Eagle Rock Energy Partners L P 10Q 2008 Q3 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 September 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 55,774,197 common units outstanding as of October 31, 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 September 30, 2008 and December 31, 2007	1
	Unaudited Condensed Consolidated Statements of Operations for the three months and nine months ended September 30, 2008 and 2007	2
	Unaudited Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2008 and 2007	3
	Unaudited Condensed Consolidated Statements of Members’ Equity for the nine months ended September 30, 2008	4
	Notes to Unaudited Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	45
Item 4.	Controls and Procedures	47

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	49
Item 1A.	Risk Factors	49
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	49
Item 3.	Defaults Upon Senior Securities	49
Item 4.	Submission of Matters to a Vote of Security Holders	49
Item 5.	Other Information	49
Item 6.	Exhibits	50

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

($ in thousands, except unit amounts)

	September 30, 2008			December 31, 2007

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	229,104		$	68,552
Accounts Receivable(1)		138,146			135,633
Risk management assets		5,239			—
Prepayments and other current assets		2,344			3,992
Total current assets		374,833			208,177
PROPERTY, PLANT AND EQUIPMENT — Net		1,310,422			1,207,130
INTANGIBLE ASSETS — Net		141,414			153,948
GOODWILL		29,890			29,527
RISK MANAGEMENT ASSETS		2,589			—
OTHER ASSETS		13,938			11,145
TOTAL	$	1,873,086		$	1,609,927
LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	137,893		$	132,485
Due to affiliate		16,405			16,964
Accrued liabilities		15,074			9,776
Income taxes payable		1,009			723
Risk management liabilities		60,823			33,089
Total current liabilities		231,204			193,037
LONG-TERM DEBT		799,383			567,069
ASSET RETIREMENT OBLIGATIONS		17,062			11,337
DEFERRED INCOME TAXES		42,508			17,516
RISK MANAGEMENT LIABILITIES		107,750			94,200
COMMITMENTS AND CONTINGENCIES (Note 12)
MEMBERS’ EQUITY:
Common Unitholders(2)		580,888			617,563
Subordinated Unitholders(3)		98,040			112,360
General Partner(4)		(3,749	)		(3,155	)
Total members’ equity		675,179			726,768
TOTAL	$	1,873,086		$	1,609,927

(1)	Net of allowable for bad debt of $11,093 and $1,046 as of September 30, 2008 and December 31, 2007, respectively.
(2)	50,824,031 and 50,699,647 units were issued and outstanding as of September 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 748,466 and 467,062 as of September 30, 2008 and December 31, 2007, respectively.
(3)	20,691,495 units were issued and outstanding as of September 30, 2008 and December 31, 2007, respectively.
(4)	844,551 units were issued and outstanding as of September 30, 2008 and December 31, 2007, respectively.

See notes to unaudited condensed consolidated financial statements.

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

($ in thousands, except per unit amounts)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
REVENUE:
Natural gas, natural gas liquids, oil, condensate and sulfur sales	$	421,346		$	254,084		$	1,230,134		$	555,826
Gathering, compression, processing and treating fees		12,513			8,103			27,741			19,269
Mineral and royalty income		17,393			6,009			34,606			9,201
Commodity risk management gains (losses)		231,851			8,688			(97,769	)		(26,209	)
Other revenue		428			(20	)		610			(20	)
Total revenue		683,531			276,864			1,195,322			558,067
COSTS AND EXPENSES:
Cost of natural gas and natural gas liquids		316,788			196,839			946,177			451,840
Operations and maintenance		21,475			16,883			54,772			36,015
Taxes other than income		5,365			2,746			14,975			4,364
General and administrative		9,893			7,196			31,161			16,587
Other operating expense		3,920			220			10,134	��		1,931
Depreciation, depletion and amortization		28,597			25,105			80,799			50,883
Total costs and expenses		386,038			248,989			1,138,018			561,620
OPERATING INCOME (LOSS)		297,493			27,875			57,304			(3,553	)
OTHER INCOME (EXPENSE):
Interest income		212			231			673			530
Other income		434			767			2,867			879
Interest expense, net		(7,498	)		(10,633	)		(23,576	)		(27,031	)
Interest rate risk management losses		(2,859	)		(8,102	)		(5,375	)		(2,588	)
Other expense		(205	)		(415	)		(652	)		(1,545	)
Total other expense		(9,916	)		(18,152	)		(26,063	)		(29,755	)
INCOME (LOSS) BEFORE INCOME TAXES		287,577			9,723			31,241			(33,308	)
INCOME TAX (BENEFIT) PROVISION		(494	)		352			(1,482	)		772
NET INCOME (LOSS)	$	288,071		$	9,371		$	32,723		$	(34,080	)
NET INCOME (LOSS) PER COMMON UNIT — BASIC AND DILUTED:
Basic:
Net Income (Loss)
Common units	$	2.31		$	0.25		$	0.45		$	(0.24	)
Subordinated units	$	2.31		$	(0.09	)	$	0.45		$	(1.22	)
General partner units	$	2.31		$	(0.09	)	$	0.45		$	(1.22	)
Basic (units in thousands)
Common units		50,824			45,954			50,762			32,512
Subordinated units		20,691			20,691			20,691			20,691
General partner units		845			845			845			845
Diluted:
Net Income (Loss)
Common units	$	2.31		$	0.25		$	0.45		$	(0.24	)
Subordinated units	$	2.31		$	(0.09	)	$	0.45		$	(1.22	)
General partner units	$	2.31		$	(0.09	)	$	0.45		$	(1.22	)
Diluted (units in thousands)
Common units		50,868			46,021			50,900			32,539
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)

	Nine Months Ended September 30,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income/(Loss)	$	32,723		$	(34,080	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		80,799			50,883
Amortization of debt issuance costs		655			416
Reclassifying financing derivative settlements		15,462			(100	)
Distribution from unconsolidated affiliates – return on investment		1,751			—
Equity in earnings of unconsolidated affiliates		(2,859	)		—
Equity-based compensation expense		4,147			1,578
Other		(1,726	)		(241	)
Changes in assets and liabilities — net of acquisitions:
Accounts receivable		634			(22,437	)
Prepayments and other current assets		17			2,115
Risk management activities		30,592			25,102
Accounts payable		2,742			24,516
Due to affiliates		(559	)		17,541
Accrued liabilities		(1,227	)		11,018
Other assets and liabilities		420			287
Net cash provided by operating activities		163,571			76,598
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions, net of cash acquired		(81,289	)		(403,170	)
Additions to property, plant and equipment		(45,337	)		(53,787	)
Purchase of intangible assets		(1,438	)		(1,128	)
Investment in partnership		(3,416	)		—
Other		—			22
Net cash used in investing activities		(131,480	)		(458,063	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of revolving credit facility		(145,069	)		(18,054	)
Proceeds from revolving credit facility		377,383			173,400
Proceeds (payments) on derivative contracts		(15,462	)		100
Payment of debt issuance costs		(789	)		—
Proceeds from equity issuance		—			331,500
Distributions to members and affiliates		(87,602	)		(31,775	)
Net cash provided by financing activities		128,461			455,171
NET CHANGE IN CASH AND CASH EQUIVALENTS		160,552			73,706
CASH AND CASH EQUIVALENTS — Beginning of period		68,552			10,851
CASH AND CASH EQUIVALENTS — End of period	$	229,104		$	84,557

SUPPLEMENTAL CASH FLOW DATA:
Interest paid — net of amounts capitalized	$	26,028		$	27,212
Investments in property, plant and equipment not paid	$	5,534		$	2,068
Acquisition of assets for equity	$	—		$	307,937

See notes to unaudited condensed consolidated financial statements.

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF MEMBERS’ EQUITY

FOR THE NINE MONTHS ENDED SEPTEMBER 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 income		—		382			—		22,976			—		9,365			32,723
Distributions		—		(1,016	)		—		(61,704	)		—		(24,882	)		(87,602	)
Vesting of restricted units		—		—			124,384		---			—		—			—
Distribution to affiliates		—		—			—		(857	)		—		—			(857	)
Restricted unit expense		—		40			—		2,910			—		1,197			4,147
BALANCE —September 30, 2008		844,551	$	(3,749	)		50,824,031	$	580,888			20,691,495	$	98,040		$	675,179

See notes to unaudited condensed consolidated financial statements.

EAGLE ROCK ENERGY PARTNERS, L.P

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 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, became a 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 nine-month periods ending September 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 and transporting of natural gas; fractionating and transporting natural gas liquids (“NGLs”); and marketing natural gas, condensate and NGLs, which collectively 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 mineral and royalty interests, either through direct ownership or through investment in other partnerships in properties 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 businesses 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.

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 nine months ended September 30, 2008, goodwill increased by $0.4 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, if not subject to cash out provisions, are recovered or repaid through the receipt or delivery of natural gas or natural gas liquids in future periods. Imbalance receivables are included in accounts receivable; 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 September 30, 2008, the Partnership had imbalance receivables totaling $0.5 million and imbalance payables totaling $4.8 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 to 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. Because the Partnership has not designated any of these derivatives as hedges, the Partnership recognizes these financial instruments on its consolidated balance sheets at the instrument’s fair value, and changes in fair value are reflected in the consolidated statements of operations. 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. These reclassifications had no impact on total operating income (loss) or net income (loss). Amounts recorded in "Other Income" within Revenue in the Partnerships Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2007 have been reclassified as "Natural gas, natural gas liquids, oil, condensate and sulfur sales" and as "Gathering, compression, processing and treating fees" for comparability to the 2008 presentation. Amounts for "Realized interest rate risk management gains and (losses)" were presented in "Interest expense, net," in the Partnership’s Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2007. These amounts have been presented herein as "Interest rate risk management gains (losses)" for comparability to 2008 presentation. Amounts recorded in "Interest income" in the Partnerships Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2007 have been reclassified as "Interest expense, net," for comparability to the 2008 presentation.

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 on its financial statements, if any, of adopting FSP FAS 157-2.

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 of minority interests 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.

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. 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 affects 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

2008 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 borrowings under its existing credit facility as well as existing cash from operations. Stanolind owned and operated oil and natural gas producing properties in the Permian Basin, primarily in Ward, Crane and Pecos Counties, Texas.

