Eagle Rock Energy Partners L P (EROC) 10-Q 2009 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2009

OR

¨ 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 Incorporation or Organization)	(I.R.S. Employer 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  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period than the registrant was required to submit and post such files).  Yes  ¨    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  x
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  x

The issuer had 55,215,112 common units outstanding as of August 3, 2009.

EAGLE ROCK ENERGY PARTNERS, L.P.

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Unaudited Condensed Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008	2
	Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2009 and 2008	3
	Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2009 and 2008	4
	Unaudited Condensed Consolidated Statements of Members’ Equity for the six months ended June 30, 2009 and 2008	5
	Notes to the Unaudited Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	41
Item 4.	Controls and Procedures	41
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	42
Item 1A.	Risk Factors	42
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	43
Item 3.	Defaults Upon Senior Securities	43
Item 4.	Submission of Matters to a Vote of Security Holders	43
Item 5.	Other Information	43
Item 6.	Exhibits	43

1

PART 1. FINANCIAL INFORMATION

Item 1. Financial Statements.

EAGLE ROCK ENERGY PARTNERS, L.P.

 UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

($ in thousands)

	June 30, 2009			December 31, 2008
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2,062		$	17,916
Accounts receivable(1)		80,796			115,932
Risk management assets		49,277			76,769
Prepayments and other current assets		3,909			2,607
Total current assets		136,044			213,224
PROPERTY, PLANT AND EQUIPMENT — Net		1,326,066			1,357,609
INTANGIBLE ASSETS — Net		144,201			154,206
RISK MANAGEMENT ASSETS		7,183			32,451
OTHER ASSETS		19,719			15,571
TOTAL	$	1,633,213		$	1,773,061
LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	67,684		$	116,578
Due to affiliate		11,077			4,473
Accrued liabilities		13,137			19,565
Taxes payable		504			1,559
Risk management liabilities		24,756			13,763
Total current liabilities		117,158			155,938
LONG-TERM DEBT		804,383			799,383
ASSET RETIREMENT OBLIGATIONS		19,638			19,872
DEFERRED TAX LIABILITY		35,175			42,349
RISK MANAGEMENT LIABILITIES		35,045			26,182
OTHER LONG TERM LIABILITIES		270			1,622
COMMITMENTS AND CONTINGENCIES (Note 12)
MEMBERS’ EQUITY:
Common Unitholders(2)		549,398			625,590
Subordinated Unitholders(3)		77,027			105,839
General Partner(4)		(4,881	)		(3,714	)
Total members’ equity		621,544			727,715
TOTAL	$	1,633,213		$	1,773,061

(1) Net of allowable for bad debt of $12,127 as of June 30, 2009 and $12,080 as of December 31, 2008, of which $10,699 relates to SemGroup L.P. which filed for bankruptcy in July 2008.

(2) 53,244,361 and 53,043,767 units were issued and outstanding as of June 30, 2009 and December 31, 2008, respectively. These amounts do not include unvested restricted common units granted under the Partnership’s long-term incentive plan of 694,813 and 905,486 as of June 30, 2009 and December 31, 2008, respectively.

(3) 20,691,495 units were issued and outstanding as of June 30, 2009 and December 31, 2008.

(4) 844,551 units were issued and outstanding as of June 30, 2009 and December 31, 2008.

See notes to unaudited condensed consolidated financial statements.

2

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit amounts)

	Three Month Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
REVENUE:
Natural gas, natural gas liquids, oil, condensate and sulfur sales	$	153,056		$	369,715		$	304,148		$	674,689
Gathering, compression, processing and treating services		11,562			8,085			23,229			15,228
Minerals and royalty income		3,499			10,255			6,738			17,213
Commodity risk management losses		(74,561	)		(283,973	)		(48,305	)		(329,620	)
Other revenue		1,678			122			1,720			182
Total revenue		95,234			104,204			287,530			377,692
COSTS AND EXPENSES:
Cost of natural gas and natural gas liquids		115,476			272,055			241,295			496,129
Operations and maintenance (1)		19,049			17,731			37,690			33,297
Taxes other than income		2,878			5,263			5,856			9,610
General and administrative		11,895			10,026			24,433			21,268
Other operating (income) expenses		(3,552	)		6,214			(3,552	)		6,214
Impairment		—			—			242			—
Depreciation, depletion, and amortization		27,588			26,457			57,651			52,202
Total costs and expenses		173,334			337,746			363,615			618,720
OPERATING LOSS		(78,100	)		(233,542	)		(76,085	)		(241,028	)
OTHER INCOME (EXPENSE):
Interest income		141			160			173			461
Other income		550			886			1,110			2,433
Interest expense, net		(5,428	)		(6,974	)		(12,967	)		(16,078	)
Interest rate risk management gains (losses)		6,807			11,245			6,424			(2,516	)
Other expense		(267	)		(232	)		(534	)		(447	)
Total other income (expense)		1,803			5,085			(5,794	)		(16,147	)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		(76,297	)		(228,457	)		(81,879	)		(257,175	)
INCOME TAX BENEFIT		(1,477	)		(886	)		(4, 207	)		(988	)
LOSS FROM CONTINUING OPERATIONS		(74,820	)		(227,571	)		(77,672	)		(256,187	)
DISCONTINUED OPERATIONS		33			551			340			839
NET LOSS	$	(74,787	)	$	(227,020	)	$	(77,332	)	$	(255,348	)
NET INCOME (LOSS) PER COMMON UNIT — BASIC AND DILUTED:
Basic and diluted loss from continuing operations per unit:
Common units	$	(1.00	)	$	(3.15	)	$	(1.03	)	$	(3.55	)
Subordinated units	$	(1.02	)	$	(3.15	)	$	(1.08	)	$	(3.55	)
General partner units	$	(1.00	)	$	(3.15	)	$	(1.03	)	$	(3.55	)
Basic and diluted discontinued operations per unit:
Common units	$	—		$	0.01		$	—		$	0.01
Subordinated units	$	—		$	0.01		$	—		$	0.01
General partner units	$	—		$	0.01		$	—		$	0.01
Basic and diluted net loss per unit:
Common units	$	(0.99	)	$	(3.14	)	$	(1.02	)	$	(3.54	)
Subordinated units	$	(1.02	)	$	(3.14	)	$	(1.07	)	$	(3.54	)
General partner units	$	(0.99	)	$	(3.14	)	$	(1.02	)	$	(3.54	)
Basic and diluted weighted average units outstanding:
Common units		53,147			50,762			53,093			50,731
Subordinated units		20,691			20,691			20,691			20,691
General partner units		845			845			845			845

(1)   Includes costs to dispose of sulfur in our Upstream segment of $717 and $1,157 for three and six months ended June 30, 2009.

See notes to unaudited condensed consolidated financial statements.

3

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

($ in thousands)

	Six Months Ended June 30,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(77,332	)	$	(255,348	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		57,651			52,202
Impairment		242			—
Amortization of debt issuance costs		534			436
Reclassifying financing derivative settlements		(6,774	)		9,537
Distribution from unconsolidated affiliates – return on investment		247			509
Equity in earnings of unconsolidated affiliates		(927	)		(2,433	)
Equity-based compensation expense		4,120			2,718
Other operating income		(3,552	)		—
Other		(3,980	)		(825	)
Changes in assets and liabilities — net of acquisitions:
Accounts receivable		36,217			(48,032	)
Prepayments and other current assets		(1,291	)		(901	)
Risk management activities		72,613			289,308
Accounts payable		(45,266	)		65,571
Due to affiliates		6,604			4,105
Accrued liabilities		(5,173	)		6,021
Other assets and liabilities		(1,654	)		(224	)
Net cash provided by operating activities		32,279			122,644
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions, net of cash acquired		—			(81,289	)
Additions to property, plant and equipment		(25,501	)		(33,080	)
Purchase of intangible assets		(1,109	)		(1,011	)
Investment in unconsolidated affiliates		(393	)		—
Net cash used in investing activities		(27,003	)		(115,380	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of revolving credit facility		(118,000	)		(50,069	)
Proceeds from revolving credit facility		123,000			106,000
Proceeds (payments) for derivative contracts		6,774			(9,537	)
Distributions to members and affiliates		(32,904	)		(57,624	)
Net cash used in financing activities		(21,130	)		(11,230	)
NET CHANGE IN CASH AND CASH EQUIVALENTS		(15,854	)		(3,966	)
CASH AND CASH EQUIVALENTS — Beginning of period		17,916			68,552
CASH AND CASH EQUIVALENTS — End of period	$	2,062		$	64,586
SUPPLEMENTAL CASH FLOW DATA:
Interest paid — net of amounts capitalized	$	17,041		$	12,442
Cash paid for taxes	$	1,237		$	705
Investments in property, plant and equipment not paid	$	1,545		$	1,885

See notes to unaudited condensed consolidated financial statements.

4

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY

FOR THE SIX MONTH PERIOD ENDED JUNE 30, 2008

($ in thousands, except unit amounts)

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

FOR THE SIX MONTH PERIOD ENDED JUNE 30, 2009

($ in thousands, except unit amounts)

	General Partner			Number of Common Units			Common Units			Number of Subordinated Units		Subordinated Units			Total
BALANCE — December 31, 2008	$	(3,714	)		53,043,767		$	625,590			20,691,495	$	105,839		$	727,715
Net loss		(873	)		—			(55,062	)		—		(21,397	)		(77,332	)
Distributions		(337	)		—			(24,029	)		—		(8,538	)		(32,904	)
Vesting of restricted units		—			217,503			—			—		—			—
Units returned from escrow		—			(7,065	)		(25	)		—		—			(25	)
Repurchase of common units		—			(9,844	)		(30	)		—		—			(30	)
Equity based compensation		43			—			2,954			—		1,123			4,120
BALANCE — June 30, 2009	$	(4,881	)		53,244,361		$	549,398			20,691,495	$	77,027		$	621,544

See notes to unaudited condensed consolidated financial statements.

5

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 (“NGP”). On October 24, 2006, Eagle Rock Energy Partners, L.P. completed its initial public offering of common units. 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, 2008. That report contains a more comprehensive summary of the Partnership’s major accounting policies. In the opinion of management, the accompanying unaudited condensed consolidated financial statements contain all appropriate adjustments, all of which are normally recurring adjustments unless otherwise noted, considered necessary to present fairly the financial position of the Partnership and its consolidated subsidiaries and the results of operations and cash flows for the respective periods. Operating results for the three and six-month periods ended June 30, 2009 are not necessarily indicative of the results that may be expected for the year ending December 31, 2009.

 Description of Business— The Partnership is a growth-oriented limited partnership engaged in the business of (i) gathering, compressing, treating, processing and transporting and selling 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 seven 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. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates and such differences could be material.

The Partnership has provided a discussion of significant accounting policies in its annual report on Form 10-K for the year ended December 31, 2008. Certain items from that discussion are repeated or updated below as necessary to assist in understanding these financial statements.

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.

Impairment of Oil and Natural Gas Properties

 The Partnership reviews its proved properties at the field level when management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future oil and natural gas reserves that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels. If the carrying amount of an asset exceeds the sum of the undiscounted estimated future net cash flows, the Partnership recognizes impairment expense equal to the difference between the carrying value and the fair value of the asset, which is estimated to be the expected present value of discounted future net cash flows from proved reserves utilizing the Partnership’s estimated weighted average cost of capital. In connection with the preparation of these financial statements for the six months ended June 30, 2009, the Partnership recorded impairment charges of $0.2 million in its Upstream Segment as a result of continued decline in natural gas prices during the period.  These impairment charges related specifically to the three months ended March 31, 2009 and there is no additional impairment specifically for the three months ended June 30, 2009.  The Partnership did not incur any impairment charges related to its Upstream Segment’s oil and natural gas properties during the three and six months ended June 30, 2008.   The Partnership cannot predict the amount of additional impairment charges that may be recorded in the future.

Other Significant Accounting Policies

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 unaudited condensed consolidated balance sheets and marked-to-market using current market prices in effect for the reporting period of the outstanding imbalances. For the midstream business, as of June 30, 2009, the Partnership had imbalance receivables totaling $0.6 million and imbalance payables totaling $2.5 million, respectively. For the midstream business, as of December 31, 2008, the Partnership had imbalance receivables totaling $0.3 million and imbalance payables totaling $2.8 million, respectively. Changes in market value and the settlement of any such imbalance at a price greater than or less than the recorded imbalance results in either an upward or downward adjustment, as appropriate, to the cost of natural gas 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 put and call options, 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 unaudited condensed consolidated balance sheets at the instrument’s fair value, and changes in fair value are reflected in the unaudited condensed 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 amounts in prior period financial statements have been reclassified to conform to the current period presentation. The reclassification consists of an increase in revenue and operations and maintenance costs of $0.4 million from the amounts previously recognized in first quarter of fiscal 2009.  This reclassification relates to disposal costs incurred on sulfur sales which currently exceed the amount of revenue recognized for sulfur sales in fiscal 2009.  In addition, the Partnership sold its producer services business in April 2009; therefore, for the six months ended June 30, 2009, $0.3 million of revenues minus the cost of natural gas and natural gas liquids have been reported as discontinued operations, as compared to revenues minus the cost of natural gas of $0.6 million and $0.8 million, respectively, for the three and six months ended June 30, 2008.

Subsequent Events— The Partnership has evaluated all events subsequent to the balance sheet date of June 30, 2009 through the date of issuance, August 10, 2009.

6

NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS

 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.  SFAS No. 141R was effective for the Partnership as of January 1, 2009 but the impact of the adoption on the Partnership’s consolidated financial statements will depend on the nature and the extent of business combinations occurring after January 1, 2009.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of APB 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.  SFAS No. 160 was effective for the Partnership as of January 1, 2009 and did not have a material impact on its consolidated results of operations or 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.  Non-financial assets and liabilities that the Partnership measures at fair value on a non-recurring basis consists primarily of property, plant and equipment, intangible assets and asset retirement obligations, which are subject to fair value adjustments in certain circumstances (for example, when there is evidence of impairment).

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.  SFAS No. 161 was effective for the Partnership as of January 1, 2009.  See Note 11 for the additional disclosures required under FAS No. 161 related to the Partnership’s derivative instruments.

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 (“EITF 07-4”), 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.  EITF Issue No. 07-4 was effective for the Partnership as of January 1, 2009 and the impact on its earnings per unit calculation has been retrospectively applied to June 30, 2008 (see Note 16).

 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 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.  FSP SFAS No. 142-3 was effective for the Partnership as of January 1, 2009 but the impact of the adoption on the Partnership’s consolidated financial statements will depend on the nature and the extent of business combinations occurring after January 1, 2009. 

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.  FSP EITF 03-6-1 was effective for the Partnership as of January 1, 2009 and the impact on its earnings per unit calculation has been retrospectively applied to June 30, 2008. (see Note 16).

 In December 2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting to revise the existing Regulation S-K and Regulation S-X reporting requirements to align with current industry practices and technological advances. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. In addition, the new disclosure requirements require a company to (a) disclose its internal control over reserves estimation and report the independence and qualification of its reserves preparer or auditor, (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserve audit and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than period-end prices. The provisions of this final ruling will become effective for disclosures in the Partnership’s Annual Report on Form 10-K for the year ending December 31, 2009.  The adoption of the Final Rule, Modernization of Oil and Gas Reporting revision to Regulation S-K and Regulations S-X is not expected to have a material impact on the Partnership’s consolidated financial statements.  

 In April 2009, the FASB issued FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments “FSP FAS 115-2 and FAS 124-2”).  FSP FAS 115-2 and FAS 124-2 amend the other-than-temporary impairment guidance for debt securities to make the guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments in the financial statements. The most significant change is a revision to the amount of other-than-temporary loss of a debt security recorded in earnings. FSP FAS 115-2 and FAS 124-2 were effective for the Partnership as of June 30, 2009 and did not have a material impact on its consolidated financial statements.

 In April 2009, the FASB issued FSP FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (“FSP FAS 157-4”).  FSP FAS 157-4 provides additional guidance for estimating fair value in accordance with FASB Statement No. 157, Fair Value Measurements, when the volume and level of activity for the asset or liability have significantly decreased.  FSP FAS 157-4 also includes guidance on identifying circumstances that indicate a transaction is not orderly and emphasizes that even if there has been a significant decrease in the volume and level of activity for the asset or liability and regardless of the valuation technique(s) used, the objective of a fair value measurement remains the same. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction (that is, not a forced liquidation or distressed sale) between market participants at the measurement date under current market conditions.  FSP FAS 157-4 was effective for the Partnership as of June 30, 2009 and did not have a material impact on its consolidated financial statements.

 In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments (“FSP FAS 107-1 and APB 28-1”). FSP FAS 107-1 and APB 28-1 amends FASB Statement No. 107, Disclosures about Fair Value of Financial Instruments, to require disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements.  FSP FAS 107-1 and APB 28-1 also amend APB Opinion No. 28, Interim Financial Reporting, to require those disclosures in summarized financial information at interim reporting periods. FSP FAS 107-1 and APB 28-1 were effective for the Partnership as of June 30, 2009.  See Note 10 for further discussion.

In April 2009, the FASB issued FSP FAS 141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies (“FSP FAS 141(R)-1”), which amended and clarified SFAS 141R with respect to contingencies.  FSP FAS 141(R)-1 provides that an acquirer shall recognize at fair value, at the acquisition date, an asset acquired or a liability assumed in a business combination that arises from a contingency if the acquisition-date fair value of that asset or liability can be determined during the measurement period.  If the acquisition-date fair value of an asset acquired or a liability assumed in a business combination that arises from a contingency cannot be determined using the measurement period, the guidance in SFAS 5 and in FASB Interpretation No. 14, Reasonable Estimation of the Amount of a Loss, shall apply.”  FSP FAS 141(R)-1 was effective for the Partnership as of January 1, 2009 but the impact of the adoption on the Partnership’s consolidated financial statements will depend on the nature and the extent of business combinations occurring after January 1, 2009.

 On May 28, 2009, the FASB issued SFAS No. 165, Subsequent Events (“SFAS No. 165”), which provides guidance on the Partnership’s assessment of subsequent events. Historically, the Partnership has relied on U.S. auditing literature for guidance on assessing and disclosing subsequent events.  SFAS No. 165 clarifies that the Partnership must evaluate, as of each reporting period, events or transactions that occur after the balance sheet date “through the date that the financial statements are issued or are available to be issued.” The Partnership must perform its assessment for both interim and annual financial reporting periods prospectively.  SFAS No. 165 was effective for the Partnership as of June 30, 2009 but the impact of the adoption will depend on the nature and the extent of transactions that occur subsequent to our interim and annual reporting periods.

