.5% of our business, and the East Texas/Louisiana Segment accounting for 9.5% of our business), our upstream business comprised approximately 42.3% of our business, and our minerals business comprised approximately 10.4% of our business. We intend to acquire and construct additional assets in both our midstream and upstream businesses, and we intend to continue to seek attractive acquisitions for our minerals business.

Midstream Business (Three Segments)

Texas Panhandle Segment

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
	($ in thousands, except for price data)
Revenue:
Sales of natural gas, NGLs, oil and condensate	$	180,987		$	107,884		$	334,842		$	200,664
Gathering and treating services		2,524			2,206			4,993			4,342
Total revenue		183,511			110,090			339,835			205,006
Cost of natural gas and natural gas liquids		140,282			86,057			260,400			161,704
Operating costs and expenses:
Operating		8,715			8,661			16,463			16,005
Depreciation and amortization		10,894			9,983			21,603			19,765
Total operating costs and expenses		19,609			18,644			38,066			35,770
Operating income	$	23,620		$	5,389		$	41,369		$	7,532
Capital Expenditures	$	6,469		$	12,155		$	13,455		$	22,473

Realized average prices:
Oil and condensate (per Bbl)	$	117.93		$	54.43		$	104.15		$	50.27
Natural gas (per Mcf)	$	9.44		$	6.64		$	8.42		$	6.39
NGLs (per Bbl)	$	74.76		$	49.98		$	68.46		$	39.06

Production volumes:
Gathering volumes (Mcf/d)(a)		149,881			138,032			152,225			138,544
NGLs and condensate (net equity gallons)		19,650,791			21,641,964			41,535,043			41,634,155
Natural gas short position (MMbtu/d)(a)		(4,974	)		(9,320	)		(6,112	)		(7,919	)

__________________

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

Revenue and Cost of Natural Gas and Natural Gas Liquids. For the three and six months ended June 30, 2008, the revenues minus cost of natural gas and natural gas liquids for our Texas Panhandle Segment operations totaled $43.2 million and $79.4 million compared to $24.0 and $43.3 million for the three and six months ended June 30, 2007. There were two primary contributors to this increase: (i) higher NGL and condensate pricing, as compared to pricing in 2007, and (ii) higher natural gas liquids production as compared to production in 2007.

The higher 2008 gathering volumes compared to 2007 was primarily due to the colder than normal weather in that area and the downtime to repair the Arrington plant which reduced production during the three and six months ended June 30, 2007 and the start-up of the Red Deer Plant in June 2007, which benefited the gathering volumes during the three and six months ended June 30, 2008 compared to the same periods in 2007.

The drilling activity in the West Panhandle System is not sufficient to offset the natural declines experienced on the System. While our contract mix in the West Panhandle System provides us with a higher equity share of the production, the overall decline will continue and we expect to recover smaller amounts of equity production in the future on the West Panhandle System. The East Panhandle System continues to experience strong growth in volumes and equity production due to the active Granite Wash drilling play located in Roberts and Hemphill Counties, Texas. The liquids content of the natural gas is lower in the East Texas Panhandle System and our contract mix provides us with a smaller share of equity production as compared to the West Panhandle System. Due to this difference in contract mix and liquid content between our West and East Panhandle Systems, while we have grown aggregate volumes during the three and six months ended June 30, 2008 as compared to the three and six months

ended June 30, 2007, our equity share of liquids production would have been less through the six months ended June 30, 2008 if 2007 had been a normal winter. Our current goal is to grow volumes aggressively in the East Panhandle System to offset the decline in volumes and our share of equity production in the West Panhandle System. The start-up of the Red Deer Plant in June 2007 provided an additional 20 MMcf/d of processing capacity in our East Panhandle System that was immediately utilized by our customers. We expanded our Red Deer facility during the six months ended June 30, 2008 to handle additional volumes of 3 MMcf/d, bringing total capacity to 23 MMcf/d.

Operating Expenses. Operating expenses, including taxes other than income, for three and six months ended June 30, 2008 were $8.7 million and $16.5 million compared to $8.7 million and $16.0 million for the three and six months ended June 30, 2007. The three and six months ended June 30, 2007 included additional maintenance costs for repairing the Arrington plant. The major items impacting the $0.5 million increase in operating expense for the six months ended June 30, 2008 were a combination of the operations of the Red Deer Plant, which was brought on line in June 2007, and higher materials, supplies and labor costs.

Depreciation and Amortization. Depreciation and amortization expenses for three and six months ended June 30, 2008 were $10.9 million and $21.6 million compared to $10.0 million and $19.8 million for the three and six months ended June 30, 2007. The major items impacting the $0.9 million and $1.8 million increases was placing the Red Deer Plant into service and beginning the depreciation expense associated with the capital expenditure.

Capital Expenditures. Capital expenditures for the three and six months ended June 30, 2008 were $6.5 million and $13.5 million as compared to $12.2 million and $22.5 million for the three and six months ended June 30, 2007. During the six months ended June 30, 2008, of our capital spending in this segment, we spent $10.6 million on growth capital and $2.9 million on maintenance capital. We classify capital expenditures as either maintenance capital which represents routine well connects and capitalized maintenance activities or as growth capital which represents organic growth projects. Our decrease in capital spending for the three and six month periods of 2008 of $5.7 million and $9.0 million was driven by less growth capital due to expenditures in 2007 on the new Red Deer Plant, which was off set by capital expenditures related to our Stinnett – Cargray plant consolidation projects during 2008, which were completed in July 2008.

East Texas/Louisiana Segment

	Three Months Ended June 30,				Six Months Ended June 30,
	2008		2007(b)		2008		2007(b)
	($ in thousands, except for price data)
Revenue:
Sales of natural gas, NGLs, oil and condensate	$	93,176	$	33,853	$	160,135	$	51,194
Gathering and treating services		4,700		3,785		8,148		5,932
Total revenue		97,876		37,638		168,283		57,126
Cost of natural gas and natural gas liquids		83,911		29,105		143,930		44,094
Operating costs and expenses:
Operating		3,837		2,877		7,317		4,159
Depreciation and amortization		2,988		2,056		5,857		3,731
Total operating costs and expenses		6,825		4,933		13,174		7,890
Operating income	$	7,140	$	3,600	$	11,179	$	5,142
Capital Expenditures	$	4,044	$	3,576	$	6,095	$	15,893

Realized average prices:
Oil and condensate (per Bbl)	$	116.33	$	72.82	$	111.37	$	62.04
Natural gas (per Mcf)	$	12.32	$	7.24	$	10.67	$	7.04
NGLs (per Bbl)	$	58.80	$	40.57	$	55.86	$	39.48

Production volumes:
Gathering volumes (Mcf/d) (a)		179,744		131,535		171,824		111,519
NGLs and condensate (net equity gallons)		6,624,451		4,823,502		11,928,049		7,930,684
Natural gas short position (MMbtu/d) (a)		1,543		668		958		1,664

_____________

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

(b) Includes operations related to the Laser Acquisition starting on May 3, 2007.