The purchase price was allocated on a preliminary basis to acquired assets and liabilities assumed based on their respective fair value as determined by management. 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 within 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 owning a majority of the equity interests in Eagle Rock Energy and Stanolind, the Board of Directors authorized the Company’s Conflicts Committee to review, evaluate, and, if determined appropriate, approve the Stanolind acquisition. The Conflicts Committee, consisting of independent Directors of the Company, determined that the Stanolind acquisition was fair and reasonable to Eagle Rock Energy and its public unitholders and recommended to the Board of Directors of the Company that the transaction be approved and authorized. In considering the fairness of the Stanolind acquisition, the Conflicts Committee considered the valuation of the assets and liabilities involved in the transaction and the cash flow of Stanolind. Based on the recommendation of management and the Conflicts Committee, the Board of Directors approved the transaction.

2007 Acquisitions

During the three months ended September 30, 2008, the Partnership finalized its purchase price allocations with respect to its acquisition of Escambia Asset Co., LLC and Escambia Operating Co., LLC (the “EAC Acquisition”) and its acquisition of Redman Energy Holdings, L.P. and Redman Energy Holdings II, L.P. (the “Redman Acquisition”). With respect to the EAC Acquisition, during the three months ended September 30, 2008, the Partnership increased the amount assumed for the environmental liability by $2.6 million and finalized the acquired working capital balances, which resulted in an increase to plant and related assets of $3.0 million. With respect to the Redman Acquisition, during the three months ended September 30, 2008, the Partnership finalized the acquired working capital balances which resulted in an increase to goodwill of $0.4 million.

NOTE 5. FIXED ASSETS AND ASSET RETIREMENT OBLIGATIONS

Fixed assets consisted of the following:

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

Land	$	1,153		$	1,153
Plant		196,647			181,689
Gathering and pipeline		552,221			541,247
Equipment and machinery		15,858			14,081
Vehicles and transportation equipment		3,949			3,657
Office equipment, furniture, and fixtures		1,022			1,023
Computer equipment		4,714			4,636
Corporate		126			126
Linefill		4,157			4,157
Proved properties		586,876			461,884
Unproved properties		73,621			66,023
Construction in progress		30,295			20,884
		1,470,639			1,300,560
Less: accumulated depreciation and amortization		(160,217	)		(93,430	)
Net fixed assets	$	1,310,422		$	1,207,130

Depreciation expense for the three and nine months ended September 30, 2008 and for the three and nine months ended September 30, 2007 was approximately $9.8 million, $31.8 million, $10.9 million and $26.9 million, respectively. Depletion expense for the three and nine months ended September 30, 2008 and for the three and nine months ended September 30, 2007 was approximately $14.1 million, $35.0 million, $9.4 million and $10.9 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 nine months ended September 30, 2008 and 2007, the Partnership capitalized interest costs of approximately $0.1 million, $0.5 million, $0.3 million and $0.8 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 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		751
Asset retirement obligations—September 30, 2008	$	17,062

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, $14.0 million, $4.8 million and $13.1 million for the three and nine months ended September 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:

	September 30,			December 31,
	2008			2007
	($ in thousands)
Rights-of-way and easements—at cost	$	81,507		$	80,069
Less: accumulated amortization		(10,315	)		(7,274	)
Customer contracts		108,772			108,772
Less: accumulated amortization		(38,550	)		(27,619	)
Net intangible assets	$	141,414		$	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 a weighted average as of September 30, 2008.

NOTE 7. LONG-TERM DEBT

During the three months ended September 30, 2008, the Partnership exercised $180 million of its $200 million accordion feature under its senior secured revolving credit facility (“Revolving Credit Facility”), which increased the total commitments from the Partnership’s lenders to $980 million. In connection with exercising the accordion feature of its Revolving Credit Facility, the Partnership incurred debt issuance costs of $0.8 million. As of September 30, 2008 and December 31, 2007, the Partnership had $799.4 million and $567.1 million outstanding, respectively, under its Revolving Credit Facility. As of September 30, 2008, the Partnership was in compliance with the financial covenants under its Revolving Credit Facility and the unused capacity available to the Partnership under the Revolving Credit Facility was approximately $175 million (excluding the commitment from Lehman Brothers), based on the financial covenants.

NOTE 8. MEMBERS’ EQUITY

At September 30, 2008, there were 50,824,031 common units (not including unvested restricted common units), 20,691,495 subordinated units (all owned by Holdings) and 844,551 general partner units outstanding. In addition, there were 748,466 unvested restricted common units outstanding at September 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 day of any quarter beginning after September 30, 2009 in respect of which, among other things, 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 each of the three consecutive, non-overlapping four quarter periods immediately preceding such date. 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 all its unitholders (i.e. common, including unvested restricted units, general and subordinated) of record as of February 11, 2008. The distribution amount was $0.3925 per unit, 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 all unitholders of

record as of May 9, 2008.

On July 29, 2008, the Partnership declared a cash distribution of $0.41 per unit, or approximately $30.0 million, for the second quarter ended June 30, 2008. The distribution was paid on August 14, 2008, for all unitholders of record as of August 8, 2008.

On October 29, 2008, the Partnership declared a cash distribution of $0.41 per unit for the third quarter ended September 30, 2008. The distribution will be paid on November 14, 2008, for all unitholders of record as of November 7, 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. In July 2008, the company to which we sold our natural gas was sold by the affiliate of NGP and thus ceased being a related party. For the period that such counterparty was an affiliate, the Partnership recorded revenues of $0.0 million, $16.0 million, $6.5 million and $20.4 million for the three and nine months ended September 30, 2008 and 2007, respectively, of which there was a receivable of $5.5 million outstanding at December 31, 2007, respectively.

In addition, during the three and nine months ended September 30, 2008 and September 30, 2007, the Partnership incurred $1.7 million, $4.7 million, $1.1 million and $4.0 million in expenses with related parties, of which there was an outstanding accounts payable balance of $0.5 million and $0.5 million as of September 30, 2008 and December 31, 2007.

Related to its investments in unconsolidated subsidiaries, during the three and nine months ended September 30, 2008 and 2007, the Partnership recorded income of $0.4 million and $2.9 million, respectively, of which there was no outstanding account receivable balance as of September 30, 2008 and December 31, 2007, respectively.

As of September 30, 2008 and December 31, 2007, Eagle Rock Energy G&P, LLC had $16.4 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 and nine months ended September 30, 2008, the Partnership incurred approximately $1.0 million and $1.6 million for services performed by Stanolind Field Services (“SFS”), which are assets controlled by NGP and certain individuals, including one employee of Eagle Rock Energy G&P, LLC. As of September 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 gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurements). The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:

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

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value,

volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the market place throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

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

As of September 30, 2008, the Partnership has recorded its interest rate swaps and commodity derivative instruments (see Note 11), which includes crude oil, natural gas and natural gas liquids (“NGLs”), at fair value. 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. Because the NGL market is considered to be less liquid beyond one year's time, 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. The following table discloses the fair value of the Partnership’s derivative instruments as of September 30, 2008:


	Level 1		Level 2			Level 3			Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	7,705		$	—		$	7,705
Natural gas derivatives		—		123			—			123
Total	$	—	$	7,828		$	—		$	7,828

Liabilities:
Crude oil derivatives	$	—	$	(125,478	)	$	—		$	(125,478	)
Natural gas derivatives		—		(931	)		—			(931	)
NGL derivatives		—		(15,241	)		(14,223	)		(29,464	)
Interest rate derivatives		—		(12,700	)		—			(12,700	)
Total	$	—	$	(154,350	)	$	(14,223	)	$	(168,573	)

As of September 30, 2008, risk management current assets in the Condensed Consolidated Balance Sheet include an investment premium of $5.5 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 September 30, 2008 (in thousands):

Net liability balances as of July 1, 2008	$	36,856
Transfers from Level 3 to Level 2		(4,931	)
Unrealized gains		(17,702	)
Net liability balances as of September 30, 2008	$	14,223

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

Net liability balances as of January 1, 2008	$	36,695
Transfers from Level 3 to Level 2		(15,661	)
Unrealized gains		(6,811	)
Net liability balances as of September 30, 2008	$	14,223

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 rate risk management gains and losses in the Condensed Consolidated Statements of Operations. Realized and unrealized gains and 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.

The carrying amount of cash equivalents is believed to approximate their fair values because of the short maturities of these instruments. As of September 30, 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 a portion of 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, demand, 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 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’s derivative counterparties include BNP Paribas, Wachovia, Barclay’s, Royal Bank of Scotland, Bank of America, Wells Fargo, J Aron (an affiliate of Goldman Sachs), British Petroleum and Shell.

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 200-	Gas	20,000 MMbtu	WEST TEXAS (WAHA)	$	7.50	$	8.90

The Partnership entered into the following derivative transactions associated with its Midstream business during the three months ended September 30, 2008. For the crude oil puts that were acquired, the Partnership paid premiums totaling $3.3 million. The natural gas collars were costless transactions that were entered into in order to reduce the Partnership’s exposure to potential natural gas increases. The transactions offset previous derivative transactions, and were necessary because of change in the Partnership’s expected net natural gas position.

				Price ($ per MMbtu or $ per Bbl)
Period	Commodity	Average Volumes per Month	Index	Average Floor		Average Ceiling
Jan-Dec 2009	Oil	7,000 Bbl	NYMEX WTI	$	90.00
Jan-Dec 2009	Oil	5,000 Bbl	NYMEX WTI	$	100.00
Jan-Dec 2010	Oil	6,000 Bbl	NYMEX WTI	$	90.00
Jan-Dec 2010	Oil	5,000 Bbl	NYMEX WTI	$	100.00
Sep-Oct 2008	Gas	(103,000) MMbtu	NYMEX Henry Hub	$	8.65	$	10.62
Nov-Dec 2008	Gas	(103,000) MMbtu	NYMEX Henry Hub	$	8.35	$	13.75
Jan-Mar 2009	Gas	(92,700) MMbtu	NYMEX Henry Hub	$	8.80	$	13.75

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's accruals were approximately $1.3 million and $1.5 million as of September 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. 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 Partnership's insurance coverage includes (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 director and officer 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 September 30, 2008 and December 31, 2007, the Partnership had accrued, on an undiscounted basis, approximately $7.8 million and $2.4 million, respectively, for environmental matters.

TCEQ Matters—In 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 a second 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. During the three months ended September 30, 2008, the Partnership executed an Agreed Order resolving with the TCEQ the two Notice of Enforcement matters. The administrative penalties paid by the Partnership were, in the aggregate, less than $10,000, and the Partnership considers these matters concluded at this time.