 On June 12, 2009, the FASB issued SFAS No. 166, Transfers of Financial Assets (SFAS No. 166), which amends the derecognition guidance in Statement 140.  SFAS No. 166 reflects the FASB’s response to issues entities have encountered when applying Statement 140.  In addition, SFAS 166 addresses concerns expressed by the SEC, members of the United States Congress, and financial statement users about the accounting and disclosures required by Statement 140 in the wake of the subprime mortgage crisis and the deterioration in the global credit markets.  In addition, because SFAS No. 166 eliminates the exemption from consolidation for qualified special-purpose entities (“QSPEs”) a transferor will need to evaluate all existing QSPEs to determine whether they must be consolidated.   SFAS No. 166 is effective for financial asset transfers occurring after the beginning of an entity’s first fiscal year that begins after November 15, 2009.  Early adoption of SFAS No. 166 is prohibited.   The Partnership is currently evaluating the potential impact, if any, of the adoption of SFAS No. 166 on its financial statements.

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 On June 12, 2009, the FASB issued SFAS No. 167, Amendments to FASB Interpretation 46(R), (“SFAS No. 167”), which amends the consolidation guidance applicable to variable interest entities (VIEs). The amendments will significantly affect the overall consolidation analysis under FASB Interpretation 46(R) (“FIN 46(R)”).  While the FASB’s discussions leading up to the issuance of SFAS No. 167 focused extensively on structured finance entities, the amendments to the consolidation guidance affect all entities and enterprises currently within the scope of Interpretation 46(R), as well as qualifying special-purpose entities (QSPEs) that are currently excluded from the scope of FIN 46(R).  Accordingly, an enterprise will need to carefully reconsider its previous FIN 46(R) conclusions, including (1) whether an entity is a VIE, (2) whether the enterprise is the VIE’s primary beneficiary, and (3) what type of financial statement disclosures are required.  SFAS 167 is effective as of the beginning of the first fiscal year that begins after November 15, 2009, and early adoption is prohibited.  The Partnership is currently evaluating the potential impact, if any, of the adoption of SFAS No. 167 on its financial statements.

 On June 29, 2009, the FASB issued SFAS No. 168, FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162 (“SFAS No. 168”).  The FASB has stated that “the FASB Accounting Standards Codification (“Codification”)” will become the source of authoritative U.S. GAAP recognized by the FASB to be applied to nongovernmental entities.  Once effective, the Codification’s content will carry the same level of authority, effectively superseding SFAS No. 162.  The U.S. GAAP hierarchy will be modified to include only two levels of GAAP: authoritative and nonauthoritative.  SFAS No. 168 is effective for financial statements issued for interim and annual periods ended after September 15, 2009.  The Partnership does not believe that the adoption of SFAS No. 168 will have a material impact on its financial statements.

NOTE 4. ACQUISITIONS

2008 Acquisitions

Update on Stanolind Acquisition. During the three months ended June 30, 2009, the Partnership finalized its purchase price allocations with respect to its acquisition of Stanolind Oil and Gas Corp. (“Stanolind”).  With respect to the Stanolind Acquisition, during the three months ended June 30, 2009, the Partnership decreased the amount assumed for the environmental liability by $1.3 million, reduced the deferred tax liability by $2.6 million and finalized the acquired working capital balances, which resulted in a decrease to proved properties of $2.8 million and a decrease to unproved properties of $0.5 million.

 Update on Millennium Acquisition.   With respect to the South Louisiana assets acquired in the acquisition of Millennium Midstream Partners, L.P. (“MMP”), 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 Gustav and/or Ike in August and September 2008, respectively. The North Terrebonne facility came back on-line in November 2008 and the Yscloskey facility came back on-line in January 2009.  The Partnership received a partial payment for business interruption caused by Hurricanes Gustav and Ike of approximately $1.6 million, which was recognized as other revenue during the three and six months ended June 30, 2009. The former owners of MMP provided the Partnership indemnity coverage for Hurricanes Gustav and Ike to the extent losses are not covered by insurance and established an escrow account of 1,818,182 common units and $0.6 million in cash available for the Partnership to recover against for this purpose and for settlement of the purchase price adjustment.  As of December 31, 2008, the escrow account held 1,777,302 common units and $0.3 million in cash.  During the six months ended June 30, 2009, the Partnership recovered 527,064 common units, the majority of which was on account of the purchase price adjustment, and the remaining $0.3 million in cash from the escrow account.  In addition, during the three months ended June 30, 2009, the Partnership received $0.1 million representing the distribution for the fourth quarter of 2008 that was paid into escrow on 342,609 of those units, per an arrangement with the sellers that the fourth quarter 2008 distribution on certain units cancelled as part of the purchase price adjustment should be returned to the Partnership upon cancellation.  As of June 30, 2009, the escrow account held 1,250,238 common units.

NOTE 5. FIXED ASSETS AND ASSET RETIREMENT OBLIGATIONS

Fixed assets consisted of the following:

	June 30, 2009			December 31, 2008
	($ in thousands)
Land	$	1,219		$	1,211
Plant		241,750			232,219
Gathering and pipeline		677,355			653,016
Equipment and machinery		18,856			18,672
Vehicles and transportation equipment		4,160			3,958
Office equipment, furniture, and fixtures		1,248			1,023
Computer equipment		4,965			4,714
Corporate		126			126
Linefill		4,269			4,269
Proved properties		515,801			515,452
Unproved properties		72,516			73,622
Construction in progress		20,272			39,498
		1,562,537			1,547,780
Less: accumulated depreciation, depletion and amortization		(236,471	)		(190,171	)
Net fixed assets	$	1,326,066		$	1,357,609

Depreciation expense for the three and six months ended June 30, 2009 and 2008 was approximately $12.6 million, $27.0 million, $11.2 million and $22.0 million respectively. Depletion expense for the three and six months ended June 30, 2009 and 2008 was approximately $9.2 million, $19.1 million, $10.6 million and $20.9 million respectively.  In connection with the preparation of these financial statements for the six months ended June 30, 2009, the Partnership recorded impairment charges related to its Upstream Segment proved property assets of $0.2 million relating specifically to the three months ended March 31, 2009.  The Partnership did not incur any impairment charges during the three months ended June 30, 2009 or during the three and six months ended June 30, 2008.

The Partnership capitalizes interest costs on major projects during extended construction time periods. Such interest costs are allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. During the three and six months ended June 30, 2009 and 2008, the Partnership capitalized interest costs of approximately $0.1 million, $0.1 million, $0.2 million and $0.5 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, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional upon a future event that may or may not be within the Partnership’s 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, 2008	$	19,872
Liabilities settled		(831	)
Accretion expense		597
Asset retirement obligations—June 30, 2009	$	19,638

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NOTE 6. INTANGIBLE ASSETS

Intangible Assets—Intangible assets consist of rights-of-way and easements and acquired customer contracts, which the Partnership amortizes over the term of the agreement or estimated useful life. Amortization expense was approximately $5.8 million, $11.6 million, $4.7 million and $9.3 million for the three and six months ended June 30, 2009 and 2008, respectively. Estimated aggregate amortization expense for 2009 and each of the four succeeding years is as follows: 2009—$22.9 million; 2010—$21.9 million; 2011—$11.2 million; 2012—$11.2 million; and 2013—$10.1 million. Intangible assets consisted of the following:

	June 30, 2009			December 31, 2008
	($ in thousands)
Rights-of-way and easements—at cost	$	86,645		$	85,537
Less: accumulated amortization		(13,119	)		(11,437	)
Contracts		123,409			123,409
Less: accumulated amortization		(52,734	)		(43,303	)
Net intangible assets	$	144,201		$	154,206

           The amortization period for rights-of-ways and easements is 20 years. The amortization period for contracts range from 5 to 20 years, with an average life of approximately 10 years as of June 30, 2009.

NOTE 7. LONG-TERM DEBT

As of June 30, 2009 and December 31, 2008, the Partnership had $804.4 million and $799.4 million outstanding, respectively, under its revolving credit facility.  In April 2009, due to a regularly scheduled redetermination of the Upstream Segment’s borrowing base associated with its proved reserves, the Partnership’s borrowing base was lowered to $135 million from $206 million as a result of declining commodity prices, including sulfur prices.  As of June 30, 2009, 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 $88.0 million (excluding the commitment from Lehman Brothers), based on the financialcovenants.

In a Form 8-K filing on July 23, 2009, Guaranty Financial Group Inc. stated that it is probable that it will not be able to continue as a going concern.  Guaranty Bank, a wholly owned subsidiary of Guaranty Financial Group Inc., has a commitment under the Partnership’s revolving credit facility of $30 million, of which approximately $25 million has been funded.  If Guaranty Bank ceases to be a going concern, the Partnership would likely lose access to the approximate $5 million unfunded portion of Guaranty Bank’s commitment.  This unfunded commitment may increase to the extent the Partnership reduces its borrowings under the revolving credit facility, as repayments by the Partnership under the revolving credit facility would be applied proportionately among funding lenders against their respective outstanding borrowings.  As of this filing, the Partnership has not received formal notice from Guaranty Bank or any other party as to the status of its unfunded commitment.

NOTE 8. MEMBERS’ EQUITY

At June 30, 2009, there were 53,244,361 common units (excluding unvested restricted common units), 20,691,495 subordinated units (all subordinated units owned by Holdings) and 844,551 general partner units outstanding. In addition, there were 694,813 unvested restricted common units outstanding.

Subordinated units represent limited partner interests in the Partnership, and holders of subordinated units exercise the rights and privileges available to unitholders under the limited 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 and any outstanding arrearages on the common units have been paid. 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 and any outstanding arrearages on the common units have been paid.  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, or $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 and there are no outstanding arrearages on the common units.  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, at which point all outstanding common unit arrearages would be extinguished.  For the three months ended March 31, 2009 and June 30, 2009, the Partnership did not pay the full minimum quarterly distribution amount.  The second quarter Common Unit Arrearage is $0.3375 per common unit.  The Cumulative Common Unit Arrearage is expected to increase to $0.675 per common unit with the payment of the second quarter distribution on August 14, 2009.  Both Common Unit Arrearage and Cumulative Common Unit Arrearage are terms defined in Eagle Rock Energy’s partnership agreement.

 During the three months ended June 30, 2009, the Partnership recovered and cancelled 7,065 common units that were being held in an escrow account related to its acquisition of MacLondon Energy, L.P.

 On February 4, 2009, the Partnership declared its fourth quarter 2008 cash distribution to all its unitholders (i.e. common, general and subordinated) of record as of February 10, 2009. The distribution amount was $0.41 per unit, or approximately $31.6 million. The distribution was paid on February 13, 2009.

 On April 30, 2009, the Partnership declared its first quarter 2009 cash distribution to its common unitholders of record as of May 11, 2009.  The distribution amount was $0.025 per common unit, or approximately $1.4 million.  In addition, pursuant to the terms of the Partnership’s partnership agreement, the Partnership’s general partner received a distribution of $0.025 per general partner unit.  The distribution was paid on May 15, 2009.

On July 29, 2009, the Partnership declared its second quarter 2009 cash distribution of $0.025 per unit to its general partner (as to its general partner units) and its common unitholders of record as of August 10, 2009.  The distribution will be paid August 14, 2009.

9

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 Natural Gas Partners, under which the Partnership sells a portion of its gas supply.  In July 2008, the company to which the Partnership sold its natural gas was sold by the affiliate of NGP and thus ceased being a related party.  For the three and six months ended June 30, 2008, during which such counterparty was an affiliate, the Partnership recorded revenues of $8.3 million and $16.0 million respectively.

 In addition, during the three and six months ended June 30, 2009 and 2008, the Partnership incurred $1.9 million, $4.7 million, $1.7 million, and $3.0 million, respectively, in expenses with related parties, of which there was an outstanding accounts payable balance of $0.7 million and $0.7 million, respectively, as of June 30, 2009 and December 31, 2008.

 Related to its investments in unconsolidated subsidiaries, during the three and six months ended June 30, 2009 and 2008, the Partnership recorded income of $0.4 million, $0.9 million, $0.9 million and $2.4 million, respectively, of which there was no outstanding account receivable balances as of June 30, 2009 and December 31, 2008.

 During the three and six months ended June 30, 2009, the Partnership incurred approximately $0.5 million and $0.7 million, respectively, for services performed by Stanolind Field Services (“SFS”), which is an entity controlled by NGP.  As of June 30, 2009, there were less than $0.1 million outstanding accounts payable balances.

 As of June 30, 2009 and December 31, 2008, Eagle Rock Energy G&P, LLC had $11.1 million and $4.5 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.

 The Partnership is leasing office space from Montierra Minerals & Production, L.P. (“Montierra”), which is owned by NGP and certain members of the Partnership’s senior management, including the Chief Executive Officer.  During the three and six months ended June 30, 2009, the Partnership made rental payments of less than $0.1 million and $0.1 million, respectively.  In addition, the Partnership was reimbursed by Montierra for services performed by its employees on behalf of Montierra of less than $0.1 million for both the three and six months ended June 30, 2009.  As of June 30, 2009 and December 31, 2008, the Partnership has an outstanding receivable balance of less than $0.1 million and $0.3 million, respectively, due from Montierra and an outstanding payable balance of $0.7 million due to Montierra.

 As of June 30, 2009 and December 31, 2008, the Partnership had an outstanding receivable balance of $1.9 million due from an affiliate of NGP.

NOTE 10. FAIR VALUE OF FINANCIAL INSTRUMENTS

Effective January 1, 2008, the Partnership adopted SFAS No. 157, 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 measurements) 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 June 30, 2009, the Partnership has recorded its interest rate swaps and commodity derivative instruments (see Note 11), which includes crude, 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 swaps, crude derivatives and natural gas derivatives as Level 2. Because the NGL market is considered to be less liquid and thinly traded, the Partnership has classified the inputs related to its NGL derivatives as Level 3.

10

The following table discloses the fair value of the Partnership’s derivative instruments as of June 30, 2009.

	Level 1		Level 2			Level 3			Total
	($ in thousands)
Assets:
Crude derivatives	$	—	$	42,776		$	—		$	42,776
Natural gas derivatives		—		10,318			—			10,318
NGL derivatives		—		—			1,815			1,815
Interest rate swaps		—		1,551			—			1,551
Total	$	—	$	54,645		$	1,815		$	56,460
Liabilities:
Crude derivatives	$	—	$	(32,395	)	$	—		$	(32,395	)
Natural gas derivatives		—		1,372			—			1,372
NGL derivatives		—		—			(2,335	)		(2,335	)
Interest rate swaps		—		(26,443	)		—			(26,443	)
Total	$	—	$	(57,466	)	$	(2,335	)	$	(59,801	)

 As of June 30, 2009, risk management current and long-term assets in the unaudited condensed consolidated balance sheet include put premium and other derivative costs, net of amortization, of $20.7 million and $1.7 million, respectively.

The following table sets forth a reconciliation primarily of changes in the fair value of the NGL derivatives classified as Level 3 in the fair value hierarchy during the three months ended June 30, 2009 and 2008 (in thousands):

	Three Months Ended June 30,
	2009			2008
Balances as of April 1	$	11,447		$	27,454
Settlements		(2,468	)		—
Transfers from Level 3 to Level 2		—			(4,873	)
Total gains or losses (realized and unrealized)		(9,499	)		14,275
Net liability balances as of June 30	$	(520	)	$	36,856

The following table sets forth a reconciliation primarily of changes in the fair value of the NGL derivatives classified as Level 3 in the fair value hierarchy for the six months ended June 30, 2009 and 2008 (in thousands):

	Six Months Ended June 30,
	2009			2008
Balances as of January 1	$	14,016		$	36,695
Settlements		(910	)		—
Transfers from Level 3 to Level 2		—			(10,730	)
Total gains or losses (realized and unrealized)		(13,626	)		10,891
Net liability balances as of June 30	$	(520	)	$	36,856

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

 Realized and unrealized losses related to the interest rate derivatives are recorded as part of interest rate risk management gains and losses in the unaudited condensed consolidated statements of operations.  Realized and unrealized gains and losses and the amortization of put premiums and other derivative costs related to the Partnership’s commodity derivatives are recorded as a component of revenue in the unaudited condensed consolidated statements of operations. 

 The following table discloses the fair value of the Partnership’s assets measured at fair value on a nonrecurring basis for the six months ended June 30, 2009 (in thousands):

	June 30, 2009		Level 1		Level 2		Level 3		Total Losses
Impaired proved properties	$	49	$	—	$	—	$	49	$	242

 In connection with the preparation of these financial statements for the six months ended June 30, 2009, the Partnership wrote down proved properties with a carrying value of $0.3 million to their fair value of $0.1 million, resulting in an impairment charge of $0.2 million being included in earnings for the period.  This impairment charge related specifically to the three months ended March 31, 2009.  The Partnership calculated the fair value of the impaired proved properties using its proved reserves, estimated forward prices and an estimated weighted average cost of capital.

 The carrying amount of cash equivalents is believed to approximate their fair values because of the short maturities of these instruments.  The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments.

11

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 fixed-rate interest obligations. 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 2012.  The Partnership has not designated any of its interest rate swaps 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).

 On March 30, 2009, the Partnership amended all of its existing interest rate swaps to change the interest rate the Partnership received from three month LIBOR to one month LIBOR through January 9, 2011.  During this time period, the fixed rate to be paid by the Partnership was reduced, on average, by 20 basis points.  After January 9, 2011, the interest rate to be received by the Partnership will change back to three month LIBOR and the fixed rate the Partnership pays will revert back to the original rate through the end of swap maturities in 2012.

 The table below summarizes the terms, notional amounts and rates to be paid and the fair values of the various interest swaps as of June 30, 2009:

Roll Forward Effective Date	Expiration Date	Notional Amount		Fixed Rate(a)
12/31/2008	12/31/2012	$	150,000,000		2.360% / 2.560	%
09/30/2008	12/31/2012		150,000,000		4.105% / 4.295	%
10/03/2008	12/31/2012		300,000,000		3.895% / 4.095	%

(a) First amount is the rate the Partnership pays through January 9, 2011 and the second amount is the interest rate the Partnership pays from January 10, 2011 through December 31, 2012.

 Our interest rate derivative counterparties include Wells Fargo Bank N.A. / Wachovia Bank N.A and The Royal Bank of Scotland plc.