Revenue and Cost of Natural Gas and Natural Gas Liquids. For the three and six months ended June 30, 2008, revenues minus cost of natural gas and natural gas liquids for our East Texas/Louisiana Segment totaled $14.0 million and $24.4 million, respectively, compared to $8.5 million and $13.0 million ,respectively, for the three and six months ended June 30, 2007.

We were positively impacted from higher NGL and condensate pricing during the six months ended June 30, 2008 as compared to the six months ended June 30, 2007. We were also positively impacted by a 37% and 54% growth in daily gathering volumes during the three and six months ended June 30, 2008, respectively, compared to comparable periods in 2007. Increased volumes were due to both a full six months of the Laser Acquisition during 2008 compared to only a two-month period in 2007 and continued successful drilling in the Austin Chalk play in Tyler and Jasper Counties, Texas. Excluding the Laser Acquisition, our gathering volumes increased by 29%. The Tyler County Pipeline Extension completed in March 2007, connected the Tyler County Pipeline to our Brookeland gathering system providing an additional 50 MMcf/d of outlet capacity for the Tyler County Pipeline. The production rates of wells drilled in the Austin Chalk play are characterized by high initial decline rates; therefore, operators must conduct active drilling programs if they are to maintain or grow their production in this play. We have also constructed a new seven mile lateral from our Brookeland gathering system into an active Austin Chalk drilling area where we have a large dedicated acreage position under a life-of-lease contract with an active significant producer. Depending upon the continued success of the producer’s drilling activities on this acreage; this area may continue to provide added volume growth to the segment during 2008.

The Laser Acquisition positively impacted the East Texas/Louisiana Segment by $4.2 million and $7.5 million during the three and six months ended June 30, 2008, respectively, compared to $3.3 million during the same time periods in the prior year. The Laser Acquisition’s daily gathering volumes for the three months ended June 30, 2008 compared to the two months ended June 30, 2007, the time period covering ownership of the Laser Acquisition, are down 9% due to reduced drilling activity around the Belle Bower system.

Operating Expenses. Operating expenses for the three and six months ended June 30, 2008 were $3.8 million and $7.3 million, respectively, compared to $2.9 million and $4.2 million for the three and six months ended June 30, 2007, respectively. The major items impacting the $0.9 million and $3.1 million increases in operating expense for the three and six months ended June 30, 2008 were (i) the additional one and four months that we have owned the assets in 2008 that were a part of the Laser Acquisition compared to the same time period in the prior year and (ii) incremental expenses for of additional compression costs due to increased gathered volumes on the Tyler County Pipeline and (iii) higher materials, supplies and labor costs.

Depreciation and Amortization. Depreciation and amortization expenses for the three and six months ended June 30, 2008 were $3.0 million and $5.9 million compared to $2.1 million and $3.7 million, respectively, for the three and six months ended June 30, 2007. The major items impacting the increases were (i) the inclusion of one and four months of additional depreciation and amortization during the three and six months ended June 30, 2008, as compared to the same period in 2007 due to the Laser acquisition occurring in May 2007, (ii) a full year and placing the Tyler County Pipeline Extension into service and beginning the depreciation expense associated with the capital expenditure.

Capital Expenditures. Capital expenditures for the three and six months ended June 30, 2008 were $4.0 million and $6.1 million, respectively, compared to $3.6 million and $15.9 million, respectively, for the three and six months ended June 30, 2007. During the six months ended June 30, 2008 we spent $4.4 million on growth capital of our capital spending in this segment and $1.7 million on maintenance capital. We classify capital expenditures as either maintenance capital which represents routine well connects and capitalized maintenance activities or as growth capital which represents organic growth projects. Our increase in capital spending for the three month period of $0.4 was due to expansion of the Indian Springs Plant and construction of gathering lines to the significant producer discussed above, while the decrease in the six month period of $9.8 million was due primarily to the construction and start-up of the Tyler County Pipeline Extension in March 2007.

South Texas Segment

	Three Months Ended June 30,				Six Months Ended June 30,
	2008		2007(b)		2008		2007(b)
	($ in thousands, except for price data)
Revenue:
Sales of natural gas, NGLs, oil and condensate	$	131,794	$	49,884	$	229,033	$	49,884
Gathering and treating services		861		892		2,087		892
Other		—		—		2		—
Total revenue		132,655		50,776		231,122		50,776
Cost of natural gas and natural gas liquids		129,365		49,202		225,059		49,202
Operating costs and expenses:
Operating		574		294		1,227		294
Depreciation and amortization		934		379		1,873		379
Total operating costs and expenses		1,508		673		3,100		673
Operating income	$	1,782	$	901	$	2,963	$	901
Capital Expenditures	$	218	$	829	$	579	$	829

Realized average prices:
Oil and condensate (per Bbl)	$	123.16	$	62.17	$	105.12	$	62.17
Natural gas (per Mcf)	$	10.88	$	6.62	$	9.67	$	6.62
NGLs (per Bbl)	$	72.66	$	63.42	$	73.08	$	63.42

Production volumes:
Gathering volumes (Mcf/d) (a)		84,514		67,574		81,312		33,787
NGLs and condensate (net equity gallons)		377,706		155,904		827,568		155,904
Natural gas short position (MMbtu/d) (a)		500		333		500		167

___________

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

(b) Includes operations related to the Laser Acquisition starting on May 3, 2007.

Revenue and Cost of Natural Gas and Natural Gas Liquids. This segment was a new area of operations for us as we entered this segment as a result of the Laser Acquisition, effective May 2007. During the three and six months ended June 30, 2008 the South Texas Segment contributed revenues minus cost of natural gas and natural gas liquids of $3.3 million and $6.1 million, respectively, as compared to $1.6 million for the three and six months ended June 30, 2007. The increase in revenues during the three and six months ended June 30, 2008 compared to the comparable periods in 2007 was due to increases in volumes on account of inclusion of the Laser Acquisition during the full six month period in 2008 as compared to only a two month period ending June 30, 2007. The Laser Acquisition daily gathering volumes for the three months ended June 30, 2008 compared to the two months ended June 30, 2007, the time period covering ownership of the Laser Acquisition, are down approximately 17% due to reduced volumes on the Raymondville and McAllen systems.

There are two primary activities in this segment: (i) volumes of natural gas gathered on our own assets, which represents approximately 86% of revenues minus cost of natural gas and natural gas liquids for this segment and (ii) producer services, providing marketing and pipeline connection services to small independent producers and to third party pipeline systems, which accounted for approximately 14% of revenues minus cost of natural gas and natural gas liquids.

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

Operating Expenses. Operating expenses for the three and six months ended June 30, 2008 were $0.6 million and $1.2 million, respectively, as compared to $0.3 million for the three and six months ended June 30, 2007.

Depreciation and Amortization. Depreciation and amortization expenses for the three and six months ended June 30, 2008 were $0.9 million and $1.9 million, respectively, as compared to $0.4 million for the three and six months ended June 30, 2007.