In late September 2008, the TCEQ issued another Notice of Enforcement to a subsidiary of the Partnership, concerning the environmental compliance of the Partnership’s Red Deer Gas Plant (the “Site”), TCEQ ID No.: RH 0004-B (the “NOE”). The allegations in the NOE are the result of findings made by the TCEQ’s Amarillo Region Office as a result of a routine inspection of the Site. In response, the subsidiary of the Partnership is providing substantial documentation, some of which is corrective in nature, to the TCEQ and is contesting certain other allegations. The TCEQ has great discretion to assess administrative penalties, in a range of $0 to $10,000 per day, and the allegations underpinning the NOE involve a time period that runs over one year. The TCEQ has not yet made a final determination with respect to whether 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 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 for the retained revenue interests on a monthly basis.

The retained revenue interests affect the Partnership’s interest at the Big Escambia Creek, Flomaton and Fanny Church fields in Escambia County, Alabama. With respect to the Partnership’s Flomaton and Fanny Church fields, 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 and possibly 2010. With respect to the Partnership’s Big Escambia Creek field, these payments are expected 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, $3.7 million, $0.3 million and $0.5 million for the three and nine months ended September 30, 2008 and September 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 that is its Upstream Business, one minerals segment that is its Minerals Business and one functional (corporate) segment:

(i) Midstream—Texas Panhandle Segment:

gathering, processing, transportating and marketing of natural gas, condensate and NGLs in the Texas Panhandle;

(ii)

Midstream—South Texas Segment:

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

(iii)

Midstream—East Texas/Louisiana Segment:

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

(iv)

Upstream Segment:

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

(v)

Minerals Segment:

fee minerals and royalties, lease bonus and rental income either through direct ownership or through investment in other partnerships; and

(vi)

Corporate Segment:

risk management and other corporate activities.

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 September 30, 2008	Texas Panhandle Segment		South Texas Segment		East Texas / Louisiana Segment		Total Midstream Segments
($ in millions)
Sales to external customers	$	182.3	$	115.8	$	80.8	$	378.9
Cost of natural gas and natural gas liquids		138.4		112.4		66.0		316.8
Operating costs and other expenses		9.2		0.6		4.2		14.0
Depreciation, depletion, and amortization		11.0		0.9		3.0		14.9
Operating income	$	23.7	$	1.9	$	7.6	$	33.2
Capital Expenditures	$	7.2	$	0.2	$	2.6	$	10.0
Segment Assets	$	580.6	$	89.6	$	250.9	$	921.1

Three Months Ended September 30, 2008	Total Midstream Segments		Upstream Segment		Minerals Segment		Corporate Segment			Total Segments
($ in millions)
Sales to external customers	$	378.9	$	55.4	$	17.4	$	231.8	(a)	$	683.5
Cost of natural gas and natural gas liquids		316.8		—		—		—			316.8
Operating costs and other expenses		14.0		12.4		0.4		13.8			40.6
Depreciation, depletion, and amortization		14.9		11.2		2.3		0.2			28.6
Operating income	$	33.2	$	31.8	$	14.7	$	217.8		$	297.5
Capital Expenditures	$	10.0	$	4.5	$	—	$	0.3		$	14.8
Segment Assets	$	921.1	$	634.5	$	149.4	$	168.1		$	1,873.1

Midstream Segments Three Months Ended September 30, 2007	Texas Panhandle Segment		South Texas Segment		East Texas / Louisiana Segment		Total Midstream Segments
($ in millions)
Sales to external customers	$	130.2	$	64.3	$	48.6	$	243.1
Cost of natural gas and natural gas liquids		96.9		61.6		38.4		196.9
Operating costs and other expenses		9.6		0.4		3.6		13.6
Depreciation, depletion, and amortization		10.4		0.9		3.3		14.6
Operating income	$	13.3	$	1.4	$	3.3	$	18.0
Capital Expenditures	$	7.2	$	0.8	$	5.7	$	13.7
Segment Assets	$	584.0	$	62.3	$	290.6	$	936.9

Three Months Ended September 30, 2007	Total Midstream Segments		Upstream Segment		Minerals Segment		Corporate Segment			Total Segments
($ in millions)
Sales to external customers	$	243.1	$	19.1	$	6.0	$	8.7	(a)	$	276.9
Cost of natural gas and natural gas liquids		196.9		—		—		—			196.9
Operating costs and other expenses		13.6		5.8		0.2		7.4			27.0
Depreciation, depletion, and amortization		14.6		6.9		3.4		0.2			25.1
Operating income (loss)	$	18.0	$	6.4	$	2.4	$	1.1		$	27.9
Capital Expenditures	$	13.7	$	—	$	—	$	—		$	13.7
Segment Assets	$	936.9	$	470.9	$	160.8	$	94.2		$	1,662.8

________________________________________

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

Midstream Segments Nine months Ended September 30, 2008	Texas Panhandle Segment		South Texas Segment		East Texas / Louisiana Segment		Total Midstream Segments
($ in millions)
Sales to external customers	$	522.1	$	346.9	$	249.1	$	1,118.1
Cost of natural gas and natural gas liquids		398.9		337.4		209.9		946.2
Operating costs and other expenses		25.6		1.8		11.6		39.0
Depreciation, depletion, and amortization		32.6		2.8		8.8		44.2
Operating income	$	65.0	$	4.9	$	18.8	$	88.7
Capital Expenditures	$	20.6	$	0.8	$	8.7	$	30.1
Segment Assets	$	580.6	$	89.6	$	250.9	$	921.1

Nine months Ended September 30, 2008	Total Midstream Segments		Upstream Segment		Minerals Segment		Corporate Segment			Total Segments
($ in millions)
Sales to external customers	$	1,118.1	$	140.4	$	34.6	$	(97.8	)(a)	$	1,195.3
Cost of natural gas and natural gas liquids		946.2		—		—		—			946.2
Operating costs and other expenses		39.0		29.4		1.4		41.3			111.1
Depreciation, depletion, and amortization		44.2		29.5		6.4		0.6			80.7
Operating income (loss)	$	88.7	$	81.5		26.8	$	(139.7	)	$	57.3
Capital Expenditures	$	30.1	$	17.7	$	—	$	0.5		$	48.3
Segment Assets	$	921.1	$	634.5	$	149.4	$	168.1		$	1,873.1

Midstream Segments Nine months Ended September 30, 2007	Texas Panhandle Segment		South Texas Segment		East Texas / Louisiana Segment		Total Midstream Segments
($ in millions)
Sales to external customers	$	335.2	$	115.1	$	105.7	$	556.0
Cost of natural gas and natural gas liquids		258.5		110.8		82.5		451.8
Operating costs and other expenses		25.6		0.7		7.8		34.1
Depreciation, depletion, and amortization		30.2		1.3		7.2		38.7
Operating income	$	20.9	$	2.3	$	8.2	$	31.4
Capital Expenditures	$	29.7	$	2.1	$	24.1	$	55.9
Segment Assets	$	584.0	$	62.3	$	290.6	$	936.9

Nine months Ended September 30, 2007	Total Midstream Segments		Upstream Segment		Minerals Segment		Corporate Segment			Total Segments
($ in millions)
Sales to external customers	$	556.0	$	19.1	$	9.2	$	(26.2	)(a)	$	558.1
Cost of natural gas and natural gas liquids		451.8		—		—		—			451.8
Operating costs and other expenses		34.1		5.8		0.5		18.5			58.9
Depreciation, depletion, and amortization		38.7		6.9		4.8		0.6			51.0
Operating income (loss)	$	31.4	$	6.4	$	3.9	$	(45.3	)	$	(3.6	)
Capital Expenditures	$	55.9	$	—	$	—	$	0.5		$	56.4
Segment Assets	$	936.9	$	470.9	$	160.8	$	94.2		$	1,662.8

_______________________________________

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

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. (acquiring entity of certain entities acquired in the Redman acquisition) and Eagle Rock Energy Acquisition Co. II, Inc. (acquiring entity of certain entities acquired in the Stanolind acquisition) and their wholly-owned corporations, Eagle Rock Upstream Development Company, Inc. (successor entity to certain entities acquired in the Redman acquisition) and Eagle Rock Upstream Development Company II, Inc. (successor entity to certain entities acquired in the Stanolind acquisition), 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 $0.2 million and $0.6 million were used during the three and nine months ended September 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 effective rate for the three and nine month periods ended September 30, 2008 was (0.2%) and (4.7%), respectively compared to 100% and 100% for the same periods in 2007. The changes in effective tax rates are attributable to the provision amounts for the total of state and federal taxes being applied against book income for the three months and nine month periods of 2008 whereas they were applied against book losses for the same period in 2007 which resulted in a 100% effective tax rate for those periods.

Deferred taxes - As of September 30, 2008, the net deferred tax liability was $42.5 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 Company II, Inc. our wholly-owned corporations which are subject to federal income taxes. Eagle Rock Upstream Development Company 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 and Redman acquisitions.

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

Eagle Rock Energy G&P, LLC, 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 and its subsidiaries and affiliates covering an aggregate of 2,000,000 common units to be granted either as options, restricted units or phantom units. The Partnership has historically only issued restricted units under the LTIP. As to outstanding restricted units, distributions associated with the restricted units will be distributed directly to the awardees. No options or phantom units have been issued to date.

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

	Number of Restricted Units			Weighted Average Fair Value per Unit
Outstanding at December 31, 2007		467,062		$	23.01
Granted		538,450		$	16.54
Vested		(124,384	)	$	23.27
Forfeitures		(132,662	)	$	18.90
Outstanding at September 30, 2008		748,466		$	19.04

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

For the three and nine months ended September 30, 2008 and September 30, 2007, non-cash compensation expense of approximately $1.4 million, $4.1 million, $0.8 million and $1.6 million respectively, was recorded related to the granted restricted units.

As of September 30, 2008, unrecognized compensation costs related to the outstanding restricted units under our LTIP totaled approximately $13.3 million. The remaining expense is to be recognized over a weighted average of 2.1 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), in accordance with the amount of distributions made for the quarter by each class, if any. The remaining net income (loss) is 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.