 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.  These risks can cause significant changes in the Partnership’s cash flows and affect its ability to achieve its distribution objective and comply with the covenants of its revolving credit facility.  In order to manage the risks associated with the future prices of crude oil, natural gas and NGLs, the Partnership engages in non-speculative risk management activities that take the form of commodity derivative instruments.  The Partnership has determined that it is necessary to hedge a substantial portion of its expected production in order to meaningfully reduce its future cash flow volatility.  The Partnership recognizes that hedging 100% of its future expected production is not prudent, thus it generally limits its hedging levels to 80% of expected future production.   While hedging at this level of production does not eliminate all of the volatility in the Partnership’s cash flows, it allows the Partnership to mitigate the risk of situations where a modest loss of production would put it in an over-hedged position.  The Partnership may hedge for periods of time above the 80% of expected future production levels where it deems it prudent to reduce extreme future price volatility.  However, hedging to that level requires approval of the Board of Directors, which the Partnership has obtained for its 2009 and 2010 hedging activity.  Expected future production for its Upstream and Minerals Businesses is derived from the proved reserves, adjusted for price-dependent expenses and revenue deductions; for the Midstream Business, expected future production is based on the expected production from wells currently flowing to the Partnership’s processing plants, plus additional volumes the Partnership expects to receive from future drilling activity by its producer customer base.  The Partnership’s expectations for its Midstream Segment volumes associated with future drilling are based on information it receives from its producer customer base and  historical observations. The Partnership applies the appropriate contract terms to these projections to determine its expected future equity share of the commodities.

The Partnership uses put options, costless collars and fixed-price swaps to achieve its hedging objectives, and often hedges its expected future volumes of one commodity with derivatives of the same commodity.  In some cases, however, the Partnership believes it is better to hedge future changes in the price of one commodity with a derivative of another commodity, which it refers to as “cross-commodity” hedging.  The Partnership will often hedge the changes in future NGL prices (propane and heavier) using crude oil hedges because NGL prices have been highly correlated to crude oil prices and hedging NGLs directly is usually less attractive due to the relative illiquidity in the NGL forward market.  The Partnership will also use natural gas hedges to hedge a portion of its expected future ethane production because forward prices for ethane are often heavily discounted from its current prices.  Also, natural gas prices provide support for ethane prices because in many processing plants ethane can be recombined with the residue gas stream and sold as natural gas.  When the Partnership uses cross-commodity hedging, it will convert the expected volumes of the underlying commodity to equivalent volumes of the hedged commodity.  In the case of NGLs hedged with crude oil derivatives, these conversions are based on the linear regression of the prices of the two commodities observed during the previous 36 months and management’s judgment regarding future price relationships of the commodities.   In the case where ethane is hedged with natural gas derivatives, the conversion is based on the thermal content of ethane.

 The Partnership has a risk management policy which allows management to execute crude oil, natural gas and NGL hedging instruments in order to reduce exposure to substantial adverse changes in the prices of these commodities. The Partnership continually monitors and ensures compliance with this risk management policy through senior level executives in our operations, finance and legal departments.

The Partnership has not designated any of its commodity derivative instruments as hedges and therefore is marking these derivative contracts to fair value.  Changes in fair values of the commodity derivative instruments are recorded as an adjustment to the mark-to-market gains (losses) on risk management transactions within revenue.

Our commodity derivative counterparties include BNP Paribas, Wachovia Bank N.A, Comerica Bank, Barclays Bank PLC, Bank of Nova Scotia, Sempra Energy Trading LLC (an agent of The Royal Bank of Scotland plc), Bank of America N.A., J Aron and Company (an affiliate of Goldman Sachs), BBVA Compass Bank and Credit Suisse Energy LLC (an affiliate of Credit Suisse Group AG).

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

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 The following table, as of June 30, 2009, sets forth certain information regarding our commodity derivatives that will mature during the year ended December 31, 2009 (excluding transactions and volumes that settled or were unwound during the six months ended June 30, 2009):   

Underlying	Period	Total Notional Volumes (units)	Type	Floor Strike Price ($/unit)		Cap Strike Price ($/unit)
Natural Gas:
IF Waha	Jul-Sep 2009	60,000 mmbtu	Costless Collar	$	7.50	$	8.60
IF Waha	Oct-Dec 2009	60,000 mmbtu	Costless Collar		7.50		8.90
NYMEX Henry Hub	Jul-Dec 2009	100,000 mmbtu	Costless Collar		6.25		11.20
NYMEX Henry Hub	Jul-Dec 2009	425,000 mmbtu	Costless Collar		7.85		9.25
NYMEX Henry Hub	Jul-Dec 2009	425,000 mmbtu	Swap		8.35
NYMEX Henry Hub	Jul-Dec 2009	350,000 mmbtu	Swap		6.685
NYMEX Henry Hub	Jul-Dec 2009	350,000 mmbtu	Swap		6.885
Crude Oil:
NYMEX WTI	Jul-Dec 2009	36,000 bbls	Costless Collar		60.00		77.00
NYMEX WTI	Jul-Dec 2009	60,000 bbls	Costless Collar		93.00		100.85
NYMEX WTI	Jul-Dec 2009	30,000 bbls	Put		90.00
NYMEX WTI	Jul-Dec 2009	42,000 bbls	Put		100.00
NYMEX WTI	Jul-Dec 2009	150,000 bbls	Swap		71.25
NYMEX WTI	Jul-Dec 2009	300,000 bbls	Swap		100.00
NYMEX WTI	Jul-Dec 2009	300,000 bbls	Swap		97.00
Natural Gas Liquids:
OPIS Ethane Mt Belv non TET	Jul-Dec 2009	2,520,000 gallons	Costless Collar		0.48		0.58
OPIS Ethane Mt Belv non TET	Jul-Dec 2009	2,520,000 gallons	Swap		0.53
OPIS Ethane Mt Belv non TET	Jul-Dec 2009	6,300,000 gallons	Swap		0.6361
OPIS IsoButane Mt Belv non TET	Jul-Dec 2009	630,000 gallons	Costless Collar		0.935		1.035
OPIS IsoButane Mt Belv non TET	Jul-Dec 2009	630,000 gallons	Swap		0.985
OPIS IsoButane Mt Belv non TET	Jul-Dec 2009	746,676 gallons	Swap		1.295
OPIS NButane Mt Belv non TET	Jul-Dec 2009	1,386,000 gallons	Costless Collar		0.935		1.035
OPIS NButane Mt Belv non TET	Jul-Dec 2009	1,386,000 gallons	Swap		0.985
OPIS NButane Mt Belv non TET	Jul-Dec 2009	1,484,070 gallons	Swap		1.2775
OPIS Propane Mt Belv non TET	Jul-Dec 2009	2,646,000 gallons	Costless Collar		0.765		0.815
OPIS Propane Mt Belv non TET	Jul-Dec 2009	2,646,000 gallons	Swap		0.815
OPIS Propane Mt Belv non TET	Jul-Dec 2009	3,780,000 gallons	Swap		1.0925
OPIS Propane Mt Belv non TET	Jul-Dec 2009	1,350,846 gallons	Swap		1.0775
OPIS Propane Mt Belv non TET	Jul-Dec 2009	722,610 gallons	Swap		1.0875

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During the six months ended June 30, 2009, the Partnership entered into the following derivative transactions for the 2010 calendar year: a 125,000 MMBtu per month Henry Hub natural gas swap at $6.65 per MMBtu on January 19, 2009, a 170,000 MMBtu per month Henry Hub natural gas swap at $6.14 per MMBtu on February 17, 2009, a 45,000 barrel per month WTI crude oil swap at $53.55 per barrel on February 17, 2009 and a 40,000 barrel per month WTI crude oil swap at $51.40 per barrel on February 19, 2009.

 The following table, as of June 30, 2009, sets forth certain information regarding our commodity derivatives that will mature during the year ended December 31, 2010:

Underlying	Period	Total Notional Volumes (units)	Type	Floor Strike Price ($/unit)		Cap Strike Price ($/unit)
Natural Gas:
NYMEX Henry Hub	Jan-Dec 2010	1,320,000 mmbtu	Costless Collar	$	7.70	$	9.10
NYMEX Henry Hub	Jan-Dec 2010	1,500,000 mmbtu	Swap		6.65
NYMEX Henry Hub	Jan-Dec 2010	2,040,000 mmbtu	Swap		6.14
Crude Oil:
NYMEX WTI	Jan-Dec 2010	60,000 bbls	Costless Collar		50.00		67.50
NYMEX WTI	Jan-Dec 2010	60,000 bbls	Costless Collar		50.00		68.00
NYMEX WTI	Jan-Dec 2010	108,000 bbls	Costless Collar		90.00		99.80
NYMEX WTI	Jan-Dec 2010	180,000 bbls	Costless Collar		50.00		67.50
NYMEX WTI	Jan-Dec 2010	180,000 bbls	Costless Collar		50.00		68.00
NYMEX WTI	Jan-Dec 2010	60,000 bbls	Put		100.00
NYMEX WTI	Jan-Dec 2010	72,000 bbls	Put		90.00
NYMEX WTI	Jan-Dec 2010	120,000 bbls	Swap		78.35
NYMEX WTI	Jan-Dec 2010	300,000 bbls	Swap		70.00
NYMEX WTI	Jan-Dec 2010	540,000 bbls	Swap		53.55
NYMEX WTI	Jan-Dec 2010	480,000 bbls	Swap		51.40
Natural Gas Liquids:
OPIS Ethane Mt Belv non TET	Jan-Dec 2010	4,536,000 gallons	Costless Collar		0.43		0.53
OPIS Ethane Mt Belv non TET	Jan-Dec 2010	4,536,000 gallons	Swap		0.58
OPIS IsoButane Mt Belv non TET	Jan-Dec 2010	2,520,000 gallons	Costless Collar		0.82		1.02
OPIS IsoButane Mt Belv non TET	Jan-Dec 2010	5,544,000 gallons	Costless Collar		0.82		1.02
OPIS IsoButane Mt Belv non TET	Jan-Dec 2010	5,040,000 gallons	Costless Collar		0.705		0.81
OPIS IsoButane Mt Belv non TET	Jan-Dec 2010	5,040,000 gallons	Swap		0.755

 During the six months ended June 30, 2009, the Partnership entered into the following derivative transactions for its 2011 calendar year: a 30,000 barrel per month NYMEX WTI swap at $65.60 per barrel on March 31, 2009, a 10,000 barrel per month NYMEX WTI swap at $65.10 per barrel on April 1, 2009, a 20,000 barrel per month NYMEX WTI swap at $75.00 per barrel on June 1, 2009, a 20,000 barrel per month NYMEX WTI swap at $80.05 per barrel on June 9, 2009 and a 60,000 MMBtu per month HENRY HUB swap at $7.085 per MMBtu on June 9, 2009.

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 The following table, as of June 30, 2009, sets forth certain information regarding our commodity derivatives that will mature during the year ended December 31, 2011:

Underlying	Period	Total Notional Volumes (units)	Type	Floor Strike Price ($/unit)		Cap Strike Price ($/unit)
Natural Gas:
NYMEX Henry Hub	Jan-Dec 2011	1,200,000 mmbtu	Costless Collar	$	7.50	$	8.85
NYMEX Henry Hub	Jan-Dec 2011	720,000 mmbtu	Swap		7.085
Crude Oil:
NYMEX WTI(1)	Jan-Dec 2011	139,152 bbls	Costless Collar		75.00		85.70
NYMEX WTI(2)	Jan-Dec 2011	125,256 bbls	Swap		80.00
NYMEX WTI	Jan-Dec 2011	360,000 bbls	Swap		65.60
NYMEX WTI	Jan-Dec 2011	120,000 bbls	Swap		65.10
NYMEX WTI	Jan-Dec 2011	240,000 bbls	Swap		75.00
NYMEX WTI	Jan-Dec 2011	240,000 bbls	Swap		80.05

(1) 460,848 barrels of this costless collar were “unwound” as part of the January 8, 2009 hedge transactions.

(2) 414,744 barrels of this swap were “unwound” as part of the January 8, 2009 hedge transactions.

 During the six months ended June 30, 2009, the Partnership entered into the following derivative transactions for its 2012 calendar year: a 20,000 barrel per month NYMEX WTI swap at $68.30 per barrel on April 1, 2009, a 20,000 barrel per month NYMEX WTI swap at $76.50 per barrel on June 1, 2009 and a 20,000 barrel per month NYMEX WTI swap at $82.02 per barrel on June 9, 2009.

 The following table, as of June 30, 2009, sets forth certain information regarding our commodity derivatives that will mature during the year ended December 31, 2012:

Underlying	Period	Total Notional Volumes (units)	Type	Floor Strike Price ($/unit)		Cap Strike Price ($/unit)
Natural Gas:
NYMEX Henry Hub	Jan-Dec 2012	1,080,000 mmbtu	Costless Collar	$	7.35	$	8.65
Crude Oil:
NYMEX WTI(1)	Jan-Dec 2012	135,576 bbls	Costless Collar		75.30		86.30
NYMEX WTI(2)	Jan-Dec 2012	108,468 bbls	Swap		68.30
NYMEX WTI	Jan-Dec 2012	240,000 bbls	Swap		80.30
NYMEX WTI	Jan-Dec 2012	240,000 bbls	Swap		76.50
NYMEX WTI	Jan-Dec 2012	240,000 bbls	Swap		82.02

(1) 464,424 barrels of this costless collar were “unwound” as part of the January 8, 2009 hedge transactions.

(2) 371,532 barrels of this swap were “unwound” as part of the January 8, 2009 hedge transactions.

 On July 30, 2009, the Partnership entered into a 190,000 MMBtu per month Henry Hub natural gas swap at $6.57 per MMBtu for the 2011 calendar year and a 260,000 MMBtu per month Henry Hub natural gas swap at $6.77 per MMBtu for the 2012 calendar year. These derivative transactions are not reflected in the above tables.

15

 Fair Value of Interest Rate and Commodity Derivatives

 Fair values of interest rate and commodity derivative instruments not designated as hedging instruments under SFAS No. 133 in the unaudited condensed consolidated balance sheet as of June 30, 2009 and December 31, 2008:

	Derivative Assets								Derivative Liabilities
	June 30, 2009				December 31, 2008				June 30, 2009				December 31, 2008
	Balance Sheet  Location	Fair Value			Balance Sheet  Location	Fair Value			Balance Sheet Location	Fair Value			Balance Sheet Location	Fair Value
	($ in thousands)
Interest rate derivatives – assets	Long-term assets	$	1,551			$	—			$	—			$	—
Interest rate derivatives – liabilities			—				—		Current liabilities		(14,749	)	Current liabilities		(13,763	)
Interest rate derivatives – liabilities			—				—		Long-term liabilities		(11,694	)	Long-term liabilities		(26,182	)
Commodity derivatives – assets	Current assets		54,003		Current assets		77,603		Current liabilities		3,320				—
Commodity derivatives – assets	Long-term assets		6,025		Long-term assets		34,088		Long-term liabilities		2,498				—
Commodity derivatives – liabilities	Current assets		(4,726	)	Current assets		(834	)	Current liabilities		(13,327	)			—
Commodity derivatives – liabilities	Long-term assets		(393	)	Long-term assets		(1,637	)	Long-term liabilities		(25,849	)			—
Total derivatives		$	56,460			$	109,220			$	(59,801	)		$	(39,945	)

 The following table sets forth the location of gains and losses for derivatives not designated as hedging instruments under SFAS No. 133 within the Partnership’s Unaudited Condensed Consolidated Statement of Operations:

	Location of Gain or (Loss) Recognized in Income on Derivatives	Amount of Gain or (Loss) Recognized in Income on Derivatives
		Three Month Ended June 30,						Six Months Ended June 30,
		2009			2008			2009			2008
		($ in thousands)
Interest rate derivatives	Interest rate risk management gains (losses)	$	6,807		$	11,245		$	6,424		$	(2,516	)
Commodity derivatives	Commodity risk management losses		(74,561	)		(283,973	)		(48,305	)		(329,620	)
Total		$	(67,754	)	$	(272,728	)	$	(41,881	)	$	(332,136	)

 Our hedge counterparties are participants in our credit agreement, and the collateral for the outstanding borrowings under our credit agreement is used as collateral for our hedges.  We do not have rights to collateral from our counterparties, nor do we have rights of offset against borrowings under our credit agreement.

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NOTE 12. COMMITMENTS AND CONTINGENT LIABILITIES

 Litigation—The Partnership is subject to lawsuits which arise from time to time in the ordinary course of business, such as the interpretation and application of contractual terms related to the calculation of payment for liquids and natural gas proceeds. The Partnership’s accruals were approximately $0.1 million as of June 30, 2009 and December 31, 2008 related to these matters. The Partnership has been indemnified up to a certain dollar amount for certain lawsuits that were assumed as part of prior acquisitions. 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 the limits of the indemnification. The Partnership has not established any accruals as the likelihood of these suits being successful in amounts in excess of the indemnification limits is considered remote. These matters are not expected to have a material adverse effect on our financial position, results of operations or cash flows.

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

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

 Regulatory Compliance—In the ordinary course of business, the Partnership is subject to various laws and regulations. In the opinion of management, the Partnership is in material compliance with existing laws and regulations.

 Environmental—The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, the Partnership must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership’s combined results of operations, financial position or cash flows. At June 30, 2009 and December 31, 2008, the Partnership had accrued approximately $6.8 million and $8.6 million, respectively, for environmental matters.

 The Partnership has voluntarily undertaken a self-audit of its compliance with air quality standards, including permitting in the Texas Panhandle Segment as well as a majority of its other Midstream Business locations and some of its Upstream Business locations in Texas. This auditing has been performed pursuant to the Texas Environmental, Health and Safety Audit Privilege Act, as amended. The Partnership has completed the disclosures to the Texas Commission on Environmental Quality (“TCEQ”), and the Partnership is addressing in due course the deficiencies that it disclosed therein.  The Partnership does not foresee at this time any impediment to the timely corrective efforts identified as a result of these audits.

 Subsequent to December 31, 2008, the Partnership received additional Notices of Enforcement (“NOEs”) and a Notice of Violation (“NOV”) from the TCEQ related to air compliance matters.  The Partnership expects to receive additional NOEs or NOVs from the TCEQ from time to time throughout 2009.  Though the TCEQ has the discretion to adjust penalties and settlements upwards based on a compliance history containing multiple, successive NOEs, the Partnership does not expect that the resolution of any existing NOE or any future similar NOE will vary significantly from the administrative penalties and agreed settlements experienced by it to date.

 Retained Revenue Interest—Certain assets in 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.   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 operating leases for its corporate office, certain rights-of way, facility locations and vehicles. Rental expense, including leases with no continuing commitment, amounted to approximately, $2.2 million, $4.2 million, $1.2 million, and $2.5 million for the three and six months ended June 30, 2009 and June 30, 2008, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term.

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NOTE 13. SEGMENTS

Based on the Partnership’s approach to managing its assets, the Partnership believes its operations consist of four 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, compressing, processing and treating natural gas and marketing of natural gas, NGLs and condensate in the Texas Panhandle;

(ii) Midstream—South Texas Segment:

gathering, compressing, processing and treating natural gas and marketing of natural gas, NGLs and condensate in South Texas and West Texas;

(iii) Midstream—East Texas/Louisiana Segment:

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

(iv) Midstream—Gulf of Mexico Segment:

gathering and processing of natural gas and fractionating, transporting and marketing of NGLs in South Louisiana, Gulf of Mexico and inland waters of Texas;

(v) Upstream Segment:

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

(vi) Minerals Segment:

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

(vii) Corporate Segment:

risk management and other corporate activities.