Capital Expenditures. Capital expenditures for the three and six months ended June 30, 2008 were $0.2 million and $0.6 million, respectively, as compared to $0.8 million for the three and six months ended June 30, 2007. During the six months ended June 30, 2008, of our capital spending in this segment, we spent $0.5 million on growth capital and $0.1 million on maintenance capital.

Upstream Segment

The Upstream segment became a new line of business for the Partnership in 2007. The initial assets were acquired on July 31, 2007.

	Three Months Ended June 30,				Six Months Ended June 30,
	2008(a)		2007		2008(a)		2007
	($ in thousands, except for price data)
Revenue:
Oil and condensate	$	21,126	$	—	$	39,459	$	—
Natural gas		9,431		—		16,557		—
NGLs		8,155		—		16,295		—
Sulfur		7,100		—		12,467		—
Other		122		—		180		—
Total revenue		45,934				84,958
Operating costs and expenses:
Operating		9,386		—		16,975		—
Depletion, depreciation and amortization		9,914		—		18,339		—
Total operating costs and expenses		19,300		—		35,314		—
Operating income	$	26,634	$	—	$	49,644	$	—
Capital Expenditures	$	10,261	$	—	$	13,184	$	—

Realized average prices:
Oil and condensate (per Bbl)	$	114.50	$	—	$	102.25	$	—
Natural gas (per Mcf)	$	10.80	$	—	$	9.65	$	—
NGLs (per Bbl)	$	68.74	$	—	$	66.21	$	—
Sulfur (per Long ton)	$	359.97	$	—	$	271.28	$	—

Production volumes:
Oil and condensate ( Bbl)		184,511		—		385,916		—
Natural gas (Mcf)		873,093		—		1,715,290		—
NGLs (Bbl)		118,644		—		246,097		—
Total (Mcfe)		2,692,023		—		5,507,368		—
Sulfur (Long ton)		19,724		—		45,956		—

__________

(a) Includes operations from the EAC Acquisition and Redman Acquisition beginning on August 1, 2007 and from the Stanolind Acquisition starting on May 1, 2008.

Revenue. For the three and six months ended June 30, 2008, the Upstream Segment contributed $45.9 million and $85.0 million of revenue, respectively, which includes two months of operations related to the assets acquirin the Stanolind acquisition.

Production was negatively impacted by curtailed or shut-in production at Big Escambia Creek (“BEC”), Flomaton and Fanny Church fields during a portion of both the three month and six months periods ended June 30, 2008. In April 2008, the BEC treating facility was shut-in for 20 days for a planned turnaround, which shut-in all the production in the BEC field. In addition, production was partially curtailed for 18 days during the months of May and June 2008 to repair damage caused by a lightning strike at the BEC treating facility. During this repair period, oil and sulfur sales continued, but at a restricted rates.

Gas production from Flomaton and Fanny Church fields was restricted from sales for 25 days during the six months ended June 30, 2008 associated with a third party’s gas quality issue at the point of sales. Oil sales from both Flomaton and Fanny Church fields continued during this period of curtailment.

During the first quarter of 2008, the BEC field’s production was partially curtailed for 31 days due to sulfur recovery limitations ahead of the planned turnaround that occurred at the Big Escambia Creek treating facility during the month of April 2008.

In addition, historically, sulfur was viewed as a low value by-product in the production of oil and gas. Currently, primarily due to an increase in demand in the global fertilizer market, the price per long ton is over $600 at the Tampa, Florida market (before effects of net-backs); as compared to $40 per long ton at the Tampa, Florida market as recently as the summer of 2007. We believe that if our wells and facilities and certain third-party facilities are at full production we are capable of producing 8,000 to 10,000 long tons per month, net to us. There is no guarantee that these high prices will remain in effect for the future. As of June 30, 2008, our sulfur product is not hedged and we have attempted to identify and negotiate a long term contract to lock in some of the price upside, but we have been unable to find a suitable counterparty to this exposure.

Operating Expenses. Operating expenses, including severance and ad valorem taxes, totaled $9.4 million and $17.0 million for the Upstream Segment during the three and six months ended June 30, 2008, respectively. These operating expenses include two months of expenses related to the assets acquired in the Stanolind acquisition. Excluding severance and ad valorem taxes, the most significant portion of operating expenses were associated with operating the BEC and Flomaton treating and processing facilities. In April 2008, we incurred additional operating expenses related to the planned turnaround at the BEC treating facility. These facilities are required to extract the hydrogen sulfide and carbon dioxide to achieve pipeline sales quality specifications, as well as beneficially extracting natural gas liquids and sulfur for sale. The remaining operating expenses are attributed to base lease operating expenses and well workovers.

Depletion, Depreciation and Amortization. Depletion, depreciation and amortization expense for the three and six months ended June 30, 2008 was $9.9 million and $18.3 million, respectively.

Capital Expenditures. The Upstream Segment’s maintenance capital expenditures for the three and six months ended June 30, 2008 total $8.3 million and $11.2 million, respectively. Growth capital expenditures during the three and six months ended June 30, 2008 totaled $1.9 million (for both periods) and were associated with drilling projects acquired in the Stanolind acquisition. The maintenance capital expenditures during the three and six months ended June 30, 2008 were associated with the planned turnaround at the BEC treating facility and increasing drilling, recompletions and workover activities. In addition, certain capital facility projects were conducted in each of the new asset areas.

Minerals Segment

The Minerals Segment became a new line of business for the Partnership during 2007. The first assets were acquired in April 2007.

	Three Months Ended June 30,				Six Months Ended June 30,
	2008		2007(a)		2008		2007(a)
	($ in thousands, except for price data)
Revenue:
Oil and condensate	$	4,732	$	1,533	$	8,099	$	1,533
Natural gas		3,565		1,490		5,774		1,490
NGLs		411		98		646		98
Lease bonus, rentals and other		1,547		71		2,694		71
Total revenue		10,255		3,192		17,213		3,192
Operating costs and expenses:
Operating		482		292		925		292
Depletion		1,528		1,532		4,139		1,532
Total operating costs and expenses		2,010		1,824		5,064		1,824
Operating income	$	8,245	$	1,368	$	12,149	$	1,368

Realized average prices:
Oil and condensate (per Bbl)	$	115.68	$	62.80	$	102.86	$	62.80
Natural gas (per Mcf)	$	10.50	$	8.65	$	8.81	$	8.65
NGLs (per Bbl)	$	66.13	$	33.85	$	62.12	$	33.85

Production volumes:
Oil and condensate ( Bbl)		40,907		24,412		78,740		24,412
Natural gas (Mcf)		339,518		172,212		655,474		172,212
NGLs (Bbl)		6,215		2,895		10,400		2,895
Total (Mcfe)		622,250		336,054		1,129,400		336,054

__________

(a) Includes operations from the Montierra Acquisition as of May 1, 2007 and from the MacLondon Acquisition as of July 1, 2007.

Revenue. For the three and six months ended June 30, 2008 our revenue was $10.3 million and $17.2 million, respectively, as compared to $3.2 million for the three and six months ended June 30, 2007. The increase in revenue was due to increases in commodity prices and increases in production rates during the three and six months ended June 30, 2008, which was the result of drilling, recompletion and workover operations conducted by the various operators of the properties.