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

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

Net income (loss)	$	288,071		$	9,371		$	32,723	$	(34,080	)
Less: Incentive Distribution Rights		(121,090	)		—			—		—
Net income (loss) to be allocated	$	166,981		$	9,371		$	32,723	$	(34,080	)

Net loss allocated to:
Common units	$	117,284		$	6,372		$	22,976	$	(20,448	)
Subordinated units	$	47,749		$	2,905		$	9,365	$	(12,950	)
General partner units	$	1,948		$	94		$	382	$	(682	)

Basic weighted average unit outstanding during period:
Common units		50,824			45,954			50,762		32,512
Subordinated units		20,691			20,691			20,691		20,691
General partner units		845			845			845		845
Basic Earnings Per Unit:
Common units	$	2.31		$	0.25		$	0.45	$	(0.24	)
Subordinated units	$	2.31		$	(0.09	)	$	0.45	$	(1.22	)
General partner units	$	2.31		$	(0.09	)	$	0.45	$	(1.22	)

Diluted weighted average unit outstanding during period:
Common units		50,868			46,021			50,900		32,539
Subordinated units		20,691			20,691			20,691		20,691
General partner units		845			845			845		845
Diluted Earnings Per Unit:
Common units	$	2.31		$	0.25		$	0.45	$	(0.24	)
Subordinated units	$	2.31		$	(0.09	)	$	0.45	$	(1.22	)
General partner units	$	2.31		$	(0.09	)	$	0.45	$	(1.22	)

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, through certain subsidiaries, 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 filing, the Partnership recorded a $6.2 million bad debt charge in the second quarter of 2008, and the Partnership recorded an additional $3.9 million as a bad debt charge during the three months ended September 30, 2008. The bad debt charges are included in “Other Operating Expense” in the consolidated statement of operations. The Partnership stopped all sales to SemGroup as of August 1, 2008, and as a result, the Partnership does not anticipate recording any additional bad debt charges in future periods. Other operating expenses for the nine months ended September 30, 2008 consisted of the aggregate $10.1 million bad debt charge for the Partnership’s aggregate outstanding SemGroup receivable, whereas the other operating expenses for the nine months ended September 30, 2007 consisted of an arbitration settlement of $1.4 million, a severance payout to a former executive of $0.3 million and liquidated damages related to the late registration of the Partnership’s common units for $0.2 million.

NOTE 18. HURRICANES IKE AND GUSTAV

Hurricane Ike, which made landfall in Texas on September 13, 2008, caused no material damage to the Partnership’s offices, facilities or assets; however, the storm did cause temporary operational disruption to the Partnership's operations located in East Texas, North Louisiana and South Texas due to third party downstream infrastructure issues. Operations were either temporarily interrupted or curtailed during and immediately after the storm due to power disruptions suffered by third parties causing natural gas and natural gas liquids supply and market issues. All of the Partnership’s operations returned to pre-hurricane levels within ten days after the storm. The Partnership’s assets were not impacted by Hurricane Gustav.

NOTE 19. SUBSEQUENT EVENTS

On October 1, 2008, the Partnership completed the acquisition of 100% of the outstanding units of Millennium Midstream Partners, L.P. (“MMP”) for an aggregate purchase price of $225.9 million, comprised of approximately, $181.5 million in cash and 4,000,000 (recorded value of $44.4 million) common units, subject to post closing purchase price adjustments. The cash portion of the consideration was funded through borrowings of $176.4 million under the Partnership’s Revolving Credit Facility made prior to September 30, 2008 and cash on hand. MMP is in the natural gas gathering and processing business, with assets located in East, Central and West Texas and South Louisiana. With respect to the South Louisiana assets acquired in the Millennium acquisition, the Yscloskey and North Terrebonne facilities were flooded with three to four feet of water as a result of the storm surges caused by Hurricanes Ike and/or Gustav. The Partnership has filed claims for, and expects to receive payment on its business interruption insurance coverage related to Hurricane Ike and Gustav’s damage to these two facilities. The timing of collection of such insurance claims is unknown at this time. The expected timing for the facilities to be brought back on line is currently late November 2008. The former owners of MMP provided the Partnership idemnity coverage for Hurricanes Ike and Gustav to the extent losses are no covered by insurance, and there is an escrow of 2,036,364 common units and $0.6 million in cash available for the Partnership to recover against for this purpose.

On October 31, 2008, the Partnership reset two existing crude oil swap transactions. The first swap was reset from $73.90 to $100 per barrel on 80,000 barrels per month for months of November and December, 2008. The second swap was reset from $80.25 to $100 per barrel on 50,000 barrels per month for calendar year 2009. The total cost of these reset swaps was $15.9 million. The strike prices of these swaps were reset to stabilize overall cash flows for the months of November and December, 2008 and all of 2009 and to provide further assurance of the Partnership’s ability to maintain its current rate of distribution in the face of declining commodity prices and industry activity.

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 and transporting of natural gas; fractionating and transporting of natural gas liquids (“NGLs”); and the marketing of natural gas, condensate and NGLs;

•

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

•

Minerals Business—acquiring and managing fee mineral and royalty interests, either through direct ownership or through investment in other partnerships.

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 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, Shelby, Panola, Ward, Crane, Pecos and Atascosa Counties, Texas.

We conduct, evaluate, and report our Minerals Business as one segment. Our Minerals Segment consists of fee mineral, royalty and overriding royalty interests located in multiple producing trends in the United States. A significant portion of the mineral interests that we own are managed by a non-affiliated private partnership (the “Minerals Manager”) that controls the executive rights associated with the minerals. We acquired our interest in these minerals by participating as a co-investor when the Minerals Manager acquired its interest. As part of that transaction, we also owned a minority interest in a partnership (“Ivory Acquisition Partners”) that owned an interest in the same minerals that we purchased and hold directly. Ivory Acquisition Partners is controlled by the Minerals Manager, and it was specified at the time of the acquisition of these minerals that our interest in Ivory Acquisition Partners would revert to the Minerals Manager if certain payout hurdles were reached. The hurdles have been reached and we no longer have an interest in Ivory Acquisition Partners. The impact of this reversion on the financial statements is discussed under “Corporate Segment – Other Income and Expenses.”

We also own a minority interest in another non-affiliated partnership (“Ivory Working Interest Partners”) that is controlled by the Minerals Manager. Ivory Working Interest Partners owns non-operating working interests in certain wells that are drilled on those minerals that are managed by the Minerals Manager. Ivory Working Interest Partners owns these non-operated working interests by virtue of the terms of certain leases negotiated by the Minerals Manager. We believe that Ivory Working Interest Partners will continue to participate in the drilling of new wells as a non-operating working interest owner. In general, Ivory Working Interest Partners attempts to fund its activities from its internal cash flow; however, it has the right to retain cash derived from the payment of royalties, bonus and delay rentals related to the mineral interests that it manages to fund its activities of Ivory Working Interest Partners, to the extent necessary and approved by the partners.

Our final reporting segment 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.

Hurricanes Ike and Gustav

Hurricane Ike, which made landfall in Texas on September 13, 2008, caused no material damage to our offices, facilities or assets; however, the storm did cause temporary operational disruption to our operations located in East Texas, North Louisiana and South Texas due to third party downstream infrastructure issues. Operations were either temporarily interrupted or curtailed during and immediately after the storm due to power disruptions suffered by third parties causing natural gas and natural gas liquids supply and market issues. All of our operations returned to pre-hurricane levels within ten days after the storm. Our assets were not impacted by Hurricane Gustav.

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”). One or more Natural Gas Partners private equity funds owned a majority of the equity interests in Stanolind. We funded the transaction from existing cash from operations, as well as with borrowings under our existing secured revolving credit facility. Stanolind operated 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 (by direct acquisition or acquisition of certain entities) of certain fee minerals, royalties, working interest properties and certain investments in partnerships 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 Co., 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.

Recent Acquisition

On October 1, 2008, we completed the acquisition of 100% of the outstanding units of Millennium Midstream Partners, L.P. (“MMP”), and thereby acquired control of its operating subsidiaries, for an aggregate purchase price of $225.9 million, comprised of approximately, $181.5 million in cash and 4,000,000 (recorded value of $44.4 million) common units, subject to post-closing purchase price adjustments. The cash portion of the consideration was funded through borrowings of $176.4 million

under our secured revolving credit facility made prior to September 30, 2008 and cash on hand. MMP is in the natural gas gathering and processing business, with assets located in East, Central and West Texas and South Louisiana. With respect to the South Louisiana assets acquired in the Millennium acquisition, the Yscloskey and North Terrebonne facilities were flooded with three to four feet of water as a result of the storm surges caused by Hurricanes Ike and/or Gustav.. We have filed claims for, and expect to receive payment on our business interruption insurance coverage related to Hurricane Ike and Gustav's damage to these two facilities. The timing of collection of such insurance claims is unknown at this time. The expected timing for the facilities to be brought back on line is currently late November 2008. The former owners of MMP provided us idemnity coverage for Hurricane Ike and Gustav, to the extent losses are not covered by insurance, and there is an escrow of 2,036,364 common units and $0.6 million of cash available for us to recover against for this purpose.

Recent Transactions

On October 31, 2008, we reset two existing crude oil swap transactions. The first swap was reset from $73.90 to $100 per barrel on 80,000 barrels per month for the months of November and December, 2008. The second swap was reset from $80.25 to $100 per barrel on 50,000 barrels per month for calendar year 2009. The total cost of these reset swaps was $15.9 million. The strike prices of these swaps were reset to stabilize overall cash flows for the balance the months of November and December, 2008 and all of 2009 and to provide further assurance of our ability to maintain our current rate of distribution in the face of declining commodity prices and industry activity.