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

Midstream Segments Three Months Ended June 30, 2009	Texas Panhandle Segment		South Texas Segment			East Texas / Louisiana Segment		Gulf of Mexico		Total Midstream Segments
($ in millions)
Sales to external customers	$	69.0	$	25.8		$	48.6	$	7.7	$	151.1
Cost of natural gas and natural gas liquids		49.4		23.7			37.2		5.2		115.5
Operating costs and other expenses		8.1		0.9			4.6		0.7		14.3
Depreciation, depletion, amortization and impairment		11.0		1.3			4.2		1.4		17.9
Operating income (loss) from continuing operations	$	0.5	$	(0.1	)	$	2.6	$	0.4	$	3.4
Capital Expenditures	$	0.7	$	0.1		$	4.8	$	—	$	5.6
Segment Assets	$	532.5	$	68.5		$	250.9	$	89.1	$	941.0

Three Months Ended June 30, 2009	Total Midstream Segments		Upstream Segment		Minerals Segment		Corporate Segment			Total Segments
($ in millions)
Sales to external customers	$	151.1	$	15.2	$	3.5	$	(74.6	)(a)	$	95.2
Cost of natural gas and natural gas liquids		115.5		—		—		—			115.5
Operating costs and other expenses		14.3		3.7		0.3		11.9			30.2
Depreciation, depletion, amortization and impairment		17.9		8.0		1.5		0.2			27.6
Operating income (loss) from continuing operations operations	$	3.4	$	3.5	$	1.7	$	(86.7	)	$	(78.1	)
Capital Expenditures	$	5.6	$	2.0	$	—	$	0.6		$	8.2
Segment Assets	$	941.0	$	379.4	$	138.6	$	174.2		$	1,633.2

Midstream Segments Three Months Ended June 30, 2008	Texas Panhandle Segment		South Texas Segment		East Texas / Louisiana Segment		Total Midstream Segments
($ in millions)
Sales to external customers	$	183.5	$	50.6	$	97.9	$	332.0
Cost of natural gas and natural gas liquids		140.3		47.9		83.9		272.1
Operating costs and other expenses		8.7		0.5		3.8		13.0
Depreciation, depletion, and amortization		10.9		0.9		3.0		14.8
Operating income from continuing operations	$	23.6	$	1.3	$	7.2	$	32.1
Capital Expenditures	$	6.5	$	0.2	$	4.0	$	10.7
Segment Assets	$	582.4	$	97.0	$	265.3	$	944.7

Three Months Ended June 30, 2008	Total Midstream Segments		Upstream Segment		Minerals Segment		Corporate Segment			Total Segments
($ in millions)
Sales to external customers	$	332.0	$	45.9	$	10.3	$	(284.0	)(a)	$	104.2
Cost of natural gas and natural gas liquids		272.1		—		—		—			272.1
Operating costs and other expenses		13.0		9.4		0.5		16.2			39.1
Depreciation, depletion, and amortization		14.8		10.0		1.5		0.2			26.5
Operating income (loss) from continuing operations operations	$	32.1	$	26.5	$	8.3	$	(300.4	)	$	(233.5	)
Capital Expenditures	$	10.7	$	10.3	$	—	$	0.1		$	21.1
Segment Assets	$	944.7	$	588.8	$	148.2	$	83.3		$	1,765.0

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

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Midstream Segments Six Months Ended June 30, 2009	Texas Panhandle Segment			South Texas Segment			East Texas / Louisiana Segment		Gulf of Mexico			Total Midstream Segments
($ in millions)
Sales to external customers	$	134.7		$	51.8		$	103.3	$	14.1		$	303.9
Cost of natural gas and natural gas liquids		101.3			47.3			82.2		10.4			241.2
Operating costs and other expenses		16.2			2.1			9.2		1.1			28.6
Depreciation, depletion, amortization and impairment		22.1			2.7			9.0		3.0			36.8
Operating income (loss) from continuing operations	$	(4.9	)	$	(0.3	)	$	2.9	$	(0.4	)	$	(2.7	)
Capital Expenditures	$	3.7		$	-		$	14.1	$	0.1		$	17.9
Segment Assets	$	532.5		$	68.5		$	250.9	$	89.1		$	941.0

Six Months Ended June 30, 2009	Total Midstream Segments			Upstream Segment			Minerals Segment		Corporate Segment			Total Segments
($ in millions)
Sales to external customers	$	303.9		$	25.3		$	6.7	$	(48.3	)(a)	$	287.6
Cost of natural gas and natural gas liquids		241.2			—			—		—			241.2
Operating costs and other expenses		28.6			10.8			0.8		24.4			64.6
Depreciation, depletion, amortization and impairment		36.8			17.6			3.1		0.4			57.9
Operating income (loss) from continuing operations operations	$	(2.7	)	$	(3.1	)	$	2.8	$	(73.1	)	$	(76.1	)
Capital Expenditures	$	17.9		$	3.6		$	—	$	1.3		$	22.8
Segment Assets	$	941.0		$	379.4		$	138.6	$	172.4		$	1,633.2

Midstream Segments Six Months Ended June 30, 2008	Texas Panhandle Segment		South Texas Segment		East Texas / Louisiana Segment		Total Midstream Segments
($ in millions)
Sales to external customers	$	339.8	$	97.0	$	168.3	$	605.1
Cost of natural gas and natural gas liquids		260.4		91.8		143.9		496.1
Operating costs and other expenses		16.5		1.2		7.3		25.0
Depreciation, depletion, and amortization		21.6		1.9		5.9		29.4
Operating income from continuing operations	$	41.3	$	2.1	$	11.2	$	54.6
Capital Expenditures	$	13.4	$	0.6	$	6.1	$	20.1
Segment Assets	$	582.4	$	97.0	$	265.3	$	944.7

Six Months Ended June 30, 2008	Total Midstream Segments		Upstream Segment		Minerals Segment		Corporate Segment			Total Segments
($ in millions)
Sales to external customers	$	605.1	$	85.0	$	17.2	$	(329.6	)(a)	$	377.7
Cost of natural gas and natural gas liquids		496.1		—		—		—			496.1
Operating costs and other expenses		25.0		17.0		0.9		27.5			70.4
Depreciation, depletion, and amortization		29.4		18.3		4.1		0.4			52.2
Operating income (loss) from continuing operations operations	$	54.6	$	49.7	$	12.2	$	(357.5	)	$	(241.0	)
Capital Expenditures	$	20.1	$	13.2	$	—	$	0.2		$	33.5
Segment Assets	$	944.7	$	588.8	$	148.2	$	83.3		$	1,765.0

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

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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 loss carryforwards of $0.4 million, $0.4 million, $0.3 million, and $0.4 million were used during the three and six months ended June 30, 2009 and 2008, respectively, which resulted in a partial release of the valuation allowance established for the net operating losses as of December 31, 2008.

Effective Rate - The effective rate for six month period ended June 30, 2009 was 5.1% compared to 0.4% for the six month period ended June 30, 2008.

Deferred Taxes - As of June 30, 2009, the net deferred tax liability was $35.2 million compared to $42.3 million as of December 31, 2008 and is primarily attributable to temporary book and tax basis differences of the entities subject to federal income taxes discussed above.  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 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.  The Company makes appropriate accruals for this tax during the reporting period.

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., has 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.  The LTIP covers an aggregate of 2,000,000 common units to be granted either as options, restricted units or phantom units.   As to outstanding restricted units, distributions associated with the restricted units will be distributed directly to the awardees. The Partnership has historically only issued restricted units under the LTIP.  No options or phantom units have been issued to date.

A summary of the LTIP restricted common units’ activity for the three months ended June 30, 2009, is provided below:

	Number of Restricted Units			Weighted Average Fair Value
Nonvested at December 31, 2008		905,486		$	17.00
Granted		72,700		$	5.67
Vested		(217,503	)	$	20.07
Forfeitures/Cancellations		(65,870	)	$	15.41
Nonvested at June 30, 2009		694,813		$	15.01

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For the three and six months ended June 30, 2009 and 2008, non-cash compensation expense of approximately $1.9 million, $3.7 million, $1.6 million and $2.7 million, respectively, was recorded related to the granted restricted units under the LTIP.

As of June 30, 2009, unrecognized compensation costs related to the outstanding restricted units under the LTIP totaled approximately $9.9 million. The remaining expense is to be recognized over a weighted average of 1.63 years.

In addition to equity awards under the LTIP involving units of the Partnership, Eagle Rock Holdings, L.P. (“Holdings”), which is controlled by NGP, in the past has from time to time granted equity in Holdings to certain employees working on behalf of the Partnership, some of which are named executive officers.  During the six month period ended June 30, 2009, Holdings granted 160,000 “Tier I” incentive interests to one Eagle Rock Energy employee.  Under the guidance of U.S. Securities and Exchange Commission Staff Accounting Bulletin Topic 1.B: “Allocation Of Expenses And Related Disclosure In Financial Statements Of Subsidiaries, Divisions Or Lesser Business Components Of Another Entity,” the Partnership recorded a portion of the value of the incentive units as compensation expense in the Partnership’s financial statements.  This allocation is based on management’s estimation of the total value of the incentive unit grant and of the grantee’s portion of time dedicated to the Partnership.  The Partnership recorded non-cash compensation expense of $0.4 million based on management’s estimates related to the Tier I incentive unit grants made by Holdings during the six months ended June 30, 2009.  No Tier I incentive unit grants were made by Holdings during the three months ended June 30, 2009.

Due to the vesting of certain restricted units during the three months ended June 30, 2009, 9,844 units were cancelled by the Partnership for less than $0.1 million as consideration for the related employee tax liability paid by the Partnership.  Pursuant to the terms of the LTIP, these cancelled units are available for future grants under the LTIP.

NOTE 16.  EARNINGS PER UNIT

Basic earnings per unit are computed by dividing the net income, or loss, by the weighted average number of units outstanding during a period. To determine net income, or 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’s weighted average number of units outstanding for a period, as compared to the weighted average number of units for all classes for the period.

 On January 1, 2009, the Partnership adopted the provisions of EITF 07-4, which provides that for master limited partnerships (“MLPs”), current period earnings be reduced by the amount of available cash that will be distributed with respect to that period for purposes of calculating earnings per unit.  Any residual amount representing undistributed earnings is assumed to be allocated to the various ownership interests in accordance with the contractual provisions of the partnership agreement.  In addition, incentive distribution rights (“IDRs”), which represent a limited partnership ownership interest, are considered to be participating securities because they have the right to participate in earnings with common equity holders.

 Under the Partnership’s partnership agreement, for any quarterly period, IDRs participate in net income only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed earnings or losses.  Accordingly, undistributed net income is assumed to be allocated to the other ownership interests on a pro-rata basis.  During the three months ended June 30, 2009 and 2008, the Partnership did not declare a quarterly distribution for the IDRs.

 On January 1, 2009, the Partnership also adopted the provisions of FSP EITF 03-6-1, which provides that share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents meets the definition of a participating security and shall be included in the computation of earnings-per-unit pursuant to the two-class method, as provided by SFAS No. 128, Earnings Per Share.  The restricted common units granted under the LTIP, as discussed in Note 15, contain non-forfeitable rights to the distributions declared by the Partnership.

After applying the provisions of EITF 07-4 and FSP EITF 03-6-1, net loss per common, subordinated and general partner unit for the three and six months ended June 30, 2008 remained at $3.14 and $3.54, respectively.  Earnings per unit has not been separately disclosed for the restricted common units, as they restricted common units are not considered a separate class of equity.

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 The following table presents the Partnership’s basic and diluted weighted average units outstanding for the periods indicated (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Common units		53,147		50,762		53,093		50,731
Subordinated units		20,691		20,691		20,691		20,691
General partner units		845		845		845		845

 The following table presents the Partnership’s basic and diluted loss per unit for the three months ended June 30, 2009:

	Total			Common Units			Restricted Common Units		Subordinated Units			General Partner Units
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(74,820	)
Distributions declared		1,368		$	1,331		$	16	$	—		$	21
Assumed loss from continuing operations after distribution to be allocated		(76,188	)		(54,218	)		—		(21,108	)		(862	)
Assumed allocation of loss from continuing operations		(74,820	)		(52,887	)		16		(21,108	)		(841	)
Discontinued operations		33			23			—		9			1
Assumed net loss to be allocated	$	(74,787	)	$	(52,864	)	$	16	$	(21,099	)	$	(840	)
Basic and diluted loss from continuing operations per unit				$	(1.00	)			$	(1.02	)	$	(1.00	)
Basic and diluted discontinued operations per unit				$	—				$	—		$	—
Basic and diluted loss per unit				$	(0.99	)			$	(1.02	)	$	(0.99	)

 The following table presents the Partnership’s basic and diluted loss per unit for the three months ended June 30, 2008:

	Total			Common Units			Restricted Common Units		Subordinated Units			General Partner Units
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(227,571	)
Distributions declared		29,949		$	20,838		$	281	$	8,484		$	346
Assumed loss from continuing operations after distribution to be allocated		(257,520	)		(180,777	)		—		(73,733	)		(3,010	)
Assumed allocation of loss from continuing operations		(227,571	)		(159,939	)		281		(65,249	)		(2,664	)
Discontinued operations		551			387			—		157			7
Assumed net loss to be allocated	$	(227,020	)	$	(159,552	)	$	281	$	(65,092	)	$	(2,657	)
Basic and diluted loss from continuing operations per unit				$	(3.15	)			$	(3.15	)	$	(3.15	)
Basic and diluted discontinued operations per unit				$	0.01				$	0.01		$	0.01
Basic and diluted loss per unit				$	(3.14	)			$	(3.14	)	$	(3.14	)

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The following table presents the Partnership’s basic and diluted loss per unit for the six months ended June 30, 2009:

	Total			Common Units			Restricted Common Units		Subordinated Units			General Partner Units
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(77,672	)
Distributions declared		2,736		$	2,657		$	37	$	—		$	42
Assumed loss from continuing operations after distribution to be allocated		(80,408	)		(57,204	)		—		(22,294	)		(910	)
Assumed allocation of loss from continuing operations		(77,672	)		(54,547	)		37		(22,294	)		(868	)
Discontinued operations		340			242			—		94			4
Assumed net loss to be allocated	$	(77,332	)	$	(54,305	)	$	37	$	(22,200	)	$	(864	)
Basic and diluted loss from continuing operations per unit				$	(1.03	)			$	(1.08	)	$	(1.03	)
Basic and diluted discontinued operations per unit				$	—				$	—		$	—
Basic and diluted loss per unit				$	(1.02	)			$	(1.07	)	$	(1.02	)

 The following table presents the Partnership’s basic and diluted loss per unit for the six months ended June 30, 2008:

	Total			Common Units			Restricted Common Units		Subordinated Units			General Partner Units
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(256,187	)
Distributions declared		59,026		$	41,118		$	464	$	16,760		$	684
Assumed loss from continuing operations after distribution to be allocated		(315,213	)		(221,318	)		—		(90,213	)		(3,682	)
Assumed allocation of loss from continuing operations		(256,187	)		(180,200	)		464		(73,453	)		(2,998	)
Discontinued operations		839			589			—		241			9
Assumed net loss to be allocated	$	(255,348	)	$	(179,611	)	$	464	$	(73,212	)	$	(2,989	)
Basic and diluted loss from continuing operations per unit				$	(3.55	)			$	(3.55	)	$	(3.55	)
Basic and diluted discontinued operations per unit				$	0.01				$	0.01		$	0.01
Basic and diluted loss per unit				$	(3.54	)			$	(3.54	)	$	(3.54	)

NOTE 17.  DISCONTINUED OPERATIONS

 On April 1, 2009, the Partnership sold its producer services business (which was accounted for in its South Texas Segment) by assigning and novating the contracts under this business to a third-party purchaser.  The Partnership sold the producer services business to a third-party purchaser as it was a low-margin business that was not core to the Partnership’s operations. The Partnership received an initial payment of $0.1 million for the sale of the business.  In addition the Partnership will receive a contingency payment of up to $0.1 million in October 2009, and it will receive a monthly payment equivalent to $0.01 per MMbtu on the volume of gas that flows pursuant to the assigned contracts for the next two years.  Producer services was a business in which the Partnership would negotiate new well connections on behalf of small producers to pipelines other than its own.  During the six months ended June 30, 2009, this business generated revenues of $26.8 million and cost of natural gas and natural gas liquids of $26.5 million.  During the three and six months ended June 30, 2008, this business generated revenues of $82.1 million and $134.1 million, respectively, and cost of natural gas and natural gas liquids of $81.5 million and $133.3 million, respectively.  For the three and six months ended June 30, 2009, less than $0.1 million and $0.3 million, respectively, of revenues minus the cost of natural gas and natural gas liquids have been reported as discontinued operations, as compared to revenues minus the cost of natural gas of $0.6 million and $0.8 million, respectively, for the three and six months ended June 30, 2008.

NOTE 18.  OTHER OPERATING (INCOME) EXPENSE

 Other operating (income) expense for the three and six months ended June 30, 2009, includes income of $3.6 million due to the recovery of $2.2 million of assets previously written off and the release of $1.4 million of liabilities assumed as part of the Partnership’s purchase price allocation for its acquisitions of Escambia Asset Co., LLC and Redman Energy Holdings, L.P.  During the period, the Partnership received additional information about collectability of these assets and determined that it no longer had any obligation under these liabilities.

 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 historically sold portions of its condensate production from its Texas Panhandle and East Texas midstream systems to SemGroup.  As a result of the bankruptcy the Partnership took a $6.2 million bad debt charge during the three months ended June 30, 2008, which is included in “Other Operating Expense” in the consolidated statement of operations.

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

The following 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, 2008, filed with the Securities and Exchange Commission. For a description of oil and natural gas terms, see our annual report.

Overview

 We are a domestically focused growth-oriented publicly traded Delaware 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 minerals and royalty interests, either through direct ownership or through investment in other partnerships.

 We report on our businesses in seven accounting segments.

 We conduct, evaluate and report on our Midstream Business within four distinct segments—the Texas Panhandle Segment, the East Texas/Louisiana Segment, the South Texas Segment and the Gulf of Mexico 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, Central Texas and Northern Louisiana. Our South Texas Segment consists of gathering systems and related compression and processing facilities in South Texas and West Texas.   Our Gulf of Mexico Segment consists of gathering and processing assets in Southern Louisiana, the Gulf of Mexico and Galveston Bay, Texas.  During the three and six months ended June 30, 2009, our Midstream Business generated operating income from continuing operations of $3.4 million and an operating loss from continuing operations of $2.7 million, respectively, compared to operating income from continuing operations of $32.1 million and $54.6 million during the three and six months ended June 30, 2008, respectively.