Additionally, we received approximately $1.5 million and $2.7 million in bonus and delay rental payments during the three and six months ended June 30, 2008, respectively. Substantially all of this was derived from our ownership in the minerals. The amount of revenue we receive from bonus and rental payments varies significantly from month to month; therefore, we do not believe a meaningful set of conclusions can be drawn by observing changes in leasing activity over small time periods. Nevertheless, due to high commodity prices, we expect leasing activity to remain robust and expect to see similar levels of bonus income in future periods.

Operating Expenses. Operating expenses of $0.5 million and $0.9 million, respectively, for the three and six months ended June 30, 2008 as compared to $0.3 million for the three and six months ended June 30, 2007 are predominately production and ad valorem taxes. These taxes are levied by various state and local taxing entities.

Depletion. Under the successful efforts method of accounting, we calculate depletion using the units of production method. In the case of our Minerals Segment, we only claim proved producing reserves because, as a mineral interest owner, we lack sufficient engineering and geological data to estimate the proved undeveloped and non-producing reserve quantities, and because we cannot control the occurrence or the timing of the activities that would cause such reserves to become productive. Since our units of production depletion and amortization rate are a function of our proved reserves, we experience a higher depletion and amortization rate than we would if we

claimed undeveloped or non-producing reserves. Our depletion during the three and six months ended June 30, 2008 was $1.5 million and $4.1 million, respectively, as compared to $1.5 million for the three and six months ended June 30, 2007.

One of the distinctive characteristics of our large, diversified mineral position is that operators are continually conducting exploration and development drilling, recompletion, and workover operations on our interests. We do not pay for these operations, but we do receive a share of the production they generate. This mode of operation has resulted in relatively constant production rates from our mineral interests in the past, and we expect that this will continue. We refer to this phenomenon as “regeneration”. The new sources of production that we expect to materialize due to regeneration will also be the source of future extensions and discoveries, and positive revisions to our reserve estimates, which may effect out future depletion rates. During the three and six months ended June 30, 2008, as a result of the regeneration phenomenon we received an initial royalty payment for 92 and 151 new wells, respectively.

Corporate Segment

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
	($ in thousands)
Revenue:
Unrealized commodity derivative losses	$	(256,265	)	$	(28,757	)	$	(289,337	)	$	(39,398	)
Realized commodity derivative gains (losses)		(27,708	)		1,502			(40,283	)		4,501
Total revenue		(283,973	)		(27,255	)		(329,620	)		(34,897	)
General and administrative		10,026			5,171			21,268			9,391
Other operating expense		6,214			—			6,214			1,711
Depreciation and amortization		199			199			391			372
Total costs and expenses		16,439			5,370			27,873			11,474
Operating loss		(300,412	)		(32,625	)		(357,493	)		(46,371	)
Other income (expense):
Interest income		160			176			461			300
Other income		886			91			2,433			91
Interest expense, net		(6,974	)		(8,519	)		(16,078	)		(16,399	)
Unrealized interest rate derivatives gains		13,689			6,485			29			4,874
Realized interest rate derivatives gains (losses)		(2,444	)		318			(2,545	)		534
Other expense		(232	)		(711	)		(447	)		(1,003	)
Total other income (expense)		5,085			(2,160	)		(16,147	)		(11,603	)
Loss before taxes		(295,327	)		(34,785	)		(373,640	)		(57,974	)
Income tax (benefit) provision		(886	)		256			(988	)		420
Segment loss	$	(294,441	)	$	(35,041	)	$	(372,652	)	$	(58,394	)

Revenue. As a master limited partnership, we distribute available cash (as defined in our partnership agreement) every quarter to our unitholders. The volatility inherent in commodity prices generates uncertainty in future levels of available cash. We enter into derivative transactions to reduce our exposure to commodity price risk and reduce the uncertainty of future cash flows.

Our Corporate Segment’s revenue, which solely includes our commodity derivatives activity, decreased to a loss of $284.0 million and $329.6 million for the three and six months ended June 30, 2008, respectively, from a loss of $27.3 million and $34.9 for the three and six months ended June 30, 2007, respectively. As a result of our commodity hedging activities, revenues include total realized losses of $27.7 million and $40.3 million on risk management activity that was settled during the three and six months ended June 30, 2008, respectively, and unrealized mark-to-market losses of $254.0 million and $284.7 million for the three and six months ended June 30, 2008, respectively, as compared to realized gains of $1.5 million and $4.5 million and unrealized mark-to-market losses of $26.8 million and $35.2 million for the three and six months ended June 30, 2007, respectively. In addition, we recorded amortization of put premiums of $2.3 million and $4.6 million during the three and six months ended June 30, 2008, respectively, as compared to $2.0 million and $4.2 million for the three and six months ended June 30, 2007, respectively.

As the forward price curves for our hedged commodities shift in relation to the caps, floors, and swap strike prices the fair value of such instruments changes. The unrealized, non-cash, mark-to-market net losses during the three and six months ended June 30, 2008 reflects overall favorable forward curve price movements as they relate to our physical volumes sales during the three and six month periods for commodities underlying the derivative instruments. The unrealized mark-to-market net losses for the six months ended June 30, 2008 and 2007 had no impact on cash activities for those periods and, as such, are excluded from our calculation of Adjusted EBITDA.

Given the uncertainty surrounding future commodity prices, and the general inability to predict these as they relate to the strike prices at which we have hedged our exposure, it is difficult to predict the magnitude and impact that marking our hedges to market will have in future periods on our income from operations in future periods. Conversely, negative commodity price movements affecting our revenues and costs are expected to be partially offset by our executed derivative instruments.

General and Administrative Expenses and Other Operating Expenses. General and administrative expenses increased by $4.9 million and $11.9 million to $10.0 million and $21.3 million for the three and six months ended June 30, 2008, respectively, as compared to $5.2 million and $9.4 million for the three and six months ended June 30, 2007, respectively. This growth in general and administrative expenses was mostly driven by an increase in the number of employees in our corporate office as a result of our 2007 acquisitions; our expansion into the minerals and upstream businesses related to the Montierra, Redman, EAC and Stanolind acquisitions; and to recruiting efforts in accounting, engineering, land and operations. As a result of the acquisitions and recruiting efforts, corporate-office payroll expenses increased by $3.7 million and $6.9 million for the three and six months ended June 30, 2008, respectively. In addition, other professional fees, including our public partnership expenses related to audit, tax, Sarbanes-Oxley compliance and other contract labor increased by $1.1 million and $3.1 million for the three and six months ended June 30, 2008, respectively. We also incurred increased other miscellaneous general and administrative expenses of $0.1 million and $1.9 million for the three and six months ended June 30, 2008, respectively. At the present time, we do not allocate our general and administrative expenses to our operational segments. The Corporate Segment bears the entire amount.