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 and operating expenses on a segment basis 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. More significantly, recent events impacting the world’s economy and financial systems, including but not limited to, a generalized stagnation in the world’s banking system and access to credit markets, precipitous drops in the value of almost all asset classes including equity, bonds, real estate, and other investment vehicles, significant drops in commodity prices including the prices for crude oil, natural gas, NGL's, condensate and sulfur, among others, as well as the generalized expectation of a prolonged period of recession, will play an important role in the performance and growth perspectives for our business. 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 nine months ended September 30, 2008 and September 30, 2007, respectively. Operating results for our individual operating segments are presented in tables in this Item 2.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	($ in thousands)
Revenue:
Natural gas, natural gas liquids, oil, condensate and sulfur sales	$	421,346		$	254,084		$	1,230,134		$	555,826
Gathering compression, processing and treating fees		12,513			8,103			27,741			19,269
Minerals and royalty income		17,393			6,009			34,606			9,201
Realized commodity derivative gains (losses)		(24,105	)		(177	)		(64,388	)		4,324
Unrealized commodity derivative gains (losses) ...		255,956			8,865			(33,381	)		(30,533	)
Other		428			(20	)		610			(20	)
Total revenue		683,531			276,864			1,195,322			558,067
Cost of natural gas and natural gas liquids		316,788			196,839			946,177			451,840
Expenses:
Operating and maintenance		21,475			16,883			54,772			36,015
Taxes other than income		5,365			2,746			14,975			4,364
General and administrative		9,893			7,196			31,161			16,587
Other operating expense		3,920			220			10,134			1,931
Depreciation, depletion, and amortization		28,597			25,105			80,799			50,883
Total costs and expenses		386,038			248,989			1,138,018			561,620
Operating income (loss)		297,493			27,875			57,304			(3,553	)
Other income (expense):
Interest income		212			231			673			530
Other income		434			767			2,867			879
Interest expense, net		(7,498	)		(10,633	)		(23,576	)		(27,031	)
Unrealized interest rate derivatives losses		(501	)		(8,429	)		(472	)		(3,555	)
Realized interest rate derivative gains (losses)...		(2,358	)		327			(4,903	)		967
Other expense		(205	)		(415	)		(652	)		(1,545	)
Total other expense		(9,916	)		(18,152	)		(26,063	)		(29,755	)
Income (loss) before taxes		287,577			9,723			31,241			(33,308	)
Income tax (benefit) provision		(494	)		352			(1,482	)		772
Net income/(loss)	$	288,071		$	9,371		$	32,723		$	(34,080	)
Adjusted EBITDA(a)	$	75,481		$	45,155		$	185,765		$	81,407

(a)	See "Non-GAAP Financial Measures" and Reconciliation of 'Adjusted EBITDA' to net cash flows provided by operating activities and net income (loss)" 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 September 30, 2008, based on operating income of our non-Corporate segments, our midstream business comprised approximately 41.6% of our business (with the Texas Panhandle Segment accounting for 29.7% of our business, the South Texas Segment accounting for 2.4% of our business, and the East Texas/Louisiana Segment accounting for 9.5% of our business), our upstream business comprised approximately 40.0% of our business, and our minerals business comprised approximately 18.4% of our business. For the nine months ended September 30, 2008, based on operating income of our non-Corporate segments, our midstream business comprised approximately 45.0% of our business (with the Texas Panhandle Segment accounting for 33.0% 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 41.4% of our business, and our minerals business comprised approximately 13.6% 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 September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	($ in thousands, except for price data)
Revenue:
Sales of natural gas, NGLs, oil and condensate	$	179,608		$	128,008		$	514,450		$	328,672
Gathering and treating services		2,671			2,234			7,664			6,536
Other		—			(20	)		—			(20	)
Total revenue		182,279			130,222			522,114			335,188
Cost of natural gas and natural gas liquids		138,428			96,872			398,828			258,577
Operating costs and expenses:
Operating		9,190			9,603			25,653			25,608
Depreciation and amortization		10,984			10,466			32,587			30,231
Total operating costs and expenses		20,174			20,069			58,240			55,839
Operating income	$	23,677		$	13,281		$	65,046		$	20,772
Capital Expenditures	$	7,152		$	7,158		$	20,607		$	29,731

Realized average prices:
Oil and condensate (per Bbl)	$	106.43		$	63.41		$	105.03		$	54.62
Natural gas (per Mcf)	$	8.81		$	5.45		$	8.85		$	6.02
NGLs (per Bbl)	$	66.36		$	53.34		$	67.62		$	48.72

Production volumes:
Gathering volumes (Mcf/d)(a)		159,254			164,544			154,190			147,523
NGLs and condensate (net equity gallons)		22,752,290			23,644,648			64,287,333			65,278,803
Natural gas short position (MMbtu/d)(a)		(4,150	)		(6,330	)		(5,458	)		(7,389	)

__________________

(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 nine months ended September 30, 2008, the revenues minus cost of natural gas and natural gas liquids for our Texas Panhandle Segment operations totaled $43.9 million and $123.3 million compared to $33.4 and $76.6 million for the three and nine months ended September 30, 2007. There were two primary contributors to this increase: (i) higher NGL and condensate pricing, as compared to pricing in 2007, and (ii) a lower natural gas short position as compared to 2007.

The higher 2008 gathering volumes during the nine month period compared to 2007 was primarily due to a full nine months of Red Deer Plant operations in 2008 compared to only three months in 2007 and the colder than normal weather in that area along with the downtime to repair the Arrington plant during 2007, which reduced gathering volumes during the three and nine months ended September 30, 2007. The lower gathering volumes during the three months ended September 30, 2008 compared to the same period in 2007 are primarily due to the continued decline of volumes on the West Panhandle system and reduced drilling activity during the first nine months of 2008 that was not sufficient to replace the West Panhandle System decline and the natural decline in the East Panhandle System.

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 drilling activity in 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 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 nine months ended September 30, 2008 as compared to the nine months ended September 30, 2007, our equity share of liquids production would have been less through the nine months ended September 30, 2008 as compared to the nine months ended September 30, 2007. 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 nine months ended September 30, 2008 to handle additional volumes of 3 MMcf/d, bringing total capacity to 23 MMcf/d. We completed the consolidation of the Stinnett Plant to the Cargray Plant during the three months ending September 30, 2008, and we are in the process of relocating the cryogenic Stinnett Plant to replace the older technology Arringtion Plant which will result in additional processing capacity on the East Panhandle System and better NGL recovery from the processed natural gas.

Operating Expenses. Operating expenses, including taxes other than income, for three and nine months ended September 30, 2008 were $9.2 million and $25.7 million compared to $9.6 million and $25.6 million for the three and nine months ended September 30, 2007. The three and nine months ended September 30, 2007 included additional maintenance costs for repairing the Arrington plant. The major items impacting the $0.1 million increase in operating expense for the nine months ended September 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 nine months ended September 30, 2008 were $11.0 million and $32.6 million compared to $10.5 million and $30.2 million for the three and nine months ended September 30, 2007. The major items impacting the $0.5 million and $2.4 million increases was placing the Red Deer Plant into service and beginning the depreciation expense associated with the other capital expenditure projects put into service.

Capital Expenditures. Capital expenditures for the three and nine months ended September 30, 2008 were $7.2 million and $20.6 million as compared to $7.2 million and $29.7 million for the three and nine months ended September 30, 2007. During the nine months ended September 30, 2008, of our capital spending in this segment, we spent $14.2 million on growth capital and $6.4 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 of $9.1 million in capital spending for the nine month period of 2008 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 September 30,				Nine Months Ended September 30,
	2008		2007(b)		2008		2007(b)
	($ in thousands, except for price data)
Revenue:
Sales of natural gas, NGLs, oil and condensate	$	71,861	$	44,215	$	231,996	$	95,409
Gathering and treating services		8,908		4,352		17,056		10,284
Total revenue		80,769		48,567		249,052		105,693
Cost of natural gas and natural gas liquids		66,007		38,397		209,937		82,491
Operating costs and expenses:
Operating		4,194		3,619		11,511		7,778
Depreciation and amortization		2,989		3,281		8,846		7,213
Total operating costs and expenses		7,183		6,900		20,357		14,991
Operating income	$	7,579	$	3,270	$	18,758	$	8,211
Capital Expenditures	$	2,591	$	5,696	$	8,686	$	24,056

Realized average prices:
Oil and condensate (per Bbl)	$	125.29	$	75.48	$	117.16	$	66.46
Natural gas (per Mcf)	$	9.69	$	5.86	$	10.37	$	6.39
NGLs (per Bbl)	$	57.54	$	44.52	$	56.28	$	41.58

Production volumes:
Gathering volumes (Mcf/d) (a)		173,728		155,540		172,434		125,590
NGLs and condensate (net equity gallons)		6,768,037		4,742,723		18,696,086		12,573,603
Natural gas short position (MMbtu/d) (a)		747		1,116		885		1,485

_____________

(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 nine months ended September 30, 2008, revenues minus cost of natural gas and natural gas liquids for our East Texas/Louisiana Segment totaled $14.7 million and $39.1 million, respectively, compared to $10.2 million and $23.2 million, respectively, for the three and nine months ended September 30, 2007.

We were positively impacted from higher NGL and condensate pricing during the three and nine months ended September 30, 2008 as compared to the three and nine months ended September 30, 2007. We were also positively impacted by an 11.7% growth in daily gathering volumes during the three months ended September 30, 2008, and a 37.3% growth in daily gathering volumes during the nine months ended September 30, 2008, compared to the comparable period in 2007. Increased volumes were due to both a full nine months of the Laser Acquisition during 2008 compared to only a five-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 31% during the three months ended September 30, 2008 compared to the comparable time period in 2007. 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 in the future.

The Laser Acquisition positively impacted the East Texas/Louisiana Segment by $4.5 million and $12.0 million during the three and nine months ended September 30, 2008, respectively, compared to $3.1 million and $5.3 million during the same time periods in the prior year. The Laser Acquisition’s daily gathering volumes for the three months ended September 30, 2008 compared to the three months ended September 30, 2007, the time period covering ownership of the Laser Acquisition, are down due to reduced drilling activity around the Belle Bower system.

Operating Expenses. Operating expenses for the three and nine months ended September 30, 2008 were $4.2 million and $11.5 million, respectively, compared to $3.6 million and $7.8 million for the three and nine months ended September 30, 2007, respectively. The major items impacting the $0.6 million and $3.7 million increases in operating expense for the three and nine months ended September 30, 2008 were (i) the additional 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 additional compression costs due to increased gathered volumes on the Tyler County Pipeline and Brookeland system, (iii) preparation costs for Hurricane Ike and Gustav and (iv) higher materials, supplies and labor costs.