 We conduct, evaluate and report on our Upstream Business as one segment. Our Upstream Segment includes operated wells in Escambia County, Alabama as well as 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 West, East and South Texas in Ward, Crane, Pecos, Henderson, Rains, Van Zandt, Limestone, Freestone and Atascosa Counties, Texas.  During the three and six months ended June 30, 2009, our Upstream Business generated operating income of $3.4 million and an operating loss of $3.0 million, respectively, compared to operating income of $26.6 million and $49.6 million during the three and six months ended June 30, 2008, respectively.  Of important note, the cost of disposal of sulfur exceeded the revenue generated by $0.7 million and $1.2 million during the three and six months ended June 30, 2009, respectively, compared to revenue of $7.1 million and $12.5 million generated during the three and six months ended June 30, 2008, respectively.

 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.  During the three and six months ended June 30, 2009, our Minerals Business generated operating income of $1.7 million and $2.8 million, respectively, compared to operating income of $8.2 million and $12.1 million during the three and six months ended June 30, 2008, respectively.  Included within these numbers is lease bonus revenue of $0.4 million and $0.9 million generated during the three and six months ended June 30, 2009, respectively, compared to $1.5 million and $2.7 million during the three and six months ended June 30, 2008, respectively.

 The final segment that we report on is our Corporate Segment, in which we account for our commodity derivative/hedging activity and our corporate-level general and administrative expenses.  During the three and six months ended June 30, 2009, our Corporate Segment generated an operating loss of $86.7 million and $73.2 million, respectively, compared to an operating loss of $300.4 million and $357.5 million during the three and six months ended June 30, 2008, respectively.  Within these numbers were losses, realized and unrealized, on commodity derivatives of $74.6 million and $48.3 million during the three and six months ended June 30, 2009, respectively, compared to losses, realized and unrealized, on commodity derivatives of $284.0 million and $329.6 million during the three and six months ended June 30, 2008, respectively.

 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, operating oil and natural gas properties and assets, and managing royalties and minerals.

 We are controlled by our general partner who is controlled by its general partner (collectively “general partner”), who in turn is managed by its board of directors (the “Board of Directors”).

Impairment

 In connection with the preparation of our unaudited condensed consolidated financial statements for the three months ended March 31, 2009, we determined that we needed to record an impairment charge for certain fields within our proved properties within our Upstream Segment.  These impairment charges were necessary due to the continued decline in natural gas prices during the period.  As a result, we incurred impairment charges of $0.2 million in our Upstream Segment.  We did not incur any impairment charges during the three months ended June 30, 2009.

 Pursuant to generally accepted accounting principles in the United States, our impairment analysis does not take into account the value of our commodity derivative instruments, which generally increase as the estimates of future prices decline.  Further declines in commodity prices and other factors could result in additional impairment charges and changes to the fair value of our derivative instruments.

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 revolving credit facility, on terms acceptable to us.  See further discussion under “Liquidity and Capital Resources.”

 Below is a summary of our important acquisition transactions completed during the year ended December 31, 2008.

Stanolind Acquisition - On April 30, 2008, we completed the acquisition of all of the outstanding capital stock of Stanolind Oil and Gas Corp. (“Stanolind”).  With this acquisition, we acquired crude oil and natural gas producing properties in the Permian Basin of West Texas, primarily in Ward, Crane and Pecos Counties.

 Millennium Acquisition - On October 1, 2008, we completed the acquisition of 100% of the outstanding units of Millennium Midstream Partners, L.P. (“MMP”).  With the acquisition, we acquired natural gas gathering and processing business, with assets located in East, Central and West Texas and South Louisiana.

25

Recent Transactions

 On April 1, 2009, we sold our producer services business (which was accounted for in our South Texas Segment) by assigning and novating the contracts under this business to a third-party purchaser.  We sold the producer services business to a third-party purchaser as it was a low-margin business that was not core to our operations.   We received an initial payment of $0.1 million for the sale of the business.  In addition we will receive a contingency payment of up to $0.1 million in October, 2009 and we will receive a monthly payment equivalent to $0.01 per MMbtu on the volume of gas that flows pursuant to the assigned contracts for the next two years.  The producer services business was a low margin business in which we would negotiate new well connections on behalf of small producers to pipelines other than our own.  During the six months ended June 30, 2009, this business generated revenues of $26.8 million and cost of natural gas and natural gas liquids of $26.5 million.  During the three and six months ended June 30, 2008, this business generated revenues of $82.1 million and $134.1 million, respectively, and cost of natural gas and natural gas liquids of $81.5 million and $133.3 million, respectively.  For the three and six months ended June 30, 2009, less than $0.1 million and $0.3 million, respectively, of revenues minus the cost of natural gas and natural gas liquids have been reported as discontinued operations, as compared to revenues minus the cost of natural gas of $0.6 million and $0.8 million, respectively, for the three and six months ended June 30, 2008.

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 oil, gas, NGL and sulfur volumes; margins, operating expenses and Adjusted EBITDA (more fully described later under “Non-GAAP Financial Measures”) on a company-wide basis.

General Trends and Outlook

We expect our business to continue to be affected by the key trends as discussed in our Annual Report on Form 10-K for the year ended December 31, 2008 and that the recent events impacting the world’s economy and financial markets will play an important role in the performance and growth prospects of our business.  These recent events include but are not limited to: continued turbulence in the world’s banking system and reduced availability of credit on attractive terms; precipitous drops in the value of almost all asset classes including equity, bonds, real estate, and other investment vehicles; significant volatility in commodity prices including the prices for crude oil, natural gas, NGLs, condensate, and sulfur, among others; the significant reaction to the fall in natural gas prices by our producer customers in the Midstream Business, especially in the form of reduced drilling activity and curtailment or shutting-in of natural gas production; as well as the possibility of a prolonged period of economic recession. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about our interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

 On April 29, 2009, we announced that the borrowing base under our revolving credit facility, which relates to our Upstream Business, was redetermined down to $135 million from $206 million.  This meaningful reduction in the borrowing base occurred in connection with a regularly scheduled redetermination in accordance with our revolving credit facility and is primarily the result of the deterioration of commodity prices in the oil, natural gas and sulfur industries.  After taking into account this redetermination, we remain in compliance with the financial and other covenants in our revolving credit facility. 

 In light of the borrowing base redetermination and the deterioration of commodity prices in the oil and natural gas industry, which has led to declines in our customers’ drilling activity and hydrocarbon throughput volumes in our gathering and processing systems, as well as reduced revenues in our Upstream and Minerals businesses, the Board of Directors has determined it is prudent to create cash reserves for the proper conduct of our business and to remain in compliance with financial covenants under our revolving credit facility.  The cash not distributed to unitholders will be used primarily to reduce our outstanding debt under our revolving credit facility and to continue the execution of our hedge strategy to maintain future cash flows.  We anticipate continuing this strategy until our Board of Directors determines that our leverage ratio is at an appropriate level for the proper conduct of our business. In making this determination, we anticipate that our Board of Directors will also focus on certain aspects of our business which include, but are not limited to, improvement in commodity prices in the oil and natural gas industry, and increases in our producer customers’ drilling activity and resulting throughput volumes in our gathering and processing systems.

 On July 29, 2009, we announced that we will pay a quarterly cash distribution of $0.025 per common and general partner unit for the quarter ended June 30, 2009, which is consistent with the distribution payment for the quarter ended March 31, 2009.  This is a reduction from the $0.41 per unit distributed to all unitholders for the quarter ended December 31, 2008.  The distribution will be paid on August 14, 2009 to our general partner and common unit holders of record as of the close of business on August 10, 2009.

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. In addition, forward-looking statements speak only as of the date on which such statements are made.  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. We assume no obligation to update any forward-looking statement as of any future date.  For additional discussion of risks, uncertainties and assumptions, see our annual report on Form 10-K for the year ended December 31, 2008, filed with the Securities and Exchange Commission on March 13, 2009 as well as the risks disclosed in Part II, Item 1A below.

26

Summary of Consolidated Operating Results

 Below is a summary table of our consolidated operating results for the three and six months ended June 30, 2009 and June 30, 2008, respectively. Operating results for our individual operating segments are presented in tables in this Item 2.

	Three Month Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	($ in thousands)
REVENUE:
Natural gas, natural gas liquids, oil, condensate and sulfur sales	$	153,056		$	369,715		$	304,148		$	674,689
Gathering, compression, processing and treating services		11,562			8,085			23,229			15,228
Minerals and royalty income		3,499			10,255			6,738			17,213
Realized commodity derivative gains (losses)		22,483			(27,708	)		53,261			(40,283	)
Unrealized commodity derivative losses		(97,044	)		(256,265	)		(101,566	)		(289,337	)
Other revenue		1,678			122			1,720			182
Total revenue		95,234			104,204			287,530			377,692
COSTS AND EXPENSES:
Cost of natural gas and natural gas liquids		115,476			272,055			241,295			496,129
Operations and maintenance (b)		19,049			17,731			37,690			33,297
Taxes other than income		2,878			5,263			5,856			9,610
General and administrative		11,895			10,026			24,433			21,268
Other operating (income) expenses		(3,552	)		6,214			(3,552	)		6,214
Impairment		—			—			242			—
Depreciation, depletion, and amortization		27,588			26,457			57,651			52,202
Total costs and expenses		173,334			337,746			363,615			618,720
OPERATING LOSS		(78,100	)		(233,542	)		(76,085	)		(241,028	)
OTHER INCOME (EXPENSE):
Interest income		141			160			173			461
Other income		550			886			1,110			2,433
Interest expense, net		(5,428	)		(6,974	)		(12,967	)		(16,078	)
Realized interest rate derivative losses		(5,147	)		(2,444	)		(8,629	)		(2,545	)
Unrealized interest rate derivative gains		11,954			13,689			15,053			29
Other expense		(267	)		(232	)		(534	)		(447	)
Total other income (expense)		1,803			5,085			(5,794	)		(16,147	)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		(76,297	)		(228,457	)		(81,879	)		(257,175	)
INCOME TAX BENEFIT		(1,477	)		(886	)		(4,207	)		(988	)
LOSS FROM CONTINUING OPERATIONS		(74,820	)		(227,571	)		(77,672	)		(256,187	)
DISCONTINUED OPERATIONS		33			551			340			839
NET LOSS	$	(74,787	)	$	(227,020	)	$	(77,332	)	$	(255,348	)
ADJUSTED EBITDA (a)	$	44,666		$	56,953		$	85,771		$	109,443

(a)   See “Non-GAAP Financial Measures” and Reconciliation of ‘Adjusted EBITDA’ to net cash flows provided by operating activities and net loss within Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations for a definition and reconciliation to GAAP.

(b)   Includes costs to dispose of sulfur in our Upstream segment of $717 and $1,157 for three and six months ended June 30, 2009.

27

Midstream Business (Four Segments)

Texas Panhandle Segment

	Three Month Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	($ in thousands)
Revenues:
Natural gas, natural gas liquids, oil, and condensate sales	$	66,373		$	180,987		$	129,323		$	334,842
Gathering and treating services		2,601			2,524			5,414			4,993
Total revenues		68,974			183,511			134,737			339,835
Cost of natural gas and natural gas liquids		49,407			140,282			101,354			260,400
Operating costs and expenses:
Operations and maintenance		8,056			8,715			16,201			16,463
Depreciation and amortization		10,962			10,894			22,058			21,603
Total operating costs and expenses		19,018			19,609			38,259			38,066
Operating income (loss)	$	549		$	23,620		$	(4,876	)	$	41,369
Capital expenditures	$	766		$	6,469		$	3,709		$	13,455
Realized average prices:
Oil and condensate (per Bbl)	$	59.08		$	117.93		$	53.69		$	104.15
Natural gas (per Mcf)	$	2.66		$	9.44		$	3.06		$	8.42
NGLs (per Bbl)	$	29.82		$	74.76		$	27.26		$	68.46
Production volumes:
Gathering volumes (Mfc/d) (a)		143,281			149,881			143,740			152,225
NGLs (net equity gallons)		11,815,414			11,857,694			22,450,463			25,791,160
Condensate (net equity gallons)		9,813,579			7,793,097			16,006,005			15,743,884
Natural gas short position (MMbtu/d) (a)		(5,748	)		(4,974	)		(5,943	)		(6,112	)

(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.

Revenues and Cost of Natural Gas and Natural Gas Liquids. For the three and six months ended June 30, 2009, revenues minus cost of natural gas and natural gas liquids for our Texas Panhandle Segment operations totaled $19.6 million and $33.4 million, respectively, compared to $43.2 million and $79.4 million, respectively, for the three and six months ended June 30, 2008. There were two primary contributors to this decrease: (i) lower NGL and condensate pricing, as compared to pricing in 2008, and (ii) lower NGL equity production as compared to production in 2008.  The lower NGL equity production was primarily due to approximately 5.6% lower gathered volumes in 2009 as compared to 2008 and due to operating certain plants in ethane rejection mode for much of the first two months of 2009.  Ethane rejection operations occur when we elect to not recover the ethane component in the natural gas stream in our plants and instead choose to leave the ethane component in the residue gas stream sold at the tailgates of our plants. Ethane rejection operations result in a lower volume of equity NGLs with a correspondingly smaller natural gas short position.  We operate in this manner when the value of ethane is worth more in the gas stream than as an NGL.

The lower gathering volumes during the three and six months ended June 30, 2009 compared to the same period in the prior year were due to natural declines in the underlying existing wells in addition to reduced drilling activity during 2009.   The dramatic fall in commodity prices experienced in the latter part of 2008 and lasting into early 2009 has resulted in many of our producer customers significantly reducing drilling activity in the Texas Panhandle, presumably not to be resumed until commodity prices rise to levels which justify drilling.   While oil prices have recovered from the lows seen in the three months ended March 31, 2009, natural gas prices have continued to decline with an excess supply of natural gas experienced in many regions of the country.

 The drilling activity in the West Panhandle System is not sufficient to offset the natural declines experienced on this 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 equity production in the future on the West Panhandle System.

 The East Panhandle System experienced strong growth in volumes and equity production due to the active Granite Wash drilling play located in Roberts, Hemphill and Wheeler Counties, Texas through much of 2008; however due to lower commodity values during the fourth quarter of 2008 continuing through the first six months of 2009, we experienced a significant decline in drilling activity.

 Recent drilling by the largest operators in the Granite Wash play, utilizing horizontal drilling technologies, has resulted in initial potential (“IP”) natural gas rates of 6 MMcf per day or better.    These operators believe the economics of the Granite Wash play will be significantly enhanced due to the fewer number of wells and lower capital required to develop the same amount of acreage versus conventional vertical drilling results.   We have extensive gathering and processing facilities in Roberts and Hemphill Counties, Texas and long term acreage dedications from several of the larger producers.   We believe the Partnership will benefit in the future due to the application of this technology in the Granite Wash play with increased natural gas and condensate production in the East Panhandle System.

 The liquids content of the natural gas is lower in the East Texas Panhandle System and our contract mix provides us with a smaller share of equity production as compared to the West Panhandle System. At the current lower drilling activity in the East Panhandle System we would be unable to offset the continued decline on the West Panhandle System of NGL and condensate equity gallons.  Our current goal is to aggressively contract for new volumes in the East Panhandle System to offset the decline in volumes and our share of equity production in the West Panhandle System.

Operating Expenses. Operating expenses, including taxes other than income, for three and six months ended June 30, 2009 were $8.1 million and $16.2 million, respectively, compared to $8.7 million and $16.5 million, respectively, for the three and six months ended June 30, 2008. The $0.7 million decrease in operating expenses during the three months ended June 30, 2009, as compared to the same period in 2008, was primarily due to cost reductions across the segment.  The $0.3 million decrease in operating expenses during the six months ended June 30, 2009, as compared to the same period in 2008, was primarily due to overall cost reduction across the segment offset by an increase in  environmental compliance costs of approximately $0.3 million as compared to the same period in the prior year.

Depreciation and Amortization. Depreciation and amortization expenses for three and six months ended June 30, 2009 were $11.0 million and $22.1 million, respectively, compared to $10.9 million and $21.6 million, respectively, for the three and six months ended June 30, 2008.  The major item impacting the $0.1 million and $0.5 million increases, respectively, was depreciation expense associated with the capital expenditures placed into service during the period.

Capital Expenditures. Capital expenditures for three and six months ended June 30, 2009 were $0.8 million and $3.7 million, respectively, compared to $6.5 million and $13.5 million, respectively, for the three and six months ended June 30, 2008. 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). In the three and six months ended June 30, 2009, growth capital represented 31% and 73% of our capital expenditures as compared to 45% and 79%, respectively, in the three and six months ended June 30, 2008. The decrease in capital expenditures of $5.7 million and $9.8 million, respectively, was driven by reduced maintenance capital associated with fewer new well connects due to the lower drilling activity and by less growth capital due to expenditures related to our Stinnett – Cargray plant consolidation project having occurred in the three and six months ending June 30, 2008.

28

 East Texas/Louisiana Segment

	Three Month Ended June 30,				Six Months Ended June 30,
	2009(b)		2008		2009(b)		2008
	($ in thousands)
Revenues:
Natural gas, natural gas liquids, oil, and condensate sales	$	41,245	$	93,176	$	88,696	$	160,135
Gathering and treating services		7,375		4,700		14,584		8,148
Total revenues		48,620		97,876		103,280		168,283
Cost of natural gas and natural gas liquids		37,233		83,911		82,242		143,930
Operating costs and expenses:
Operations and maintenance		4,608		3,837		9,160		7,317
Depreciation and amortization		4,240		2,988		9,011		5,857
Total operating costs and expenses		8,848		6,825		18,171		13,174
Operating income (loss)	$	2,539	$	7,140	$	2,867	$	11,179
Capital expenditures	$	4,820	$	4,044	$	14,077	$	6,095
Realized average prices:
Oil and condensate (per Bbl)	$	60.87	$	116.33	$	56.13	$	111.37
Natural gas (per Mcf)	$	3.45	$	12.32	$	3.90	$	10.67
NGLs (per Bbl)	$	31.50	$	58.80	$	25.38	$	55.86
Production volumes:
Gathering volumes (Mfc/d) (a)		265,740		179,744		268,654		171,824
NGLs (net equity gallons)		6,166,467		6,283,355		8,842,886		11,234,078
Condensate (net equity gallons)		466,348		341,096		901,639		693,971
Natural gas short position (MMbtu/d) (a)		2,798		1,543		3,036		958

(a) Gathering volumes (Mcf/d) and natural gas long 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 Millennium Acquisition effective October 1, 2008.