In July 2008, SemGroup, L.P. and certain of its subsidiaries (“SemGroup”) filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. We historically sold portions of our condensate production from our Texas Panhandle and East Texas midstream systems to SemGroup. As a result of the bankruptcy we are taking a $6.2 million bad debt charge in the second quarter of 2008, which is included in “Other Operating Expense” in the consolidated statement of operations. During July 2008, we sold pre-bankruptcy, and continued to sell, post-bankruptcy, condensate to SemGroup, for which our financial exposure is approximately $5 million to $6 million. We are seeking payment of our $6.2 million receivable as a critical supplier to SemGroup and placement in the Supplier Protection Program (“SPP”). The intent of the SPP is for SemGroup to pay certain critical suppliers their pre-bankruptcy claims in full and continue to pay such suppliers in exchange for their willingness to continue performance. It is premature at this time to predict the timing of payments, if any, under the SPP or otherwise. As of August 1, 2008, we have stopped sales of condensate to SemGroup until we have more clarity around the SPP program and treatment in the bankruptcy proceedings.

Total other income (expense). Total other income (expense), which includes both realized and unrealized gains and losses from our interest rate swaps, increased to income of $5.1 million for the three months ended June 30, 2008 and decreased to expense of $16.1 million for the six months ended June 30, 2008, as compared to expense of $2.2 million and $11.6 million for the three and six months ended June 30, 2007. During the three and six months ended June 30, 2008, we incurred realized losses from our interest rate swaps of $2.4 million and $2.5 million, respectively, as compared to realized gains of $0.3 million and $0.5 million during the three and six months ended June 30, 2007, respectively. We also incurred unrealized mark-to-market gains of $13.7 million and $0 million during the three and six months ended June 30, 2008, respectively, as compared to unrealized mark-to-market gains of $6.5 million and $4.9 million for the same periods in 2007. These unrealized mark-to-market losses did not have any impact on cash activities for the period, and are excluded by definition from our calculation of Adjusted EBITDA.

In addition, interest expense, (net) decreased to $7.0 million and $16.1 million for the three and six months ended June 30, 2008, respectively, as compared to $8.5 million and $16.4 million during the same period in the prior year, respectively. The decrease in interest expense is due to the decrease in interest rates from June 30, 2007 to June 30, 2008 as well as lower interest rate margin under the new senior revolving credit facility, partially offset by higher debt balances.

Income Tax (Benefit) Provision. Income tax benefit recorded during the three and six months ended June 30, 2008 reflects the Texas Margin Tax recorded during the current year offset by the reduction of the deferred tax liability created by the book/tax differences as a result of the federal income taxes associated with the Redman and Stanolind acquisitions (See Note 14 for additional detail).

Adjusted EBITDA.

Adjusted EBITDA, as defined under “Non-GAAP Financial Measures”, increased by $35.3 million and $74.0 million from $22.2 million and $36.2 million for the three and six months ended June 30, 2007, respectively, to $57.5 million and $110.3 million for the three and six months ended June 30, 2008, respectively.

As described above, revenues minus cost of natural gas and natural gas liquids for the Midstream Segment (including the Texas Panhandle, East Texas / Louisiana and the South Texas Segment) grew by $26.3 million and $51.8 million during the three and six months ended June 30, 2008, respectively, as compared to the comparable periods in 2007. The acquisitions which lead to our entry into our Upstream and Mineral Segments contributed an additional $53.0 million and $99.0 million to revenues during the three and six months ended June 30, 2008, respectively, as compared to the comparable periods in 2007. Our Corporate Segment’s realized commodity derivatives loss decreased by $29.2 million and $44.8 million during the three and six months ended June 30, 2008, respectively, as compared to the comparable periods in 2007. This resulted in $50.1 million and $106.1 million of total incremental revenues minus cost of natural gas and natural gas liquids during the three and six months ended June 30, 2008, respectively, as compared to the comparable periods in 2007. The incremental revenue amounts are adjusted to exclude the impact of unrealized commodity derivatives not included in the calculation of Adjusted EBITDA.

Operating expenses (including taxes other than income), were $13.0 million and $24.9 million for the three and six months ended June 30, 2008, respectively, for our Midstream Segment as compared to $11.8 million and $20.4 million to the three and six months ended June 30, 2007, respectively, while the acquisitions which created the Upstream and Minerals Segments contributed additional Operating Expenses (including taxes other than income) of $9.6 million and $17.7 million, respectively, as compared to the comparable periods in 2007.

General and administrative expense, excluding the impact of non-cash compensation charges related to our long-term incentive program (“LTIP”) and captured within our Corporate Segment, increased during the three and six month period ending June 30, 2008 by $3.9 million and $9.9 million, respectively, as compared to the respective periods ended June 30, 2007.

As a result, revenues (excluding the impact of unrealized commodity derivative activity) minus cost of natural gas and natural gas liquids for the three and six month period ending June 30, 2008, as compared to the same periods in 2007 increased by $50.1 million and $106.1 million, respectively, operating expenses increased by $10.9 million and $22.2 million, respectively, and general and administrative expenses increased by $3.9 million and $9.9 million, respectively. The increases in revenues minus the cost of natural gas and natural gas liquids, offset by increases in operating costs and general and administrative expenses resulted in an increase to Adjusted EBITDA during the three and six months ended June 30, 2008, as compared to the same periods in 2007.

Liquidity and Capital Resources.

Historically, our sources of liquidity have included cash generated from operations, equity issuances and borrowings under our existing credit facilities. We believe that the cash generated from these sources will continue to be sufficient to meet our minimum quarterly cash distributions and our requirements for short-term working capital and long-term capital expenditures for at least the next twelve months.

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

Working Capital. Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. As of June 30, 2008, working capital was a deficit of $145.1 million as compared to a $15.1 million balance as of December 31, 2007.

The net decrease in working capital of $160.2 million from December 31, 2007 to June 30, 2008, resulted primarily from the following factors:

•

risk management net working capital deficit balance increased by a net $126.4 million, primarily, as a result of increases in commodity prices since December 31, 2007, which caused increases in the unrealized losses associated with our derivative instruments;

•

cash and cash equivalents, net of due to affiliates, decreased overall by $8.1 million due to the results of operations, timing of expenditure payments, and financing activities including our debt activities;

•

trade accounts receivable increased by $50.5 million primarily from the impact of higher commodity prices; and

•

accounts payable and accrued liabilities increased by $78.3 million from December 31, 2007 primarily as a result of operating activities and timing of payments, including capital expenditures.

Derivative Financial Exposure. At June 30, 2008, the fair value of our financial derivatives was a net liability of $419.5 million. Substantially all of our counterparties to these derivatives are part of our revolving credit facility and have their outstanding debt commitments and derivative exposure collateralized pursuant to our credit facility. The Partnership has crude oil put options with two counterparties that are not in our revolving credit facility; however, due to the nature of the put options we have no “margin call” exposure on these instruments. Accordingly, we do not have exposure to potential “margin calls” on our derivative instruments which could cause us to have a significant liquidity event.