Depreciation and Amortization. Depreciation and amortization expenses for the three and nine months ended September 30, 2008 were $3.0 million and $8.8 million compared to $3.3 million and $7.2 million, respectively, for the three and nine months ended September 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 nine months ended September 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 nine months ended September 30, 2008 were $2.6 million and $8.7 million, respectively, compared to $5.7 million and $24.1 million, respectively, for the three and nine months ended September 30, 2007. During the nine months ended September 30, 2008 we spent $6.4 million on growth capital of our capital spending in this segment and $2.3 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 month period of $3.1 was due to the construction of gathering lines to the significant producer discussed above, being completed, while the decrease in the nine month period of $15.4 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 September 30,				Nine Months Ended September 30,
	2008		2007(b)		2008		2007(b)
	($ in thousands, except for price data)
Revenue:
Sales of natural gas, NGLs, oil and condensate	$	114,899	$	62,792	$	343,932	$	112,676
Gathering and treating services		934		1,517		3,021		2,409
Other		—		—		2		—
Total revenue		115,833		64,309		346,955		115,085
Cost of natural gas and natural gas liquids		112,353		61,570		337,412		110,772
Operating costs and expenses:
Operating		635		394		1,862		688
Depreciation and amortization		939		910		2,812		1,289
Total operating costs and expenses		1,574		1,304		4,674		1,977
Operating income	$	1,906	$	1,435	$	4,869	$	2,336
Capital Expenditures	$	201	$	766	$	780	$	2,112

Realized average prices:
Oil and condensate (per Bbl)	$	112.20	$	71.76	$	106.54	$	69.88
Natural gas (per Mcf)	$	9.42	$	5.99	$	9.58	$	6.62
NGLs (per Bbl)	$	83.16	$	63.42	$	77.70	$	63.42

Production volumes:
Gathering volumes (Mcf/d) (a)		80,097		99,266		81,228		55,853
NGLs and condensate (net equity gallons)		571,615		162,876		1,399,183		162,876
Natural gas short position (MMbtu/d) (a)		500		500		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 is a recent area of operations for us as we entered this segment as a result of the Laser Acquisition, effective May 2007. During the three and nine months ended September 30, 2008 the South Texas Segment contributed revenues minus cost of natural gas and natural gas liquids of $3.5 million and $9.5 million, respectively, as compared to $2.7 million and $4.3 million for the three and nine months ended September 30, 2007. The increase in revenues during the three months ended September 30, 2008, were due to increased commodity prices, but volumes were down due to the impact of Hurricane Ike and reduced drilling success by producers on the Raymondville system. The increase in revenues during the nine months ended September 30, 2008 compared to the comparable period in 2007 was due to a full nine months of the Laser Acquisition as compared to only a five month period ending September 30, 2007.

There are two primary activities in this segment: (i) volumes of natural gas gathered on our own assets, which represents approximately 84% and 87% of revenues minus cost of natural gas and natural gas liquids for this segment for the three and nine months ended September 30, 2008 compared to 87% and 85% for the similar periods in 2007 and (ii) producer services, providing marketing and pipeline connection services to small independent producers and to third party pipeline systems, which accounted for approximately 16% and 13% of revenues minus cost of natural gas and natural gas liquids for the three and nine months ended September 30, 2008 as compared to 13% and 15% the same periods in 2007.

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.

Operating Expenses. Operating expenses for the three and nine months ended September 30, 2008 were $0.6 million and $1.9 million, respectively, as compared to $0.4 million and $0.7 million for the three and nine months ended September 30, 2007. Operating expenses are higher due to (i) a full nine months of the Laser Acquisition in 2008 as compared to only five months in 2007 and (ii) higher material and labor expenses when comparing the three months ended September 30, 2008 to the comparable period in 2007.

Depreciation and Amortization. Depreciation and amortization expenses for the three and nine months ended September 30, 2008 were $0.9 million and $2.8 million, respectively, as compared to $0.9 and $1.3 million for the three and nine months ended September 30, 2007.

Capital Expenditures. Capital expenditures for the three and nine months ended September 30, 2008 were $0.2 million and $0.8 million, respectively, as compared to $0.8 and $2.1 million for the three and nine months ended September 30, 2007. During the nine months ended September 30, 2008, of our capital spending in this segment, we spent $0.6 million on growth capital and $0.2 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 September 30,				Nine Months Ended September 30,
	2008(a)		2007		2008(a)		2007
	($ in thousands, except for price data)
Revenue:
Oil and condensate	$	22,694	$	9,588	$	62,153	$	9,588
Natural gas		11,168		4,375		27,725		4,375
NGLs		8,059		4,366		24,354		4,366
Sulfur		13,057		740		25,524		740
Other		428		—		608		—
Total revenue		55,406		19,069		140,364		19,069
Operating costs and expenses:
Operating		12,394		5,792		29,369		5,792
Depletion, depreciation and amortization		11,170		6,897		29,509		6,897
Total operating costs and expenses		23,564		12,689		58,878		12,689
Operating income	$	31,842	$	6,380	$	81,486	$	6,380
Capital Expenditures	$	4,532	$	—	$	17,716	$	—

Realized average prices:
Oil and condensate (per Bbl)	$	98.36	$	68.10	$	100.79	$	68.10
Natural gas (per Mcf)	$	9.05	$	6.57	$	9.41	$	6.57
NGLs (per Bbl)	$	67.35	$	49.49	$	66.58	$	49.49
Sulfur (per Long ton)	$	505.78	$	59.39	$	355.63	$	59.39

Production volumes:
Oil and condensate ( Bbl)		230,727		140,799		616,643		140,799
Natural gas (Mcf)		1,233,951		666,298		2,949,241		666,298
NGLs (Bbl)		119,664		88,228		365,761		88,228
Total (Mcfe)		3,336,297		2,040,460		8,843,665		2,040,460
Sulfur (Long ton)		25,816		12,459		71,772		12,459

__________

(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 nine months ended September 30, 2008, the Upstream Segment contributed $55.4 million and $140.4 million of revenue, respectively, which includes five months of operations related to the assets acquired in the Stanolind acquisition, as compared to $19.1 for both the three and nine month periods ending September 30, 2007.

During the three months ending September 30, 2008, production averaged 13.2 MMcfe/d, 2.5 MBO/d, 1.3 MB/d of NGL’s and 281 LT/d of sulfur. The period included three months of production from the Stanolind acquisition properties which averaged 900 BOE/d. Following the turnaround in the second quarter 2008, the Big Escambia Creek (“BEC”) treating plant operated continually during the third quarter of 2008.

During the nine month period ending September 30, 2008, revenues were negatively impacted by shut-in production at the Big Escambia Creek field associated with a 20 day planned turnaround of the BEC treating facility. In addition during the nine month period, BEC experienced 31 days and 18 days of partial curtailment associated with sulfur recovery limitations and facility damage caused by a lightning strike, respectively.

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

Historically, sulfur was viewed as a low value by-product in the production of oil and natural gas. Currently, primarily due to an increase in demand in the global fertilizer market, the price per long ton peaked at over $600 at the Tampa, Florida market (before effects of net-backs); as compared to $40 per long ton 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 9,000 long tons per month, net to us. There is no guarantee that these high prices will remain in effect in the future. As of September 30, 2008, our sulfur product is not hedged. 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 $12.4 million and $29.4 million for the Upstream Segment during the three and nine months ended September 30, 2008, as compared to $5.8 million for the three and nine month periods ending September 2007, respectively. These operating expenses include five 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, including operating expenses related to the planned turnaround at the BEC treating facility during April 2008. In addition, during the three months ended September 30, 2008, we recorded $1.4 million of expense that related to a prior period. 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 nine months ended September 30, 2008 was $11.2 million and $29.5 million, as compared to $6.9 million for the three and nine month periods ending September, 2007 respectively. The increase for the three months ended September 30, 2008 compared to the comparable period in 2007 is due to an additional month in 2008 of depletion related to our acquisition of Escambia and Redman and the depletion expense related to the assets added through the Stanolind acquisition.

Capital Expenditures. The Upstream Segment’s maintenance capital expenditures for the three and nine months ended September 30, 2008 total $4.5 million and $17.7 million, respectively. Growth capital expenditures during the three and nine months ended September 30, 2008 totaled $3.7 million and $5.7 million, respectively and were associated with drilling projects acquired in the Stanolind acquisition. The maintenance capital expenditures during the three and nine months ended September 30, 2008 were associated with the planned turnaround at the BEC treating facility, drilling, recompletions and workover activities. In addition, certain capital facility projects were conducted in each of the 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 September 30,				Nine Months Ended September 30,
	2008		2007(a)		2008		2007(a)
	($ in thousands, except for price data)
Revenue:
Oil and condensate	$	4,390	$	3,080	$	12,489	$	4,613
Natural gas		3,044		1,850		8,818		3,340
NGLs		413		527		1,059		625
Lease bonus, rentals and other		9,546		552		12,240		623
Total revenue		17,393		6,009		34,606		9,201
Operating costs and expenses:
Operating		427		221		1,352		513
Depletion		2,321		3,358		6,460		4,890
Total operating costs and expenses		2,748		3,579		7,812		5,403
Operating income	$	14,645	$	2,430	$	26,794	$	3,798

Realized average prices:
Oil and condensate (per Bbl)	$	104.62	$	64.84	$	103.47	$	64.14
Natural gas (per Mcf)	$	9.36	$	4.92	$	8.99	$	6.09
NGLs (per Bbl)	$	59.16	$	41.40	$	60.92	$	40.00

Production volumes:
Oil and condensate (Bbl)		42,004		47,498		120,744		71,908
Natural gas (Mcf)		336,060		376,389		991,534		548,600
NGLs (Bbl)		6,981		12,729		17,381		15,624
Total (Mcfe)		629,970		737,752		1,820,288		1,073,793

__________

(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 nine months ended September 30, 2008 our revenue was $17.4 million and $34.6 million, respectively, as compared to $6.0 million and $9.2 million for the three and nine months ended September 30, 2007. The increase in revenue was due to increases in commodity prices and increases in production rates during the three and nine months ended September 30, 2008, which was the result of drilling, recompletion and workover operations conducted by the various operators of the properties.

Additionally, we received approximately $9.5 million and $12.2 million in bonus and delay rental payments during the three and nine months ended September 30, 2008, respectively. Substantially all of this was derived from our ownership in the minerals. The majority of this bonus revenue ($8.5 million) was derived from new leases executed during the third quarter on our behalf by the Minerals Manager in the emerging Haynesville shale play. As a result of these leases, we now have the opportunity to receive future royalty revenues from wells drilled on approximately 75,000 gross acres in Desoto and Sabine Parishes, Louisiana and San Augustine and Sabine Counties, Texas. In addition, we made a capital contribution to Ivory Working Interest Partners who then used the funds (along with other funds contributed by the remaining partners) to purchase a working interest position in approximately 60,000 gross acres in the Haynesville shale play. We also own a mineral interest in approximately 32,000 of these acres.

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. Commodity prices may affect the amount of leasing that will occur on the minerals in future periods, and it is impossible to predict the timing or amount of future bonus payments. We do expect to receive some level of bonus payments in the future, however.

Operating Expenses. Operating expenses of $0.4 million and $1.4 million, respectively, for the three and nine months ended September 30, 2008 as compared to $0.2 million and $0.5 million for the three and nine months ended September 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 nine months ended September 30, 2008 was $2.3 million and $6.5 million, respectively, as compared to $3.4 million and $4.9 million for the three and nine months ended September 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 nine months ended September 30, 2008, as a result of the regeneration phenomenon we received an initial royalty payment for 83 and 234 new wells, respectively.