Revenues and Cost of Natural Gas and Natural Gas Liquids. For the three and six months ended June 30, 2009, revenues minus cost of natural gas and natural gas liquids for our East Texas/Louisiana Segment totaled $11.4 million and $21.0 million, respectively, compared to $14.0 million and $24.4 million, respectively, for the three and six months ended June 30, 2008.  The Millennium Acquisition positively impacted the East Texas/Louisiana Segment’s revenue minus cost of natural gas and natural gas liquids by $4.0 million and $8.4 million, respectively, during the three and six months ended June 30, 2009.  Our lower NGL equity gallons for the six months ended June 30, 2009 were primarily due to operating the facilities in ethane rejection mode during much of the first two months of 2009. Ethane rejection mode is when we elect to not recover the ethane component in the natural gas stream in our plants and instead choose to leave the ethane component in the residue gas stream sold at the tailgates of our plants.  We operate in this manner when the value of ethane is worth more in the gas stream than as an NGL.

We were negatively impacted by lower NGL and condensate pricing during the three and six months ended June 30, 2009 as compared to the three and six months ended June 30, 2008. We were positively impacted by 56.4% growth in gathering volume during the six months ended June 30, 2009 compared to the six months ended June 30, 2008 due to the Millennium Acquisition while other East Texas/Louisiana Segment gathering systems realized a reduction in volumes. Excluding the Millennium Acquisition, our gathering volumes decreased by 5.6%.  The offsetting reduction in higher margin gas volumes is being replaced with lower margin, fixed fee volumes from the Millennium Acquisition.  The gas volumes from the Millennium Acquisition are primarily dry gas that does not require processing to remove NGLs prior to delivery to the interstate pipelines in order to meet the pipelines’ gas quality tariff requirements.  The lower margin gas, though contributing to a significant increase in overall gathered volumes, has not offset the lower revenues and margins due to the lower NGL, condensate and natural gas prices during the first six months of 2009 as compared to the same time period in 2008.  During the last three months of 2008 and continuing into the first six months of 2009, we saw a significant reduction in our customer’s drilling activity due to lower commodity values.

Operating Expenses. Operating expenses for the three and six months ended June 30, 2009 were $4.6 million and $9.2 million, respectively, compared to $3.8 million and $7.3 million, respectively, for the three and six months ended June 30, 2008. The major items impacting the $0.8 million and $1.8 million increases in operating expense for the three and six months, respectively, was due to expenses associated with operating the assets acquired as part of the Millennium Acquisition.  Excluding operating expenses related to the assets acquired as part of the Millennium Acquisition, operating expenses were relatively flat for the three and six months ended June 30, 2009 as compared to the same periods in 2008.

Depreciation and Amortization. Depreciation and amortization expenses for the three and six months ended June 30, 2009 were $4.2 million and $9.0 million, respectively, compared to $3.0 million and $5.9 million, respectively, for the three and six months ended June 30, 2008. The major items impacting the $1.3 million and $3.2 million increases were (i) three and six months of depreciation and amortization of the assets acquired as part of Millennium Acquisition and (ii) depreciation expense associated with the capital expenditures placed into service.These increases were offset by an adjustment of $0.9 recorded during the three and six months ended June 30, 2009 to correct an overstatement of depreciation expense in a prior period.

Capital Expenditures. Capital expenditures for the three and six months ended June 30, 2009 were $4.8 million and $14.1 million, respectively, compared to $4.0 million and $6.1 million, respectively, for the three and six months ended June 30, 2008. We classify capital expenditures as either maintenance capital (which represents routine well connects and capitalized maintenance activities) or as growth capital (which represents organic growth projects). Our increase in capital spending of $0.8 million and $8.0 million, respectively, is due primarily to the construction of gathering lines to producers in the Brookeland and Tyler County gathering systems.

29

 South Texas Segment

	Three Month Ended June 30,					Six Months Ended June 30,
	2009(b)			2008		2009(b)			2008
	($ in thousands)
Revenues:
Natural gas, natural gas liquids, oil, and condensate sales	$	24,487		$	49,740	$	48,877		$	94,934
Gathering and treating services		1,306			861		2,863			2,087
Other		—			—		3			2
Total revenues		25,793			50,601		51,743			97,023
Cost of natural gas and natural gas liquids		23,655			47,862		47,326			91,799
Operating costs and expenses:
Operations and maintenance		989			574		2,050			1,227
Depreciation and amortization		1,284			934		2,708			1,873
Total operating costs and expenses		2,273			1,508		4,758			3,100
Operating income (loss) from continuing operations		(135	)		1,231		(341	)		2,124
Discontinued operations		33			551		340			839
Operating income (loss)	$	(102	)	$	1,782	$	(1	)	$	2,963
Capital expenditures	$	75		$	218	$	15		$	579
Realized average prices:
Oil and condensate (per Bbl)	$	55.55		$	123.16	$	40.80		$	105.12
Natural gas (per Mcf)	$	3.31		$	10.88	$	3.87		$	9.67
NGLs (per Bbl)	$	29.68		$	72.66	$	27.96		$	73.08
Production volumes:
Gathering volumes (Mfc/d) (a)		90,395			84,514		93,885			81,312
NGLs (net equity gallons)		452,942			377,706		677,447			827,568
Condensate (net equity gallons)		309,186			—		956,646			—
Natural gas short position (MMbtu/d) (a)		500			500		500			500

(a) Gathering volumes (Mcf/d) and natural gas long 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 Millennium Acquisition effective October 1, 2008.

Revenues and Cost of Natural Gas and Natural Gas Liquids. During the three and six months ended June 30, 2009, the South Texas Segment contributed $2.1 million and $4.4 million, respectively, in revenues minus cost of natural gas and natural gas liquids as compared to $2.7 million and $5.2 million, respectively, for the three and six months ended June 30, 2008.  We were negatively impacted by lower NGL, natural gas and condensate pricing during the three and six months ended June 30, 2009 as compared to the same periods in 2008.   This decline was partially offset by the impact of the assets acquired as part of the Millennium Acquisition which contributed revenue minus cost of natural gas and natural gas liquids of $0.9 million and $1.7 million, respectively, during the three and six months ended June 30, 2009.

 Operating Expenses. Operating expenses for the three and six months ended June 30, 2009 were $1.0 million and $2.1 million, respectively, compared to $0.6 million and $1.2 million, respectively, for the three and six months ended June 30, 2008.  The major item impacting the $0.4 million and $0.9 million increases in operating expense, for the three and six months, respectively, was the additional expenses associated with operating the assets acquired as part of the Millennium Acquisition.

Depreciation and Amortization. Depreciation and amortization expenses for the three and six months ended June 30, 2009 were $1.3 million and $2.7 million, respectively, compared to $0.9 million and $1.9 million, respectively, for the three and six months ended June 30, 2008.  The major item impacting the $0.4 million and $0.8 million increases, for the three and six months, respectively, was the additional depreciation and amortization of the assets acquired as part of the Millennium Acquisition.

Capital Expenditures. Capital expenditures for the three and six months ended June 30, 2009 were less than $0.1 million compared to $0.2 million and $0.6 million, respectively, for the three and six months ended June 30, 2008. 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).

Discontinued Operations.  On April 1, 2009, we sold our producer services line of business and thus have classified its revenues minus cost of natural gas and natural gas liquids as discontinued operations.  During the six months ended June 30, 2009, our producer services business generated revenues of $26.8 million and cost of natural gas and natural gas liquids of $26.5 million, as compared to revenues of $134.1 million and cost of natural gas and natural gas liquids of $133.3 million during the six months ended June 30, 2008.

30

Gulf of Mexico Segment

	Three Month Ended June 30,				Six Months Ended June 30,
	2009(b)		2008		2009(b)			2008
	($ in thousands)
Revenues:
Natural gas, natural gas liquids, oil, and condensate sales	$	5,844	$	—	$	12,066		$	—
Gathering and treating services		280		—		368			—
Other revenue		1,616		—		1,616			—
Total revenues		7,740		—		14,050			—
Cost of natural gas and natural gas liquids		5,181		—		10,373			—
Operating costs and expenses:
Operations and maintenance		658		—		1,076			—
Depreciation and amortization		1,477		—		2,965			—
Total operating costs and expenses		2,135		—		4,041			—
Operating income (loss)	$	424	$	—	$	(364	)	$	—
Capital expenditures	$	—	$	—	$	141		$	—
Realized average prices:
Oil and condensate (per Bbl)	$	48.20	$	—	$	47.79		$	—
Natural gas (per Mcf)	$	3.87	$	—	$	5.11		$	—
NGLs (per Bbl)	$	29.57	$	—	$	28.76		$	—
Production volumes:
Gathering volumes (Mfc/d) (a)		98,619		—		107,559			—
NGLs (net equity gallons)		1,192,008		—		2,904,158			—

(a) Gathering volumes (Mcf/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 Millennium Acquisition starting on October 1, 2008.

 Revenues and Cost of Natural Gas and Natural Gas Liquids. We entered into this segment as a result of the Millennium Acquisition, effective October 1, 2008.During the three and six months ended June 30, 2009, the Gulf of Mexico Segment contributed $2.6 million and $3.7 million, respectively, in revenues minus cost of natural gas and natural gas liquids.  As a result of damage inflicted by Hurricanes Gustav and Ike in August 2008 and September 2008, respectively, the Yscloskey plant did not come back online until mid-January 2009 and the North Terrebonne plant did not come back online until mid-November 2008. We received a partial payment of $1.6 million, which represents approximately 90% of our claim, for business interruption caused by Hurricanes Gustav and Ike which we recognized as other revenue during the three months ended June 30, 2009.

 Operating Expenses.  Operating expenses for the three and six months ended June 30, 2009 were $0.7 million and $1.1 million, respectively.  We continued to incur operating expenses associated with the Yscloskey and North Terrebonne plants while the plants were undergoing repair for the hurricane damage.  We also incurred costs for the repair of the two plants.  Such costs were recovered from the escrow account established pursuant to the Millennium Acquisition purchase and sale agreement.  As a result and pursuant to the agreement, any insurance proceeds received for repair costs will be deposited into the escrow account.  During the six months ended June 30, 2009, we received payment from the Millennium Acquisition escrow in the amount of $0.3 million in cash and began canceling common units held in escrow to satisfy additional claims.

 Depreciation and Amortization. Depreciation and amortization expenses for the three and six months ended June 30, 2009 were $1.5 million and $3.0 million, respectively.

 Capital Expenditures.  Capital expenditures for the six month period ended June 30, 2009 for the Gulf of Mexico Segment were $0.1 million.

31

 Upstream Business (One segment)

	Three Month Ended June 30,					Six Months Ended June 30,
	2009			2008(a)		2009			2008(a)
	($ in thousands)
Revenues:
Oil and condensate sales (b)	$	8,598		$	21,126	$	14,556		$	39,459
Natural gas sales (c)		2,965			9,431		4,860			16,557
Natural gas liquids sales (d)		3,544			8,155		5,770			16,295
Sulfur sales		—			7,100		—			12,467
Other		62			122		101			180
Total revenues		15,169			45,934		25,287			84,958
Operating costs and expenses:
Operations and maintenance		6,601			9,386		13,133			16,975
Sulfur disposal costs		717			—		1,157			—
Impairment		—			—		242			—
Other operating income		(3,552	)		—		(3,552	)		—
Depreciation and amortization		7,955			9,914		17,351			18,339
Total operating costs and expenses		11,721			19,300		28,331			35,314
Operating income (loss)	$	3,448		$	26,634	$	(3,044	)	$	49,644
Capital expenditures	$	1,988		$	10,261	$	3,580		$	13,184
Realized average prices (e):
Oil and condensate (per Bbl)	$	43.20		$	114.50	$	35.69		$	102.25
Natural gas (per Mcf)	$	2.95		$	10.80	$	3.57		$	9.65
NGLs (per Bbl)	$	27.44		$	68.74	$	23.26		$	66.21
Sulfur (per Long ton)	$	—		$	359.97	$	—		$	271.28
Production volumes:
Oil and condensate (Bbl)		204,725			184,511		415,176			385,916
Natural gas (Mcf)		909,686			873,093		1,800,489			1,715,290
NGLs (Bbl)		123,057			118,644		246,836			246,097
Total (Mcfe)		2,876,376			2,692,023		5,772,558			5,507,368
Sulfur (Long ton)		39,823			19,724		68,428			45,956

(a)   Includes operations from the Stanolind Acquisition effective May 1, 2008.

(b)   Revenues include a change in the value of product imbalances of $(247) and $(260) for the three and six months ended June 30, 2009, respectively.  No changes in the value of the product imbalances were recognized during the three and six months ended June 30, 2008.

(c)   Revenues include a change in the value of product imbalances of $284 and $(1,563) for the three and six months ended June 30, 2009, respectively.  No changes in the value of the product imbalances were recognized during three and six months ended June 30, 2008.

(d)   Revenues include a change in the value of product imbalances of $167 and $28 for the three and six months ended June 30, 2009, respectively.  No changes in the value of the product imbalances were recognized during the three and six months ended June 30, 2008.

(e)   Calculation does not include impact of product imbalances.

Revenue. For the three and six months ended June 30, 2009 and 2008, the Upstream Segment contributed $15.2 million, $25.3 million, $45.9 million and $85.0 million of revenue, respectively.  The decrease in revenue was due to substantially lower realized prices for oil, natural gas, NGLs and sulfur and the non-cash mark-to-market of product imbalances, partially offset by an additional one month and four months, respectively, of operations related to the assets acquired in the Stanolind Acquisition.  During the three and six months ending June 30, 2009, production averaged 10.0 MMcf/d and 9.9 MMcf/d, respectively, 2.2 MBO/d and 2.3 MBO/d, respectively, 1.4 MB/d of NGL’s and 1.4 MB/d of NGL’s, respectively and 437 LT/d of sulfur and 378 LT/d of sulfur, respectively.  The period included three and six months of production from the assets acquired in the Stanolind Acquisition which averaged 857 Boe/d and 832 Boe/d, respectively.  During the three months ended June 30, 2009, the Big Escambia Creek (BEC) plant experienced reduced oil, residue gas and NGL sales due to unanticipated repairs and overhauls to the plant’s residue gas compressors.  Sales of residue gas and NGLs from BEC, Flomaton and Fanny Church fields were suspended for 16 days in June 2009 associated with the compressors’ downtime.  The reduced production during this period negatively impacted Upstream revenues by approximately $1.5 million.

During the three and six months ended June 30, 2009, the cost to dispose of sulfur exceeded the sales price by $0.7 million and $1.2 million, respectively, compared to revenue of $7.1 million and $12.5 million, respectively, during the three and six months ended June 30, 2008.  Historically, sulfur was viewed as a low value by-product in the production of oil and natural gas.  Due to an increase in demand in the global fertilizer market during the first nine months of 2008, the price per long ton (before effects of net-backs) peaked at over $600 at the Tampa, Florida market in September, 2008.  Deterioration in the sulfur market during the six months ended June 30, 2009 has caused the price at the Tampa, Florida market to decline to $5 per long ton, and we are incurring costs to dispose of our sulfur at this time.   We expect this to be an ongoing issue until the sulfur market returns to normal demand/supply equilibrium.

 Operating Expenses. Operating expenses, including severance and ad valorem taxes, totaled $6.6 million and $13.1 million, respectively, for the Upstream Segment during the three and six months ended June 30, 2009, as compared to $9.4 million and $17.0 million, respectively, for the three and six months ended June 30, 2008.  The operating expenses include six months of expenses related to the assets acquired in the Stanolind Acquisition during 2009 compared to only two months for the same period in 2008.  The decrease in operating expense can be attributed to lower well workover expense incurred during the three and six months ended June 30, 2009 as compared to the same period in the prior year and additional expenses being incurred during the three and six months ended June 30, 2008 due to the turnaround at the BEC treating facility in April 2008.

 Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense for the three and six months ended June 30, 2009 was $8.0 million and $17.4 million, respectively, as compared to $9.9 million and $18.3 million, respectively for the three and six month periods ended June 30, 2008, respectively.  The decrease for the six months ended June 30, 2009 compared to the comparable period in 2008 is due to the decrease in our depletable base as a result of the impairment charges we incurred during the last three months of fiscal year 2008.  This decrease was partially offset by the depletion expense related to the assets added through the Stanolind Acquisition for the first six months of 2009 compared to only two months during the same period in 2008 and the curtailed production during the six months ended June 30, 2008 due to the turnaround at the BEC treating facility in April 2008.

 Impairment.  During the six months ended June 30, 2009, we incurred impairment charges related to certain fields within our Upstream Segment of $0.2 million due to the continued decline of natural gas prices during the period.  No impairment charges were incurred during the six months ended June 30, 2008.

Other Operating Income.  Other operating income for the three and six months ended June 30, 2009, includes income of $3.6 million due to the recovery of $2.2 million of assets previously written off and the release of $1.4 million of liabilities assumed as part of our purchase price allocation for our acquisitions of Escambia Asset Co. LLC and Redman Energy Holdings, L.P.  During the period, we received additional information about collectability of these assets and determined that we no longer had any obligation under these liabilities.

Capital Expenditures.  The Upstream Segment’s maintenance capital expenditures for the three and six months ended June 30, 2009 and 2008 was $2.0 million, $3.6 million, $10.3 million and $13.2 million, respectively.  Growth capital expenditures during the three and six months ended June 30, 2009 totaled less than $0.1 million and $0.9 million, respectively, and were associated with the completion of drilling projects associated with properties acquired in the Stanolind Acquisition.  We did not incur any growth capital expenditures during the three and six months ended June 30, 2008.  The maintenance capital expenditures during the three and six months ended June 30, 2009 were associated with compressor overhauls at the BEC and Flomaton treating facilities and well completions, recompletions, workovers, equipping and leasing activities.

32

 Minerals Business (One segment)

	Three Month Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
	($ in thousands)
Revenues:
Oil and condensate sales	$	2,232	$	4,732	$	3,908	$	8,099
Natural gas sales		840		3,565		1,705		5,774
Natural gas liquids sales		69		411		198		646
Lease bonus, rentals and other		358		1,547		927		2,694
Total revenues		3,499		10,255		6,738		17,213
Operating costs and expenses:
Operations and maintenance		298		482		769		925
Depletion		1,452		1,528		3,127		4,139
Total operating costs and expenses		1,750		2,010		3,896		5,064
Operating income (loss)	$	1,749	$	8,245	$	2,842	$	12,149
Realized average prices:
Oil and condensate (per Bbl)	$	55.69	$	115.68	$	47.04	$	102.86
Natural gas (per Mcf)	$	2.90	$	10.50	$	2.93	$	8.81
NGLs (per Bbl)	$	18.83	$	66.13	$	21.13	$	62.12
Production volumes:
Oil and condensate (Bbl)		40,112		40,907		83,138		78,740
Natural gas (Mcf)		307,287		339,518		589,489		655,474
NGLs (Bbl)		3,660		6,215		9,371		10,400
Total (Mcfe)		569,919		622,250		1,144,541		1,129,400

Revenue.  For the three and six months ended June 30, 2009 our revenue was $3.5 million and $6.7 million, respectively, as compared to $10.3 million and $17.2 million for three and six months ended June 30, 2008, respectively.  The decrease in revenue was due to decreases in commodity prices and lower production volumes in the three and six months ended June 30, 2009 as compared to the three and six months ended June 30, 2008.