Cash Flows Six Months Ended June 30, 2008 Compared to Six Months Ended June 30, 2007

Cash Flow from Operating Activities. Cash flows provided by operating activities increased by $94.5 million during the six months ended June 30, 2008 as compared to the six months ended June 30, 2007 as a result of the contribution from acquired assets and growth projects, as well as higher commodity prices.

Cash Flows From Investing Activities. Cash flows used in investing activities for the six months ended June 30, 2008, as compared to the six months ended June 30, 2007, decreased by $49.1 million. The investing activities for the current period reflect the Stanolind acquisition of $81.3 million compared to the Laser and Montierra acquisitions in the prior year totaling $114.7 and a lower 2008 capital expenditure level of $33.1 million versus $38.0 million for 2007.

Cash Flows From Financing Activities. Cash flows used in financing activities during the six months ended June 30, 2008, decreased by $139.0 million, compared to the cash flows provided by financing activities of $127.8 million for the six months ended June 30, 2007. Key differences between periods include proceeds of $127.5 from a private placement of our units in 2007 offset by increased net borrowings under our revolving credit facility of $39.5 million. Distributions to unitholders represented a cash outflow of $57.6 million during the six months ended June 30, 2008, as compared to $16.2 million during the six months ended June 30, 2007.

Revolving Credit Facility

On December 13, 2007, we entered into a credit agreement with Wachovia Bank, National Association, as administrative agent and swing line lender, Bank of America, N.A., as syndication agent; HSH Nordbank AG, New York Branch; the Royal Bank of Scotland, plc; and BNP Paribas, as co-documentation agents, and the other lenders who are parties to the agreement with aggregate commitments up to $800 million. The new credit agreement provides terms and pricing options which are more favorable than those in the prior credit agreement. Availability as of June 30, 2008 under the new credit agreement, based on financial covenants, is $800 million. Pursuant to the credit facility we may, at our request and subject to the terms and conditions of the credit facility, increase our commitments up to $1 billion. The credit agreement is scheduled to mature on December 13, 2012.

Subsequent to June 30, 2008, we exercised $100 million of our $200 million accordion feature under the credit facility, which increased the total commitment to $900 million. We have partially exercised the accordion feature to provide for adequate funding associated with our growth strategy.

Capital Requirements.

As we expand our businesses through acquisitions and organic projects, our need for capital will increase. We anticipate that we will have sufficient access to capital to grow, maintain and commercially exploit our businesses.

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

Our original 2008 capital budget anticipated that we would spend approximately $54 million on our existing assets, of which $30 million was for growth and $24 million was for maintenance. The budget includes capital expenditures for growth, maintenance and well connect projects in both our Midstream and Upstream segments. After updating our view of the remainder of 2008 (which includes expenditures on the recent Stanolind acquisition) and the actual capital expenditures incurred during the first half of 2008 we expect to spend approximately $70 million for 2008 (excludes all acquisitions), of which $40 million was for growth and $30 million was for maintenance. We intend to finance our maintenance capital expenditures (including well connect costs) with internally generated cash flow and our growth capital expenditures utilizing our revolving credit facility.

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

•

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

•

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

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

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

Off-Balance Sheet Obligations.

We have no off-balance sheet transactions or obligations.

Debt Covenants.

At June 30, 2008, we were in compliance with the covenants of our credit facilities.

Recent Accounting Pronouncements.

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

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

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

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS No. 141R”), which replaces SFAS No. 141. SFAS 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. We are currently evaluating the potential impact, if any, of the adoption of SFAS No. 141R on our financial statements.

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

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

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

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 for fiscal years beginning after December 15, 2008 and must be applied prospectively to intangible assets acquired after the effective date. We are currently evaluating the potential impact, if any, of FSP SFAS 142-3 on our consolidated financial statements.

In May 2008, 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. We are currently evaluating the potential impact, if any, of the adoption of SFAS 162 on our consolidated financial statements.

that accrue cash dividends on share-based payment awards during the awards’ service period when dividends do not need to be returned if the employees forfeit the awards. FSP EITF 03-6-1 is effective for fiscal years beginning after December 15, 2008 and earnings-per-unit calculations would need to be adjusted retroactively. We are currently evaluating the potential impact, if any, of the adoption of FSP EITF 03-6-1 on our financial statements.

Non-GAAP Financial Measures.

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

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

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

Adjusted EBITDA does not include interest expense, income taxes or depreciation and amortization expense. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate net income. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net earnings determined under GAAP, as well as Adjusted EBITDA, to evaluate our liquidity. Our Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

Reconciliation of “Adjusted EBITDA” to net cash flows provided by operating activities and net loss

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
	($ in thousands)

Net cash flows provided by operating activities	$	89,499		$	13,938		$	122,644		$	28,119
Add (deduct):
Depreciation, depletion and amortization		(26,457	)		(14,149	)		(52,202	)		(25,779	)
Amortization of debt issuance costs		(219	)		—			(436	)		(872	)
Risk management portfolio value changes		(242,576	)		(22,272	)		(289,308	)		(34,524	)
Net realized (loss) gain on financing derivative settlements		(7,259	)		—			(9,537	)		100
Other		(111	)		(250	)		31			63
Accounts receivables and other current assets		18,719			24,277			48,933			24,720
Accounts payable, due to affiliates and accrued liabilities		(58,006	)		(24,665	)		(75,697	)		(34,540	)
Other assets and liabilities		(610	)		(662	)		224			(738	)
Net loss		(227,020	)		(23,783	)		(255,348	)		(43,451	)
Add (deduct):
Interest (income) expense, net (1)		9,490			8,025			18,609			16,568
Depreciation, depletion and amortization		26,457			14,149			52,202			25,779
Income tax (benefit) provision		(886	)		256			(988	)		420
EBITDA		(191,959	)		(1,353	)		(185,525	)		(684	)
Add (deduct):
Risk management portfolio value changes		242,576			22,272			289,308			34,524
Restricted unit compensation expense		1,559			620			2,718			792
Other income		(886	)		620			(2,433	)		(91	)
Other operating expenses (2)		6,214			—			6,214			1,711
ADJUSTED EBITDA	$	57,504		$	22,159		$	110,282		$	36,252

__________

(1)	Includes realized interest rate derivative gains and losses and other expenses.

(2)	Includes the SemGroup bad debt expense for the three and six months ended June 30, 2008 and a settlement of arbitration for $1.4 million and severance to a former executive of $0.3 million for the six months ended June 30, 2007.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Risk and Accounting Policies

We are exposed to market risks associated with adverse changes in commodity prices, interest rates and counterparty credit. We may use financial instruments such as puts, calls, swaps and other derivatives to mitigate the effects of the identified risks. Adverse effects on our cash flow from changes in crude oil, natural gas, NGL product prices or interest rates could adversely impact our ability to make distributions to our unitholders, meet debt service obligations, and fund required capital expenditures and other similar requirements. Our management has established a comprehensive review of our market risks and has developed risk management policies and procedures to monitor and manage these market risks. Our general partner is responsible for the overall approval of market risk management policies, delegation of transaction authority levels, and for the establishment of a Risk Management Committee. The Risk Management Committee is composed of officers (including, on an ex officio basis, our chief executive officer) who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of commodity price risk, interest rate risk and credit risk, including monitoring exposure limits.