Corporate Segment

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	($ in thousands)
Revenue:
Unrealized commodity derivative gains (losses)	$	255,956		$	8,865		$	(33,381	)	$	(30,533	)
Realized commodity derivative gains (losses)		(24,105	)		(177	)		(64,388	)		4,324
Total revenue		231,851			8,688			(97,769	)		(26,209	)
General and administrative		9,893			7,196			31,161			16,587
Other operating expense		3,920			220			10,134			1,931
Depreciation and amortization		194			193			585			564
Total costs and expenses		14,007			7,609			41,880			19,082
Operating gains (losses)		217,844			1,079			(139,649	)		(45,291	)
Other income (expense):
Interest income		212			231			673			530
Other income		434			767			2,867			879
Interest expense, net		(7,498	)		(10,633	)		(23,576	)		(27,031	)
Unrealized interest rate derivatives gains (losses)		(501	)		(8,429	)		(472	)		(3,555	)
Realized interest rate derivatives gains (losses)		(2,358	)		327			(4,903	)		967
Other expense		(205	)		(415	)		(652	)		(1,545	)
Total other expense		(9,916	)		(18,152	)		(26,063	)		(29,755	)
Income (Loss) before taxes		207,928			(17,073	)		(165,712	)		(75,046	)
Income tax (benefit) provision		(494	)		352			(1,428	)		772
Segment income (loss)	$	208,422		$	(17,425	)	$	(164,284	)	$	(75,818	)

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, increased to again of $231.9 million and decreased to a loss of $97.8 million for the three and nine months ended September 30, 2008, respectively, from a gain of $8.7 million and a loss of $26.2 million for the three and nine months ended September 30, 2007, respectively. As a result of our commodity hedging activities, revenues include total realized losses of $24.1 million and $64.4 million on risk management activity that was settled during the three and nine months ended September 30, 2008, respectively, and unrealized mark-to-market gains of $256.0 million and losses of $33.4 million for the three and nine months ended September 30, 2008, respectively, as compared to realized losses of $0.2 million and gains of $4.3 million for the three and nine months ended September 30, 2007, respectively. In addition, we recorded amortization of put premiums of $2.3 million and $6.8 million during the three and nine months ended September 30, 2008, respectively, as compared to $2.0 million and $6.2 million for the three and nine months ended September 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 results during the three and nine months ended September 30, 2008 reflects forward curve price movements during the three and nine month periods for commodities underlying the derivative instruments. The unrealized mark-to-market results for the nine months ended September 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. General and administrative expenses were $9.9 million and $31.2 million for the three and nine months ended September 30, 2008, respectively, as compared to $7.2 million and $16.6 million for the three and nine months ended September 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 $2.7 million and $9.6 million for the three and nine months ended September 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 $0.2 million and $3.3 million for the three and nine months ended September 30, 2008, respectively. We also experienced lower other miscellaneous general and administrative expenses of $0.2 million for the three months ended September 30, 2008 and increased miscellaneous general and administrative expenses of $1.7 million for the nine months ended September 30, 2008. At the present time, we do not allocate our general and administrative expenses to our operational segments. The Corporate Segment bears the entire amount.

Other Operating Expenses. 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 recorded a $6.2 million bad debt charge in the second quarter 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 we recorded an additional bad debt charge of $3.9 million during the three months ended September 30, 2008. Although we sought payment of our $10.1 million receivable for condensate sales as a critical supplier to SemGroup under its Supplier Protection Program (“SPP”), we were not successful in being recognized as a critical provider by SemGroup and thus were not admitted to the SPP. As of August 1, 2008, we ceased all deliveries/sales of condensate to SemGroup.

For the three and nine months ended September 30, 2007, other operating expenses included a settlement of arbitration of $1.4 million, severance to a former executive of $0.3 million and $0.2 million for liquidated damages related to the late registration of our common units.

Total other expense. Total other expense, which includes both realized and unrealized gains and losses from our interest rate swaps, decreased to expense of $9.9 million and $26.1 million for the three and nine months ended September 30, 2008, respectively, as compared to expense of $18.2 million and $29.8 million for the three and nine months ended September 30, 2007, respectively. During the three and nine months ended September 30, 2008, we incurred realized losses from our interest rate swaps of $2.4 million and $4.9 million, respectively, as compared to realized gains of $0.3 million and $1.0 million during the three and nine months ended September 30, 2007, respectively.

We also incurred unrealized mark-to-market losses of $0.5 million and $0.5 million during the three and nine months ended September 30, 2008, respectively, as compared to unrealized mark-to-market losses of $8.4 million and $3.6 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.

Interest expense, net, decreased to $7.5 million and $23.6 million for the three and nine months ended September 30, 2008, respectively, as compared to $10.6 million and $27.0 million during the same period in the prior year, respectively. The decrease in interest expense, net, is due to the decrease in interest rates from September 30, 2007 to September 30, 2008 as well as lower interest rate margin under the new senior revolving credit facility, partially offset by higher debt balances.

In addition, other income includes our equity in earnings of the partnerships described in the Overview. During the three and nine months ended September 30, 2008, we recorded income of $2.5 million and $5.0 million, respectively. These income amounts were offset by a loss on the sale of investments of $2.1 million in one of these partnerships. As discussed in the Overview, once certain payout hurdles had been reached, our interest would revert to the Mineral Manager. During the three and nine months ended September 30, 2007, we recorded income of $0.8 million and $0.9 million, respectively, related to the equity in earnings of the partnerships.

Income Tax (Benefit) Provision. Income tax benefit recorded during the three and nine months ended September 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 $30.3 million and $104.4 million from $45.2 million and $81.4 million for the three and nine months ended September 30, 2007, respectively, to $75.5 million and $185.8 million for the three and nine months ended September 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 $15.8 million and $67.8 million during the three and nine months ended September 30, 2008, respectively, as compared to the comparable periods in 2007. The acquisitions which led to our entry into our Upstream and Mineral Segments contributed an additional $47.7 million and $146.7 million to revenues during the three and nine months ended September 30, 2008, respectively, as compared to the comparable periods in 2007. Our Corporate Segment’s realized commodity derivatives loss decreased by $23.9 million and $68.7 million during the three and nine months ended September 30, 2008, respectively, as compared to the comparable periods in 2007. This resulted in $39.6 million and $145.8 million of total incremental revenues minus cost of natural gas and natural gas liquids during the three and nine months ended September 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 $14.0 million and $39.0 million for the three and nine months ended September 30, 2008, respectively, for our Midstream Segment as compared to $13.6 million and $34.1 million to the three and nine months ended September 30, 2007, respectively, while the acquisitions which created the Upstream and Minerals Segments contributed additional Operating Expenses (including taxes other than income) of $6.8 million and $24.4 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 nine month period ending September 30, 2008 by $2.1 million and $12.0 million, respectively, as compared to the respective periods ended September 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 nine month period ending September 30, 2008, as compared to the same periods in 2007 increased by $39.6 million and $145.8 million, respectively, operating expenses increased by $7.2 million and $18.8 million, respectively, and general and administrative expenses increased by $2.1 million and $12.0 million, respectively. The increases in revenues minus the cost of natural gas and natural gas liquids, offset by increases in operating costs and general administrative expenses resulted in an increase to Adjuisted EBITDA during the three and nine months ended September 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 operations and borrowings under our existing credit facility will continue to be sufficient to meet our minimum quarterly distribution (as defined in our Partnership documents) and our requirements for short-term working capital and 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 September 30, 2008, working capital was $143.6 million as compared to a $15.1 million balance as of December 31, 2007.

The net increase in working capital of $128.5 million from December 31, 2007 to September 30, 2008, resulted primarily from the following factors:

•

risk management net working capital deficit balance increased by a net $22.5 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, increased overall by $161.1 million due to the results of operations, timing of expenditure payments, and a draw of $176.4 million under our secured revolving credit facility on September 29, 2008 in anticipation of the closing of the MMP acquisition on October 1, 2008;

•

trade accounts receivable increased by $2.5 million; and

•

accounts payable and accrued liabilities increased by $10.7 million from December 31, 2007 primarily as a result of operating activities and timing of payments, including capital expenditures.

Derivative Financial Exposure. At September 30, 2008, the fair value of our financial derivatives was a net liability of $160.7 million. Substantially all of our counterparties to these derivatives are participants in our revolving credit facility, and their outstanding debt commitments and derivative exposure are 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, as long as our derivative counterparties remain as lenders in our credit facility, we do not have exposure to potential “margin calls” on our derivative instruments. To the extent we are in an asset position, we do not have rights to collateral from our counterparties, nor do we have rights of offset against the borrowings under our revolving credit facility.

Cash Flows Nine months Ended September 30, 2008 Compared to Nine months Ended September 30, 2007

Cash Flow from Operating Activities. Cash flows provided by operating activities increased by $87.0 million during the nine months ended September 30, 2008 as compared to the nine months ended September 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 nine months ended September 30, 2008, as compared to the nine months ended September 30, 2007, decreased by $326.6 million. The investing activities for the current period reflect the Stanolind acquisition of $81.3 million compared to the Laser, Montierra, Escambia and Redman acquisitions in the prior year totaling $403.2 million and a lower 2008 capital expenditure level of $46.8 million versus $54.9 million for 2007.

Cash Flows From Financing Activities. Cash flows used in financing activities during the nine months ended September 30, 2008, decreased by $326.7 million, from the cash flows provided by financing activities of $455.2 million for the nine months ended September 30, 2007. Key differences between periods include proceeds of $331.5 from private placement of our units in 2007 offset by increased net borrowings under our revolving credit facility of

$77.0 million. Distributions to unitholders represented a cash outflow of $87.6 milliion during the nine months ended September 30, 2008, as compared to $31.8 million during the nine months ended September 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 of up to $800 million. During the three months ended September 30, 2008, we exercised $180 million of our $200 million accordion feature under the credit facility, which increased the total commitment to $980 million. In connection with exercising the accordion feature of our credit facility, we incurred debt issuance costs of $0.8 million. We exercised the accordion feature to provide for adequate funding associated with our growth strategy. As of September 30, 2008, unused capacity available to us under the new credit agreement, based on financial covenants, is approximately $175 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.