 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; in our minerals segment, we refer to this phenomenon as “regeneration.” 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 while we expect that regeneration will continue, we are uncertain if it will continue at rates sufficient to maintain or grow the segment’s production rate so long as commodity prices remain at their current levels. We have observed rapid and significant reductions in the active drilling rig count in virtually every producing basin of the United States, except for the Haynesville (North Louisiana and East Texas) and Marcellus (Appalachian region) shale plays. The new sources of production that we expect will materialize due to regeneration will also be the source of future extensions and discoveries and positive revisions to our reserve estimates, which may effect out future depletion rates.  During the three and six months ended June 30, 2009, as a result of regeneration we received an initial royalty payment for 62 and 135 new wells, respectively.

 Additionally, we received approximately $0.4 million and $0.9 million in bonus and delay rental payments during the three and six months ended June 30, 2009, respectively, and $1.5 million and $2.7 million in the three and six months ended June 30, 2008, respectively. Substantially all of this was derived from our ownership in the minerals. The amount of revenue we receive from bonus and rental payments varies significantly from month to month; therefore, we do not believe a meaningful set of conclusions can be drawn by observing changes in leasing activity over small time periods. 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.  However, we do expect to receive some level of bonus payments in the future.

Operating Expenses. Operating expenses of $0.3 million and $0.8 million for the three and six months ended June 30, 2009, respectively as compared to $0.5 million and $0.9 million for the three and six months ended June 30, 2008, respectively, are predominately production and ad valorem taxes. These taxes are levied by various state and local taxing entities.

 Depletion.  Our depletion during the three and six months ended June 30, 2009 was $1.5 million and $3.1 million, respectively, as compared to $1.5 million and $4.1 million for the three and six months ended June 30, 2008, respectively.  The decrease in depletion expense for the six months ended June 30, 2009, as compared to the same period in the prior year, is due to lower production and an incorrect rate being used to calculate depletion causing an overstatement of depletion during the first three months in 2008.  An adjustment of $0.7 million was recorded during the three months ended June 30, 2008 to correct this overstatement.

33

Corporate Segment

	Three Month Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	($ in thousands)
Revenues:
Unrealized commodity derivative losses	$	(97,044	)	$	(256,265	)	$	(101,566	)	$	(289,337	)
Realized commodity derivative gains (losses)		22,483			(27,708	)		53,261			(40,283	)
Total revenue		(74,561	)		(283,973	)		(48,305	)		(329,620	)
Costs and expenses:
General and administrative		11,895			10,026			24,433			21,268
Other operating expenses		—			6,214			—			6,214
Depreciation, depletion, and amortization		218			199			431			391
Total costs and expenses		12,113			16,439			24,864			27,873
Operating loss		(86,674	)		(300,412	)		(73,169	)		(357,493	)
Other income (expense):
Interest income		141			160			173			461
Other income		550			886			1,110			2,433
Interest expense, net		(5,428	)		(6,974	)		(12,967	)		(16,078	)
Realized interest rate derivative losses		(5,147	)		(2,444	)		(8,629	)		(2,545	)
Unrealized interest rate derivative gains		11,954			13,689			15,053			29
Other expense		(267	)		(232	)		(534	)		(447	)
Total other income (expense)		1,803			5,085			(5,794	)		(16,147	)
Loss before taxes		(84,871	)		(295,327	)		(78,963	)		(373,640	)
Income tax benefit		(1,477	)		(886	)		(4,207	)		(988	)
Segment loss	$	(83,394	)	$	(294,441	)	$	(74,756	)	$	(372,652	)

Revenues. The volatility inherent in commodity prices generates uncertainty around our cash flows. We attempt to counter this volatility by entering into certain derivative transactions to reduce our exposure to commodity price risk.

Our Corporate Segment’s revenues, which consist solely of our commodity derivatives activity, decreased to a loss of $74.6 million and $48.3 million, respectively, for the three and six months ended June 30, 2009, from a loss of $284.0 million and $329.6 million, respectively, for the three and six months ended June 30, 2008.  As a result of our commodity hedging activities, revenues include realized gains of $22.5 million and $53.3 million on risk management activity that was settled during the three and six months ended June 30, 2009, respectively, and unrealized mark-to-market losses of $97.0 million and $101.6 million for three and six months ended June 30, 2009, respectively, as compared to realized losses of $27.7 million and $40.3 million on risk management activity that was settled during the three and six months ended June 30, 2008, respectively, and unrealized mark-to-market net losses of $256.3 million and $289.3 million for the three and six months ended June 30, 2008, respectively.  Included with our unrealized commodity derivative gains (losses) is the amortization of put premiums and other derivative costs of $11.1 million, $23.3 million, $2.3 million and $4.6 million during the three and six months ended June 30, 2009 and 2008, respectively.

As the forward price curves for our hedged commodities shift in relation to the various strike prices of our commodity derivatives, the fair value of those instruments changes.  The unrealized, non-cash, mark-to-market results during the three and six months ended June 30, 2009 reflects forward curve price movements from the beginning to the end of the three-month and six-month period for commodities underlying the derivative instruments.  The unrealized mark-to-market results for the three and six months ended June 30, 2009 and 2008 had no impact on cash activities for those periods and 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 caps, floors, swaps and 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 on our income from operations in future periods.

General and Administrative Expenses. General and administrative expenses increased by $1.9 million and $3.1 million to $11.9 million and $24.4 million for the three and six months ended June 30, 2009, respectively, as compared to $10.0 million and $21.3 million for the three and six months ended June 30, 2009, respectively. This growth in general and administrative expenses was primarily driven by increased headcount in our corporate office as a result of our 2008 acquisitions but was also impacted by our recruiting efforts in accounting, back-office, engineering, land and operations-related corporate personnel associated with being a public partnership.  Corporate-office payroll expenses increased by $1.2 million and $4.5 million for the three and six months ended June 30, 2009, respectively, as a result of the increased headcount.  Included within the increased corporate-office payroll expenses was an increase of $0.3 million and $1.4 million for the three and six months ended June 30, 2009, respectively, related to equity-based compensation, of which the six months ended June 30, 2009 includes $0.4 million related to the allocation of expense from Eagle Rock Holdings, L.P. due to its issuance of Tier I units to one of our executives.  Also included in the six months ended June 30, 2009 was a one time charge of $0.1 million for severance payments due to a reduction in workforce.  As a result of the increase in our expenses for corporate-office headcount, contract labor and other outside professional services decreased by $0.4 million and $1.7 million during the three and six months ended June 30, 2009, respectively, as compared to the same periods in 2008.

At the present time, we do not allocate our general and administrative expenses cost to our operational segments. The Corporate Segment bears the entire amount.

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.  We historically sold to SemGroup portions of our condensate production from our Texas Panhandle and East Texas midstream systems.  As a result of the bankruptcy, we took a $6.2 million bad debt charge during the three and six months ended June 30, 2008, which is included in “Other Operating Expense” in the unaudited condensed consolidated statement of operations.

 Amounts included within other operating (income) expense are excluded from our calculation of Adjusted EBITDA.

Total Other Income (Expense). Total other income (expense) includes both realized and unrealized gains and losses from our interest rate swaps. We generated income of $1.8 million and expense of $5.8 million for the three and six months ended June 30, 2009, respectively, as compared to income of $5.1 million for the three months ended June 30, 2008 and expense of $16.1 million for the six months ended June 30, 2008.  During the three and six months ended June 30, 2009, we incurred realized losses from our interest rate swaps of $5.1 million and $8.6 million, respectively, as compared to realized losses of $2.4 million and $2.5 million during the three and six months ended June 30, 2008, respectively. We also incurred unrealized mark-to-market gains of $12.0 million and $15.1 million during the three and six months ended June 30, 2009, respectively, as compared to unrealized mark-to-market gains of $13.7 million and less than $0.1 million during the three and six months ended June 30, 2009, respectively.  These unrealized mark-to-market gains 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 $5.4 million and $13.0 million for the three and six months ended June 30, 2009, respectively, as compared to $7.0 million and $16.1 million during the three and six months ended June 30, 2008, respectively.  Interest expense, net is shown before the impact of our interest rate derivatives, which convert a portion of our outstanding debt from variable-rate interest obligations to fixed-rate interest obligations.  All of our outstanding debt consists of borrowings under our revolving credit facility, which bears interest primarily based on a LIBOR rate plus the applicable margin.  The decrease in interest expense, net is due to lower LIBOR rates during the three months ended June 30, 2009 as compared to the three months ended June 30, 2008, partially offset by higher debt balances in the 2009 period as a result of our acquisition made in 2008.

Income Tax Benefit. Income tax benefit recorded during the three months ended June 30, 2009 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 acquisition of Redman Energy Corporation in 2007 and Stanolind Oil and Gas Corp. in 2008.

34

Adjusted EBITDA

Adjusted EBITDA, as defined under “Non-GAAP Financial Measures,” decreased by $12.3 million and $23.7 million from $57.0 million and $109.4 million for the three and six months ended June 30, 2008, respectively, to $44.7 million and $85.8 million for the three and six months ended June 30, 2009, respectively.

           As described above, for the three and six months ended June 30, 2009, revenues minus cost of natural gas and natural gas liquids for the Midstream Segment (including the Texas Panhandle, East Texas/Louisiana, South Texas and the Gulf of Mexico Segment) declined by $24.3 million and $46.5 million as compared to the three and six months ended June 30, 2008. For the three and six months ended June 30, 2009, revenues for our Upstream and Mineral Segments declined by $37.7 million and $68.8 million, respectively, as compared to the same period in the prior year.  Our Corporate Segment’s realized commodity derivatives gain increased by $50.2 million and $93.5 million as compared to the three and six months ended June 30, 2008, respectively. This resulted in a decline of $11.8 million and $21.7 million of total incremental revenues minus cost of natural gas and natural gas liquids, adjusted to exclude the impact of unrealized commodity derivatives not included in the calculation of Adjusted EBITDA, as compared to the three and six months ended June 30, 2008.

Operating expenses (including taxes other than income), increased by $1.2 million and $3.5 million for our Midstream Segment with respect to the three and six months ended June 30, 2009, respectively, primarily due to the addition of the Millennium Midstream acquisition properties, while operating expenses for our Upstream and Minerals Segments decreased by $2.3 million and $3.3 million, as compared to the three and six months ended June 30, 2008, respectively.

General and administrative expense, captured in the Corporate Segment, increased by $1.5 million and $1.8 million adjusted to exclude non-cash compensation charges related to our LTIP program and other operating expenses.

As a result, revenues (excluding the impact of unrealized commodity derivative activity and non-cash mark-to-market of Upstream product imbalances) minus cost of natural gas and natural gas liquids decreased by $11.8 million and $21.7 million, operating expenses decreased by $1.1 million and increased by $0.2 million and general and administrative expenses decreased by $1.5 million and $1.8 million, resulting in the decrease to Adjusted EBITDA during the three and six months ended June 30, 2009, as compared to the three and six months ended June 30, 2008.

For a discussion of Adjusted EBITDA and reconciliation to GAAP, see “Non-GAAP Financial Measures” at the end of this item.

Liquidity and Capital Resources

Historically, our sources of liquidity have included cash generated from operations, equity investments by our existing owners, equity investments by other institutional investors and borrowings under our existing revolving credit facility.

We believe that the cash generated from these sources will continue to be sufficient to meet our expected quarterly cash distributions (which we have reduced in the first two quarters of 2009 to below the minimum quarterly distribution amount described in our partnership agreement) and our requirements for short-term working capital and long-term capital expenditures.  The actual distributions we will declare will be subject to our operating performance, prevailing market conditions (including forward oil, natural gas and sulfur commodity prices), the impact of unforeseen events and the approval of the Board of Directors of our general partner’s general partner (“general partner”) and will be done pursuant to our distribution policy.

Our distribution policy is to distribute to our unitholders, on a quarterly basis, all of our available cash in the manner described below and as further described in our partnership agreement. Available cash generally means, for any quarter ending prior to liquidation, all cash on hand at the end of that quarter less the amount of cash reserves that the general partner determines to establish to:

• provide for the proper conduct of our business, including for future capital expenditures and credit needs;

• comply with applicable law or any partnership debt instrument or other agreement; or

• provide funds for distributions to unitholders and the general partner in respect of any one or more of the next four quarters.

In connection with making the distribution decision for the first and second quarters of 2009, the Board of Directors determined to reduce the quarterly distribution in each quarter to $0.025 per common unit, as compared to $0.41 per common and subordinated unit paid for the fourth quarter of 2008, to establish cash reserves (as against available cash) for the proper conduct of our business and to enhance our ability to remain in compliance with financial covenants under our revolving credit facility in future periods.  The cash not distributed has been used to reduce our outstanding debt under our revolving credit facility.  Future cash not distributed will be used to reduce our outstanding debt, to continue the execution of our hedge strategy to maintain future cash flows and/or to fund growth capital expenditures.  We anticipate that the Board of Directors will continue this strategy until such time as commodity prices impacting our business and the general economy return to levels conducive to increasing the cash distributions to be paid to our unitholders.

Under the terms of the agreements governing our revolving credit facility, we are prohibited from declaring or paying any distribution to unitholders if a default or event of default (as defined in such agreements) exists.Our goal is to reduce outstanding indebtedness under our revolving credit facility in order to return to a ratio of outstanding debt to Adjusted EBITDA, or “leverage ratio,” with respect to our Midstream and Minerals Businesses of approximately 3.0 to 3.5, which we believe to be appropriate in light of these more turbulent economic conditions and more in-line with historical midstream industry standards.  Absent any other adjustments or changes to our business or our expectations, to meet this goal we anticipate that we may be required to reduce debt by as much as $200 million.  During the three months ended, June 30, 2009, we reduced our outstanding debt under the revolving credit facility by $33.0 million from $837.4 million to $804.4 million in keeping with our goal of reducing outstanding debt by $75 million to $100 million by the second quarter of 2010.  Based primarily on our current expectations of continued depressed commodity prices and decreased drilling activity, we do not expect to be able to maintain the same level of debt reduction achieved during the second quarter of 2009 for the remaining quarters of 2009 or for 2010.  We intend to reduce outstanding debt by an additional $45 million to $65 million by the second quarter of 2010.  The actual amount and timing of further debt repayment will depend on a number of factors, including but not limited to, changes in commodity prices, our producer customers’ drilling plans, availability of external capital, and the potential consummation of asset acquisitions or divestitures, as well as future determinations of the borrowing base under our revolving credit facility.  For a detailed description of our revolving credit facility, see the description under Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Debt Covenants included in our annual report on Form 10-K for the year ended December 31, 2008 and below under “Revolving Credit Facility and Debt Covenants.”

In the event that we acquire additional midstream assets or natural gas or oil properties that exceed our existing capital resources, we expect that we will finance those acquisitions with a combination of expanded or new debt facilities or cash reserves established by our general partner and, if necessary, new equity issuances.  The continued credit crisis and related turmoil in the global financial system has caused restricted access to the capital markets, particularly for non-investment grade companies like us.  If these conditions continue, we expect our level of acquisition activity to be lower going forward than that which we experienced in 2008 and 2007.  

Working Capital. Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. As of June 30, 2009, working capital was $18.9 million as compared to $57.3 million as of December 31, 2008.

The net decrease in working capital of $38.4 million from December 31, 2008 to June 30, 2009, resulted primarily from the following factors:

• cash balances and marketable securities, net of due to affiliates, decreased overall by $22.5 million and was impacted primarily by the distributions paid on February 15, 2009 with respect to the fourth quarter of 2008 financial results, the results of operations, timing of capital expenditures payments, and financing activities including our debt activities (the due to affiliate liability of $11.1 million as of June 30, 2009 is owed to Eagle Rock Energy G&P, LLC);

• trade accounts receivable decreased by $35.1 million primarily from the impact of lower commodity prices on our consolidated revenue;

• risk management net working capital balance decreased by a net $72.6 million as a result of the changes in current portion of the mark-to-market unrealized positions, increased other derivative costs, which includes the unwinding of long-term positions to purchase current positions (see Hedging Strategy), and amortization of the put premiums and other derivative costs;

• accounts payable decreased by $48.9 million from December 31, 2008 primarily as a result of activities and timing of payments, including capital expenditures activities and lower commodity prices; and

• accrued liabilities decreased by $6.4 million primarily reflecting payment of employee benefit accruals and the timing of payment of unbilled expenditures related primarily to capital expenditures.

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Cash Flows for the Six Months Ended June 30, 2009 Compared to the Six Months Ended June 30, 2008

Cash Flow from Operating Activities. Decrease of $90.4 million during the six months ended June 30, 2009 as compared to the six months ended June 30, 2008 is the result of lower commodity prices across our three businesses and reduced NGL equity volumes in the Midstream Business, changes in working capital, as discussed above, and payments made for the resetting of commodity hedges.

Cash Flows from Investing Activities. Cash flows used for investing activities for the six months ended June 30, 2009, as compared to the six months ended June 30, 2008, decreased by $88.4 million due to acquisitions completed in 2008. The investing activities for the current period reflect additions to property, plant and equipment expenditures of $25.5 million versus $33.1 million for the prior year period.

Cash Flows from Financing Activities. Cash flows used for financing activities during the six months ended June 30, 2009, increased by $9.9 million over the six months ended June 30, 2008. Key differences between periods include net proceeds from our revolving credit facility of $5.0 million during the six months ended June 30, 2009, as compared to net proceeds of $56.0 million from our revolving credit facility during the six months ended June 30, 2008.  Distributions to members represented a cash outflow of $32.9 million during the six months ended June 30, 2009, as compared to $57.6 million during the six months ended June 30, 2008.

Hedging Strategy

 We use a variety of hedging instruments to accomplish our risk management objectives.  At times our hedging strategy may involve entering into hedges with strike prices above current futures prices or resetting existing hedges to higher price levels in order to meet our cash flow requirements, stay in compliance with our credit facility covenants and continue to execute on our distribution objectives.  Hedge transactions such as these impact our liquidity in that we are required to pay the present value of the difference between the hedged price and the current futures price.  These transactions also increase our exposure to the counterparties through which we execute the hedges.  During the six months ended June 30, 2009, as part of this strategy, we executed a series of hedging transactions that involved the unwinding of a portion of existing “in-the-money” 2011 and 2012 WTI crude oil swaps and collars, and the unwinding of two “in-the-money” 2009 WTI crude oil collars.  With these transactions, and an additional $13.9 million of cash, we purchased a 2009 WTI crude oil swap on 60,000 barrels per month beginning January 1, 2009 at $97 per barrel.