Pursuant to our policies and practices we do not speculate in the buying and selling of commodity or interest rate derivates. Speculation includes, but is not limited to, buying and selling commodity or financial instruments that are not necessary for meeting forecasted production (i.e. physical production), consumption or outstanding debt service. In no event shall transactions be entered into to speculate on market conditions.

Commodity Price Risk

We are exposed to the impact of market fluctuations in the prices of crude oil, natural gas, NGLs and other commodities as a result of our gathering, processing, producing and marketing activities, which produce a naturally long position in crude oil, NGLs and natural gas. Both our profitability and our cash flow are affected by volatility in prevailing prices for these commodities. These prices are impacted by changes in the supply and demand for these commodities, as well as market uncertainty and other factors beyond our control. Historically, changes in the prices of NGLs, such as natural gasoline, have generally correlated with changes in the price of crude oil.

We have not designated our derivative contracts as accounting hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. As a result, we mark our derivatives to fair value with the resulting change in fair value included in our statement of operations. For the three months ended June 30, 2008, the Partnership recorded a loss on risk management instruments of $284.0 million representing a fair value (unrealized) loss of $254.0 million, amortization of put premiums of $2.3 million and net (realized) settlement losses of $27.7 million. For the six months ended June 30, 2008, the Partnership recorded a loss on risk management instruments of $329.6 million representing a fair value (unrealized) loss of $284.7 million, amortization of put premiums of $4.6 million and net (realized) settlement losses of $40.3 million. As of June 30, 2008, the fair value liability of these commodity contracts, including put premiums, totaled approximately $407.3 million.

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

Interest Rate Risk

We are exposed to variable interest rate risk as a result of borrowings under our existing credit agreement. To mitigate its interest rate risk, the Partnership has entered into various interest rate swaps. These swaps convert the variable-rate term loan into a fixed-rate obligation. The purpose of entering into this swap is to eliminate interest rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments through the end of 2010. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense.

We have not designated our contracts as accounting hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. As a result, we mark our derivatives to market with the resulting change in fair value included in our statement of operations. For the three months ended June 30, 2008, the Partnership recorded a fair value (unrealized) gain of $13.7 million and a realized loss of $2.4 million. For the six months ended June 30, 2008, the Partnership recorded a fair value (unrealized) gain of $0.1 million and a realized loss of $2.5 million. As of June 30, 2008, the fair value liability of these interest rate contracts totaled approximately $12.2 million.

Credit Risk

Our principal natural gas sales customers are large, gas marketing companies that in turn typically sell to large end users, such as local distribution companies and electrical utilities. In the sale of our NGLs and condensates, our principle customers are large natural gas liquids purchasers, fractionators and marketers and large condensate aggregators that also in turn typically sell to large multi-national petrochemical and refining companies. We also sell a small amount of propane to medium sized, local distributors.

This concentration of credit risk may affect our overall credit risk in that these customers may be similarly affected by changes in the natural gas, natural gas liquids, petrochemical and other segments of the energy industry, the economy in general, the regulatory environment and other factors. Our credit risk monitoring is not an absolute protection against credit loss, but we believe that our credit risk monitoring substantially mitigates the exposure to significant credit risk.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Management has conducted an evaluation of the effectiveness of the our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended, as of the end of the period covered by this report. Disclosure controls and procedures are designed to ensure that information required to be disclosed in reports filed or submitted under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and that such information is accumulated and communicated to management, including our principal executive officer and principal financial officer, to ensure timely decisions regarding required disclosures. During the evaluation of disclosure controls and procedures and our internal control over financial reporting as of December 31, 2007 conducted during the preparation of our financial statements, which were included in our Annul Report on Form 10-K for the year ended December 31, 2007, our management identified material weaknesses in internal control over financial reporting relating to our (a) Internal Control Environment, (b) Period End Financial Reporting, and (c) Midstream Cost of Natural Gas and Natural Gas Liquids. As a result, our principal executive officer and principal financial officer concluded that, as of December 31, 2007, our disclosure controls and procedures were ineffective. Upon identification of the material weaknesses and under the direction of our principal executive officer and principal financial officer, we developed a comprehensive plan to remediate the material weaknesses.

As of June 30, 2008, and as described under Status of Remediation of Material Weakness in Internal Control Over Financial Reporting below, all of the material weaknesses were not fully remediated. As a result, our principal executive officer and principal financial officer concluded that, as of June 30, 2008, our disclosure controls and procedures were not effective. Notwithstanding the aforementioned material weaknesses and failure of disclosure controls, our management has taken additional steps to assure there is appropriate disclosure in this report and has concluded that the financial statements included in this report fairly present, in all material respects, our financial condition for the periods presented in conformity with generally accepted accounting principles.

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

We have been and are actively engaged in the implementation of remediation efforts to address the material weaknesses in our internal control over financial reporting as of December 31, 2007 and any other subsequently identified significant deficiencies or material weaknesses. These remediation efforts outlined below are specifically designed to address the material weaknesses identified by our management relating to our Internal Control Environment, Period End Financial Reporting Process and Midstream Cost of Natural Gas and Natural Gas Liquids.

In our management’s analysis, we determined that the material weaknesses were caused as follows:

Internal Control Environment

We lacked training programs and job descriptions to communicate clearly management’s and employees’ roles and responsibilities in internal control over financial reporting and a sufficient number of accounting and finance professional to perform supervisory reviews and monitoring activities over financial reporting matters and controls.

Period End Financial Reporting Process

We did not have adequate internal controls relating to non-routine transactions and unusual journal entries, closing of accounting periods, account reconciliations and variance analyses, and recording hedging transactions including validation of monthly settlements and recording unrealized and realized gains/losses.

Midstream Cost of Natural Gas and Natural Gas Liquids

·	We did not have adequate internal controls relating to pricing, including controls over loading and maintenance of monthly index pricing in the revenue system associated with our Midstream Segment.

Remediated Material Weaknesses

As of the filing of this Quarterly Report on Form 10-Q, our management has completed the implementation of our remediation efforts related to the material weaknesses over the Internal Control Environment and Midstream Cost of Natural Gas and Natural Gas Liquids which included the following:

Internal Control Environment

·	Developed and delivered Internal Controls (“COSO”) training to Executives, other management and finance/accounting resources. The training included a review of management’s and individual roles and responsibilities related to internal controls;

Hired additional finance and accounting resources who possess public company accounting and reporting technical expertise. This includes five Certified Public Accounting resources. A portion of their job responsibilities is to perform reviews, reconciliations and other financial reporting monitoring controls;

Created a Compliance Office within the Risk and Compliance Department. The Compliance Office is focused on working with management to educate and inform staff on their internal control responsibilities, evaluate and assess the adequacy and operating effectiveness of internal controls and to assist management with identifying and remediating control deficiencies; and

·	Completed an Enterprise Risk Assessment covering all of the partnership’s segments. The results and our management’s action plans were reported to and discussed with the Audit Committee during the review of the June 30, 2008 Quarterly Report on Form 10-Q.