Given the current state of the banking industry worldwide, we have endeavored to diversify our lender group as much as possible. As such, after the upsizing of our credit facility as described above, our credit facility now counts with the participation of 21 financial institutions. As of today, all of our banks’ commitments, with the exception of Lehman Brothers’ commitment, remain in place and have funded in response to our borrowing notices. A Lehman Brothers subsidiary has an approximately 2.6% participation in the Partnership’s credit facility. We believe that based on the expected positive effects of the passing of the Emergency Economic Stabilization Act of 2008, and similar initiatives around the world, credit will continue to be available.

Capital Requirements.

As we expand our businesses through acquisitions and organic projects, our need for capital will increase. We anticipate that as long as the current volatility in the world’s capital markets continues we will have relatively limited access to capital to grow, our businesses aside from our existing availability under our revolving credit facility. Once stability returns and capital markets begin to function properly, we anticipate that we will again have sufficient access to capital to grow.

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, and draws from our revolving credit facility; however, we cannot provide assurances that we will be able to obtain additional capital from equity or debt issuances under terms acceptable to us.

Our original 2008 capital budget anticipated that we would spend approximately $48.3 million on our existing assets, of which $24.9 million was for growth and $23.4 million was for maintenance. This 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 and Millennium acquisitions) and the actual capital expenditures incurred during the nine months of 2008, we expect to spend a total of approximately $65.9 million for 2008 (excludes all acquisition purchase prices), of which $38.0 million will be fogrowth and $27.9 million 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, which currently has approximately $175 million in available funds.

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 constant.

Since our inception in 2002, we have made substantial growth capital expenditures. We anticipate we will continue to identify and fund growth capital expenditures from our revolving credit facility. We will evaluate future growth and acquisition projects, subject to capital markets regaining stability. 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 once capital markets regain stability, 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 September 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 on our financial statements, if any, of adopting FSP FAS 157-2.

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.

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 affects 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. 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 (non-recurring), 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 income (loss)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	($ in thousands)

Net cash flows provided by operating activities	$	40,927		$	48,479		$	163,571		$	76,598
Add (deduct):
Depreciation, depletion and amortization		(28,597	)		(25,104	)		(80,799	)		(50,883	)
Amortization of debt issuance costs		(219	)		456			(655	)		(416	)
Risk management portfolio value changes		258,716			9,422			(30,592	)		(25,102	)
Net realized (loss) gain on financing derivative settlements		(5,925	)		—			(15,462	)		100
Other		(1,344	)		(1,400	)		(1,313	)		(1,337	)
Accounts receivables and other current assets		(49,584	)		(4,398	)		(651	)		20,322
Accounts payable, due to affiliates and accrued liabilities		74,741			(18,535	)		(956	)		(53,075	)
Other assets and liabilities		(644	)		451			(420	)		(287	)
Net income (loss)		288,071			9,371			32,723			(34,080	)
Add (deduct):
Interest expense, net (1)		9,849			10,490			28,458			27,079
Depreciation, depletion and amortization		28,597			25,104			80,799			50,883
Income tax (benefit) provision		(494	)		352			(1,482	)		772
EBITDA		326,023			45,317			140,498			44,654
Add (deduct):
Risk management portfolio value changes		(255,455	)		(436	)		33,853			34,088
Restricted unit compensation expense		1,427			821			4,147			1,613
Other income		(434	)		(767	)		(2,867	)		(879	)
Other operating expenses (2)		3,920			220			10,134			1,931
ADJUSTED EBITDA	$	75,481		$	45,155		$	185,765		$	81,407

________

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

(2)

Includes the SemGroup bad debt expense of $3.9 million and $6.2 million for the three and nine months ended September 30, 2008, respectively, a settlement of arbitration for $1.4 million and severance to a former executive of $0.3 million for the nine months ended September 30, 2007 and $0.2 million for liquidated damages related to the late registration of our common units during the three and nine months ended September 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 but today these correlations have widened significantly and may or may not continue to maintain this correlation into the future.

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 September 30, 2008, the Partnership recorded a gain on risk management instruments of $231.9 million representing a fair value (unrealized) gain of $258.3 million, amortization of put premiums of $2.3 million and net (realized) settlement losses of $24.1 million. For the nine months ended September 30, 2008, the Partnership recorded a loss on risk management instruments of $97.8 million representing a fair value (unrealized) loss of $26.6 million, amortization of put premiums of $6.8 million and net (realized) settlement losses of $64.4 million. As of September 30, 2008, the fair value liability of these commodity contracts, including put premiums, totalled approximately $148.0 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 September 30, 2008, the Partnership recorded a fair value (unrealized) gain of $0.5 million and a realized loss of $2.4 million. For the nine months ended September 30, 2008, the Partnership recorded a fair value (unrealized) loss of $0.5 million and a realized loss of $4.9 million. As of September 30, 2008, the fair value liability of these interest rate contracts totaled approximately $12.7 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 principal 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.

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. The abrupt bankruptcy of SemGroup has caught us, the energy business and the financial community by surprise. We are not aware of any other measures that we could have taken to identify this risk at an earlier time. During the three and nine months ended September 30, 2008, we recorded a bad debt provision of $3.9 million and $10.1 million, respectively, related to our outstanding receivables from SemGroup. We discontinued all sales to SemGroup as of August 1, 2008, and as a result, we do not anticipate recording any additional bad debt charges in future periods.

Our derivative counterparties include BNP Paribas, Wachovia, Barclay’s, Royal Bank of Scotland, Bank of America, Wells Fargo, J Aron (an affiliate of Goldman Sachs), British Petroleum and Shell.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Management has conducted an evaluation of the effectiveness of the Partnership's 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 the Partnership's principal executive officer and principal financial officer, to ensure timely decisions regarding required disclosures. As part of the evaluation of disclosure controls and procedures conducted during the preparation of our financial statements as of December 31, 2007, which were included in our Annul Report on Form 10-K for the year ended December 31, 2007, material weaknesses in internal control over financial reporting were identified relating to our (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 directions of our principal executive officer and principal financial officer, we developed a comprehensive plan to remediate the material weaknesses, the status of which is described below.

As of September 30, 2008, and as described under Status of Remediation of Material Weakness in Internal Control Over Financial Reporting below, all of the aforementioned identified material weaknesses were not fully remediated. As a result, our principal executive officer and principal financial officer concluded that, as of September 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 the June 30, 2008 Quarterly Report on Form 10-Q, our management had 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 four 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.

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 completed its remediation efforts and deemed these material weaknesses remediated as of the filing of the June 30, 2008 Quarterly Report on Form 10-Q.

During the three months ended September 30, 2008 our Chief Financial Officer resigned. We are actively engaged in a search for a permanent replacement. Management also assessed the impact of the resignation on the Internal Control Environment and has concluded that, based on the other remediation actions completed and described above, and the oversight provided by our Interim Chief Financial Officer, the resignation did not have a material impact on the Internal Control Environment. Therefore, the material weakness related to Internal Control Environment, which was identified in our Annual Report on Form 10-K for the year ended December 31, 2007 is still remediated as of the filing of the September 30, 2008 Quarterly Report on Form 10-Q.

Un-remediated Material Weakness

Period End Financial Reporting Process

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. Management concluded that the controls are operating effectively across all segments.

Implemented and tested controls to ensure that access to open and close accounting periods is adequately restricted. Management concluded that the controls are operating effectively.

	·	Implemented and tested controls related to material and highly subjective accruals. Management concluded that the controls are operating effectively.
	·	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 are operating effectively.

Continued to implement and refine 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.

Implemented controls to detect un-posted journal entries. Testing of this control is in progress.

Management believes that the new procedures and controls discussed above will provide an appropriate remediation of this material weakness; however, the effectiveness of all of the controls has 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. This material weakness will be fully remediated when, in the opinion of management, the revised control processes have been operating for a sufficient period of time and independently validated by internal audit testing.

The remediation and ultimate resolution of this material weakness will be reviewed with the Audit Committee of our Board of Directors.

Changes in Internal Control Over Financial Reporting

During the fourth quarter of 2008, the partnership completed the acquisition of Millennium Midstream Partners, L.P., thereby acquiring control of its many subsidiary operating entities and their assets and operation which the Partnership subsequently restructured in order to integrate them into our existing structure. Because of the timing of the acquisition, management will not include the internal control processes for these entities, and their assets and operations, in its 2008 Internal Controls Assessment. Additionally, the acquisition is excluded from the certifications required under Section 302 of the Sarbanes-Oxley Act of 2002. Management will include all aspects of internal controls for this acquisition in its 2009 assessment.

Except for the changes and events described above, as of the quarter ended September 30, 2008, management has not identified any other events or changes which are reasonably likely to materially affect our internal controls over financial reporting.

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.

In June 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 a second NOE to our subsidiary 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. During the three months ended September 30, 2008, we executed an Agreed Order resolving with the TCEQ the two Notice of Enforcement matters. The administrative penalties paid by us were, in the aggregate, less than $10,000, and we consider these matters concluded at this time.

In late September 2008, the TCEQ issued another Notice of Enforcement to one of our subsidiaries, concerning the environmental compliance of our Red Deer Gas Plant (the “Site”), TCEQ ID No.: RH 0004-B (the “NOE”). The allegations in the NOE are the result of findings made by the TCEQ’s Amarillo Region Office as a result of a routine inspection of the Site. In response, our subsidiary is providing substantial documentation, some of which is corrective in nature, to the TCEQ and we are contesting certain other allegations. The TCEQ has great discretion to assess administrative penalties, in a range of $0 to $10,000 per day, and the allegations underpinning the NOE involve a time period that runs over one year. The TCEQ has not yet made a final determination with respect to whether it will assess an administrative penalty (or the amount of such penalty, if assessed).

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	Partnership Interests Purchase Agreement dated September 11, 2008, as amended, among Eagle Rock Energy Partners, L.P. and Millennium Midstream Partners, L.P.
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 Alfredo Garcia 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 Alfredo Garcia 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: November 10, 2008

EAGLE ROCK ENERGY PARTNERS, L.P.

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

partner

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

general partner

By: /s/ Alfredo Garcia

Alfredo Garcia

Senior Vice President, Corporate Development and Interim

Chief Financial Officer of Eagle Rock

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

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

Energy Partners, L.P.

EAGLE ROCK ENERGY PARTNERS, L.P.

EXHIBIT INDEX

2.1	Partnership Interests Purchase Agreement dated September 11, 2008, as amended, among Eagle Rock Energy Partners, L.P. and Millennium Midstream Partners, L.P.
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 Alfredo Garcia 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 Alfredo Garcia 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 Q3 Quarterly report

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