Midstream Cost of Natural Gas and Natural Gas Liquids

·	Management implemented new monitoring controls related to reviewing the accuracy of prices which are uploaded into the midstream revenue systems. These controls were independently tested by management and were determined to be operating effectively.

Management has completed its remediation efforts as of the date of this filing for these material weaknesses. Accordingly, management deems these material weaknesses remediated as of the date of the filing of this Quarterly Report on Form 10-Q.

Un-remediated Material Weakness

Management continues to devote significant planning and execution efforts toward remediation of the remaining material weakness related to period end financial reporting which is specific to controls related to the close process, including controls over:

·	Non-routine transactions and unusual journal entries;

·	Closing of accounting periods;

·	Account reconciliations and variance analyses; and

·	Recording hedging transactions including validation of monthly settlements and recording of unrealized and realized gains/losses

As of the filing of this Quarterly Report on Form 10-Q, our management has completed the following toward remediation of this material weakness:

Implemented a monthly balance sheet account reconciliation process and controls across all segments and is in the process of testing the operating effectiveness of the controls within the midstream and corporate segments. The controls within the Minerals segment have been tested and deemed to be operating effectively. Testing of the upstream segment controls are scheduled to begin in the third quarter of 2008;

·	Implemented a monthly variance fluctuation analysis across all segments. This control is also used to validate material, non-routine and unusual journal entries. Testing of this control is in progress; and

Implemented financial hedging procedures and controls to ensure the completeness and accuracy of recorded mark-to-market realized and unrealized gains and losses and also new monitoring controls to ensure that new transactions and changes to existing transactions are authorized and valid. Controls related to the completeness and accuracy of recording realized and unrealized gains and losses have been tested and the conclusion is that the controls were operating effectively.

Management is also in the process of implementing the following:

·	Controls to detect un-posted journal entries;

·	Procedures to ensure that accounting periods are closed for all segments in a timely manner and access to open and close; accounting periods is adequately restricted;

·	Controls to support the accuracy of material accruals including those accruals that are highly judgmental in nature; and

·	Continued hiring of well qualified personnel to insure that the proper accounting staff is in place to perform the necessary period end controls.

Management believes that the new procedures and controls discussed above will provide an appropriate remediation of the material weakness; however, the effectiveness of the controls have not been fully tested by management.

Due to the nature of the remediation process and the need to allow adequate time after implementation to evaluate and test the effectiveness of the controls, no assurance can be given as to the timing of achievement of remediation. The material weaknesses will be fully remediated when, in the opinion of our management, the revised control processes have been operating for a sufficient period of time and independently validated by management.

The remediation and ultimate resolution of each of the Partnership's material weaknesses will be reviewed with the Audit Committee of the Partnership's Board of Directors.

Changes in Internal Control Over Financial Reporting

During the second quarter of 2008, we completed an acquisition of Stanolind Oil and Gas Company. Because of the timing of the acquisition, management anticipates that it will not include the internal control processes for this entity in its 2008 internal controls assessment to be included in our Annual Report for the year ending December 31, 2008. The acquisition is excluded from the certifications required under Section 302 of the Sarbanes-Oxley Act of 2002. We will include all aspects of internal controls over financial reporting for this acquisition, including changes to our internal controls over financial reporting based on this acquisition, in our 2009 assessment.

All other changes in the Partnership's internal controls over financial reporting during the quarter ended June 30, 2008 that have been materially affected, or are reasonably likely to materially affect, our internal control over financial reporting have been described above.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we are and may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. However, we are not currently a party to any material litigation. We maintain insurance policies with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.

On June 20th of 2008, the Texas Commission on Environmental Quality (“TCEQ”) issued a Notice of Enforcement (“NOE”) to one of our subsidiaries, TCEQ ID No.: CF-0068-J (the “First NOE”), and on June 25th of 2008, the TCEQ issued a NOE one of our 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 during routine investigations of our Cargray facilities in the Texas Panhandle. The First NOE primarily relates to allegations of emissions in excess of those permitted, and the Second NOE primarily relates to allegations of operation of an engine in excess of the maximum hours of operation represented to the TCEQ. Both the First NOE and the Second NOE allege that the resulting emissions levels at each site result in the site being a “major source” for both nitrogen oxides and carbon monoxide, necessitating the site to have been permitted with a Title V permit, which it was not. We took prompt corrective action, by placing controls on the engine in question in the First NOE and by completely discontinuing operation of the engine in question in the Second NOE, and as a result, we believe that the sites are now in compliance and have all necessary permits with TCEQ. We anticipate that our first-time offender status and our prompt corrective actions will limit the amount of any administrative penalty to be assessed by the TCEQ. The TCEQ has great discretion to assess administrative penalties, in a range of $0 to $10,000 per day, and the allegations underpinning each of the First NOE and the Second NOE involve a time period that runs over one year.

Item 1A. Risk Factors.

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

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

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

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

Item 3. Defaults Upon Senior Securities.

None.

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

None.

Item 5. Other Information.

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

Item 6. Exhibits.

2.1	Stock Purchase Agreement dated April 2, 2008 among Eagle Rock Energy Partners, L.P., Stanolind Holdings, L.P. and Stanolind Oil and Gas Corp. (incorporated by reference to Exhibit 2.8 of the Form 8-K filed with the Commission on April 4, 2008)
31.1	Certification by Joseph A. Mills pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 7241.
31.2	Certification by Darin G. Holderness pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 7241.
32.1		Certification by Joseph A. Mills pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350.
32.2		Certification by Darin G. Holderness pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Date: August 8, 2008

EAGLE ROCK ENERGY PARTNERS, L.P.

By: EAGLE ROCK ENERGY GP, L.P., its general

partner

By: EAGLE ROCK ENERGY G&P, LLC, its

general partner

By: /s/ Darin G. Holderness

�� Darin G. Holderness

Senior Vice President and

Chief Financial Officer of Eagle Rock

Energy G&P, LLC, General Partner of Eagle Rock

Energy GP, L.P., General Partner of Eagle Rock

Energy Partners, L.P.

(Duly Authorized and Principal Financial Officer)

EAGLE ROCK ENERGY PARTNERS, L.P.

EXHIBIT INDEX

2.1	Stock Purchase Agreement dated April 2, 2008 among Eagle Rock Energy Partners, L.P., Stanolind Holdings, L.P. and Stanolind Oil and Gas Corp. (incorporated by reference to Exhibit 2.8 of the Form 8-K filed with the Commission on April 4, 2008)
31.1	Certification by Joseph A. Mills pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 7241.
31.2	Certification by Darin G. Holderness pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 7241.
32.1	Certification by Joseph A. Mills pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350.
32.2	Certification by Darin G. Holderness pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350.

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Avg

Eagle Rock Energy Partners L P (EROC) Inactive 10-Q2008 Q2 Quarterly report

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