Revolving Credit Facility and Debt Covenants

 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 year ended December 31, 2008, we exercised $180 million of our $200 million accordion feature under the credit facility, which increased the total commitment to $980 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 by an additional $20 million to an aggregate of $1 billion.  As a result of Lehman Brothers’ bankruptcy filing, the amount of available commitments was reduced by the unfunded portion of Lehman Brothers’ commitment in an amount of approximately $9.1 million.   As of June 30, 2009, unused capacity available to us under the new credit agreement, based on outstanding debt and compliance with financial covenants as of that date, was approximately $88.0 million.  The credit agreement is scheduled to mature on December 13, 2012.

 Given the current state of the banking industry worldwide, we are pleased with the degree of diversification within our lender group. After the upsizing of our credit facility as described above, our credit facility now includes the participation of 20 financial institutions. As of today, all of our banks’ commitments, with the exception of Lehman Brothers’ commitment and potentially Guaranty Bank (see discussion below), 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.

In a Form 8-K filing on July 23, 2009, Guaranty Financial Group Inc. stated that it is probable that it will not be able to continue as a going concern.  Guaranty Bank, a wholly owned subsidiary of Guaranty Financial Group Inc., has a commitment under our revolving credit facility of $30 million, of which approximately $25 million has been funded.  If Guaranty Bank ceases to be a going concern, we would likely lose access to the approximate $5 million unfunded portion of Guaranty Bank’s commitment.  This unfunded commitment may increase to the extent we reduce our borrowings under the revolving credit facility, as repayments by the Partnership under the revolving credit facility would be applied proportionately among funding lenders against their respective outstanding borrowings.  As of this filing, we have not received formal notice from Guaranty Bank or any other party as to the status of its unfunded commitment.

 Our credit facility accommodates, through the use of a borrowing base for our Upstream Business and traditional cash-flow based covenants for our Midstream and Minerals Businesses, the allocation of indebtedness to either our Upstream Business (to be measured against the borrowing base) or to our Midstream and Minerals Businesses (to be measured against the cash-flow based covenant).  At June 30, 2009, we were in compliance with our covenants under the credit facility. Our interest coverage ratio, as defined in the credit agreement (i.e., Consolidated EBITDA divided by Consolidated Interest Expense), was 5.5 as compared to a minimum interest coverage covenant of 2.5, and our leverage ratio, as defined in the credit agreement (i.e., Total Funded Indebtedness divided by Adjusted Consolidated EBITDA), was 4.4 as compared to a maximum leverage ratio of 5.0.  Primarily as a result of lower expected future commodity prices, our borrowing base was re-determined in April 2009 to $135 million (which resulted in a higher allocation of indebtedness to our Midstream and Minerals Businesses).  The reduction in borrowing base was a contributing factor to the decrease in our quarterly distribution (as discussed above).  It also contributed to our taking steps to reduce our leverage.  At this time, we believe that we will remain in covenant compliance for the remainder of 2009.

Capital Requirements

We anticipate that we will have sufficient liquidity and access to capital to continue to maintain and commercially exploit our Midstream Business (all four segments), Upstream Segment, and Mineral Segment assets consistent with our current operations.  Additionally, as an operator of midstream and upstream assets, our capital requirements have increased to maintain those assets, hold production and throughput constant and to replace reserves. We anticipate that we will meet these requirements through cash generated from operations.  We believe, however, that substantial growth would require access to external capital sources.   At this time, we cannot provide assurances that we will be able to obtain the necessary capital under terms acceptable to us.

Our 2009 capital budget anticipates that we will spend approximately $40.0 million in total for the year on our existing assets.  Our 2009 capital budget anticipated that we would spend approximately $21.2 million in the six months ended June 30, 2009 on our existing assets. We actually spent approximately $22.8 million in total during that period as a result of accelerating high return-on-investment projects.  

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

• growth capital expenditures, which are made to acquire additional assets to increase our business, to expand and upgrade existing systems and facilities or to construct or acquire similar systems or facilities in our Midstream Business (and our Upstream Business with respect to the Big Escambia Plant and other Alabama plants and 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 Midstream Business (and in our Upstream Business with respect to the Big Escambia Plant and other Alabama plants and facilities); in our Upstream Business, maintenance capital also includes capital which is expended to maintain our production and cash flow levels in the near future.

Since our inception in 2002, we have made substantial growth capital expenditures. We anticipate that when economic conditions allow us, we will continue to make growth capital expenditures and acquisitions; however we anticipate that our expenditures and acquisitions in 2009 and 2010 will not return to the levels maintained by us prior to 2009. We continually review opportunities for both organic growth projects and acquisitions which will enhance our financial performance.  De-levering our business by reducing our debt and enhancing our liquidity and access to new capital such that we once again have the ability to develop and maintain sources of funds to meet our capital requirements are critical to our ability to meet our growth objectives over the long-term.

We historically have financed our maintenance capital expenditures (including well-connect costs) with internally generated cash flow and our growth capital expenditures ultimately with draws from our credit facility (although such expenditures were often funded out of internally generated cash flow as an interim step).  We anticipate funding our limited growth capital expenditures, for the foreseeable future, out of cash flow generated from operations, and, to the extent necessary, with draws from our credit facility.

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Off-Balance Sheet Obligations

We have no off-balance sheet transactions or obligations.

Recent Accounting Pronouncements

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.  SFAS No. 141R was effective for us as of January 1, 2009 but the impact of the adoption on our consolidated financial statements will depend on the nature and the extent of business combinations occurring after January 1, 2009.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of APB 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.  SFAS No. 160 was effective for us as of January 1, 2009 and did not have a material impact on our consolidated results of operations or 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.  Non-financial assets and liabilities that the Partnership measures at fair value on a non-recurring basis consists primarily of property, plant and equipment, intangible assets and asset retirement obligations, which are subject to fair value adjustments in certain circumstances (for example, when there is evidence of impairment).

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.  SFAS No. 161 was effective for us as of January 1, 2009.  See Note 11 for the additional disclosures required under FAS No. 161 related to our derivative instruments.

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 (“EITF 07-4”), 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.  EITF Issue No. 07-4 was effective for us as of January 1, 2009 and the impact on our earnings per unit calculation has been retrospectively applied to June 30, 2008 (see Note to our unaudited condensed consolidated 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 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.  FSP SFAS No. 142-3 was effective for us as of January 1, 2009 but the impact of the adoption on our consolidated financial statements will depend on the nature and the extent of business combinations occurring after January 1, 2009. 

 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.  FSP EITF 03-6-1 was effective for us as of January 1, 2009 and the impact on its earnings per unit calculation has been retrospectively applied to June 30, 2008 (see Note 16 to our unaudited condensed consolidated financial statements).

 In December 2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting to revise the existing Regulation S-K and Regulation S-X reporting requirements to align with current industry practices and technological advances. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. In addition, the new disclosure requirements require a company to (a) disclose its internal control over reserves estimation and report the independence and qualification of its reserves preparer or auditor, (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserve audit and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than period-end prices. The provisions of this final ruling will become effective for disclosures in our Annual Report on Form 10-K for the year ending December 31, 2009.  The adoption of the Final Rule, Modernization of Oil and Gas Reporting revision to Regulation S-K and Regulation S-X is not expected to have a material impact on the Partnership’s consolidated financial statements.  

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 In April 2009, the FASB issued FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments “FSP FAS 115-2 and FAS 124-2”).  FSP FAS 115-2 and FAS 124-2 amends the other-than-temporary impairment guidance for debt securities to make the guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments in the financial statements. The most significant change is a revision to the amount of other-than-temporary loss of a debt security recorded in earnings. FSP FAS 115-2 and FAS 124-2 were effective for us as of June 30, 2009 and did not have a material impact on our consolidated financial statements.

 In April 2009, the FASB issued FSP FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (“FSP FAS 157-4”).  FSP FAS 157-4 provides additional guidance for estimating fair value in accordance with FASB Statement No. 157, Fair Value Measurements, when the volume and level of activity for the asset or liability have significantly decreased.  FSP FAS 157-4 also includes guidance on identifying circumstances that indicate a transaction is not orderly and emphasizes that even if there has been a significant decrease in the volume and level of activity for the asset or liability and regardless of the valuation technique(s) used, the objective of a fair value measurement remains the same. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction (that is, not a forced liquidation or distressed sale) between market participants at the measurement date under current market conditions.  FSP FAS 157-4 was effective for us as of June 30, 2009 and did not have a material impact on our consolidated financial statements.

 In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments (“FSP FAS 107-1 and APB 28-1”). FSP FAS 107-1 and APB 28-1 amends FASB Statement No. 107, Disclosures about Fair Value of Financial Instruments, to require disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements.  FSP FAS 107-1 and APB 28-1 also amends APB Opinion No. 28, Interim Financial Reporting, to require those disclosures in summarized financial information at interim reporting periods. FSP FAS 107-1 and APB 28-1 were effective for us as of June 30, 2009.  See Notes to our unaudited condensed consolidated financial statements for further discussion.

In April 2009, the FASB issued FSP FAS 141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies (“FSP FAS 141(R)-1”), which amended and clarified SFAS 141R with respect to contingencies.  FSP FAS 141(R)-1 provides that an acquirer shall recognize at fair value, at the acquisition date, an asset acquired or a liability assumed in a business combination that arises from a contingency if the acquisition-date fair value of that asset or liability can be determined during the measurement period.  If the acquisition-date fair value of an asset acquired or a liability assumed in a business combination that arises from a contingency cannot be determined using the measurement period, the guidance in SFAS 5 and in FASB Interpretation No. 14, Reasonable Estimation of the Amount of a Loss, shall apply.”  FSP FAS 141(R)-1 was effective for us as of January 1, 2009 but the impact of the adoption on our consolidated financial statements will depend on the nature and the extent of business combinations occurring after January 1, 2009.

 On May 28, 2009, the FASB issued SFAS No. 165, Subsequent Events (“SFAS No. 165”), which provides guidance on the Partnership’s assessment of subsequent events. Historically, the Partnership has relied on U.S. auditing literature for guidance on assessing and disclosing subsequent events.  SFAS No. 165 clarifies that the Partnership must evaluate, as of each reporting period, events or transactions that occur after the balance sheet date “through the date that the financial statements are issued or are available to be issued.” The Partnership must perform its assessment for both interim and annual financial reporting periods prospectively.  SFAS No. 165 was effective for us as of June 30, 2009 but the impact of the adoption will depend on the nature and the extent of transactions that occur subsequent to our interim and annual reporting periods.

 On June 12, 2009, the FASB issued SFAS No. 166, Transfers of Financial Assets (SFAS No. 166), which amends the derecognition guidance in Statement 140.  SFAS No. 166 reflects the FASB’s response to issues entities have encountered when applying Statement 140.  In addition, SFAS 166 addresses concerns expressed by the SEC, members of the United States Congress, and financial statement users about the accounting and disclosures required by Statement 140 in the wake of the subprime mortgage crisis and the deterioration in the global credit markets.  In addition, because SFAS No. 166 eliminates the exemption from consolidation for qualified special-purpose entities (“QSPEs”) a transferor will need to evaluate all existing QSPEs to determine whether they must be consolidated.   SFAS No. 166 is effective for financial asset transfers occurring after the beginning of an entity’s first fiscal year that begins after November 15, 2009.  Early adoption of SFAS No. 166 is prohibited.   We are currently evaluating the potential impact, if any, of the adoption of SFAS No. 166 on our financial statements.

 On June 12, 2009, the FASB issued SFAS No. 167, Amendments to FASB Interpretation 46(R), (“SFAS No. 167”), which amends the consolidation guidance applicable to variable interest entities (VIEs). The amendments will significantly affect the overall consolidation analysis under FASB Interpretation 46(R) (“FIN 46(R)”).  While the FASB’s discussions leading up to the issuance of SFAS No. 167 focused extensively on structured finance entities, the amendments to the consolidation guidance affect all entities and enterprises currently within the scope of Interpretation 46(R), as well as qualifying special-purpose entities (QSPEs) that are currently excluded from the scope of FIN 46(R).  Accordingly, an enterprise will need to carefully reconsider its previous FIN 46(R) conclusions, including (1) whether an entity is a VIE, (2) whether the enterprise is the VIE’s primary beneficiary, and (3) what type of financial statement disclosures are required.  SFAS 167 is effective as of the beginning of the first fiscal year that begins after November 15, 2009, and early adoption is prohibited.  We are currently evaluating the potential impact, if any, of the adoption of SFAS No. 167 on our financial statements.

 On June 29, 2009, the FASB issued SFAS No. 168, FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162 (“SFAS No. 168”).  The FASB has stated that “the FASB Accounting Standards Codification (“Codification”)” will become the source of authoritative U.S. GAAP recognized by the FASB to be applied to nongovernmental entities.  Once effective, the Codification’s content will carry the same level of authority, effectively superseding SFAS No. 162.  The U.S. GAAP hierarchy will be modified to include only two levels of GAAP: authoritative and nonauthoritative.  SFAS No. 168 is effective for financial statements issued for interim and annual periods ended after September 15, 2009.  We do not believe that the adoption of SFAS No. 168 will have a material impact on our financial statements.

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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 or (minus) income tax provision (benefit); interest-net, including realized interest rate risk management instruments and other expense; depreciation, depletion and amortization expense, impairment 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 related instruments; (gains) losses on discontinued operations and other (income) expense. We use Adjusted EBITDA as a measure of our core profitability to assess the financial performance of our assets.  Adjusted EBITDA is used as a supplemental financial measure by external users of our financial statements such as investors, commercial banks and research analysts. For example, our lenders under our revolving credit facility use a variant of our Adjusted EBITDA in a compliance covenant designed to measure the viability of us and our ability to perform under the terms of the revolving credit facility; we, therefore, use Adjusted EBITDA to measure our compliance with our revolving credit facility.  We believe that investors benefit from having access to the same financial measures that our management uses in evaluating performance.  Adjusted EBITDA is useful in determining our ability to sustain or increase distributions. By excluding unrealized derivative gains (losses), a non-cash, mark-to-market benefit (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 describes more accurately the underlying performance of our operating assets by isolating the performance of our operating assets from the impact of an unrealized, non-cash measure designed to describe the fluctuating inherent value of a financial asset. Similarly, by excluding the impact of non-recurring discontinued operations, Adjusted EBITDA provides users of our financial statements a more accurate picture of our current assets’ cash generation ability, independently from that of assets which are no longer a part of our operations. Our Adjusted EBITDA definition may not be comparable to Adjusted EBITDA or similarly titled measures of other entities, as other entities may not calculate Adjusted EBITDA in the same manner as us. For example, we include in Adjusted EBITDA the actual settlement revenue created from our commodity hedges by virtue of transactions undertaken by us to reset commodity hedges to higher prices or purchase puts or other similar floors despite the fact that we exclude from Adjusted EBITDA any charge for amortization of the cost of such commodity hedge reset transactions or puts.  For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP (accounting principles generally accepted in the United States) see the table below.

Adjusted EBITDA should not be considered an alternative to net income (loss), operating income (loss), cash flows from operating activities or any other GAAP measure of liquidity or financial performance.

 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 income determined under GAAP, as well as Adjusted EBITDA, to evaluate our liquidity.

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 Reconciliations of “Adjusted EBITDA” to net cash flows provided by operation activities and net loss

	Three Month Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Net cash flows provided by operating activities	$	36,896		$	89,499		$	32,279		$	122,644
Add (deduct):
Depreciation, depletion, amortization and impairment		(27,588	)		(26,457	)		(57,893	)		(52,202	)
Amortization of debt issuance costs		(267	)		(219	)		(534	)		(436	)
Risk management portfolio value changes		(85,090	)		(242,576	)		(72,613	)		(289,308	)
Net realized (loss) gain on derivatives		2,457			(7,259	)		6,774			(9,537	)
Other		3,364			(111	)		4,092			31
Accounts receivables and other current assets		(10,351	)		18,719			(34,926	)		48,933
Accounts payable, due to affiliates and accrued liabilities		2,731			(58,006	)		43,835			(75,697	)
Other assets and liabilities		3,061			(610	)		1,654			224
Net loss		(74,787	)		(227,020	)		(77,332	)		(255,348	)
Add (deduct):
Interest (income) expense, net		10,701			9,490			21,957			18,609
Depreciation, depletion and amortization		27,588			26,457			57,893			52,202
Income tax benefit		(1,477	)		(886	)		(4,207	)		(988	)
EBITDA		(37,975	)		(191,959	)		(1,689	)		(185,525	)
Add (deduct):
Unrealized risk management losses		85,090			242,576			86,513			289,308
Equity-based compensation expense		1,889			1,559			4,120			2,718
Non-cash mark-to-market of Upstream imbalances		(203	)		—			1,829			—
Other income		(550	)		(886	)		(1,110	)		(2,433	)
Discontinued operations		(33	)		(551	)		(340	)		(839	)
Other operating expenses		(3,552	)		6,214			(3,552	)		6,214
ADJUSTED EBITDA	$	44,666		$	56,953		$	85,771		$	109,443

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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 put and call options, 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, 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.

Commodity Price Risk

We are exposed to the impact of market fluctuations in the prices of crude oil, natural gas, NGLs, sulfur and other commodities as a result of our gathering, processing, producing and marketing activities, which produce a naturally long position in crude oil, NGLs, sulfur 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 those correlations may change in the future.

We frequently use financial derivatives to reduce our exposure to commodity price risk. We have implemented a risk management policy which allows management to execute crude oil, natural gas liquids and natural gas hedging instruments, which may include swaps, collars, options and other derivatives, in order to reduce exposure to substantial adverse changes in the prices of these commodities. These hedges are only intended to mitigate the risk associated with our natural physical position.  To date we have been unable to identify financial derivatives to reduce our exposure to sulfur price risk.

We have not designated our derivative contracts as accounting hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. As a result, we mark our derivatives to fair value with the resulting change in fair value included in our statement of operations.  For the three months ended June 30, 2009, the Partnership recorded a loss on risk management instruments of $74.6 million representing a fair value (unrealized) loss of $85.9 million, amortization of put premiums and other derivative costs of $11.1 million and net (realized) settlement gain of $22.5 million.  For the six months ended June 30, 2009, the Partnership recorded a loss on risk management instruments of $48.3 million representing a fair value (unrealized) loss of $78.3 million, amortization of put premiums and other derivative costs of $23.3 million and net (realized) settlement gains of $53.3 million.  As of June 30, 2009, the fair value asset of these commodity contracts, including put premiums and other derivative costs, totaled approximately $21.6 million.

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

Interest Rate Risk

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

 We have not designated our contracts as accounting hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. As a result, we mark our derivatives to market with the resulting change in fair value included in our statement of operations.  For the three months ended June 30, 2009, the Partnership recorded a fair value (unrealized) gain of $12.0 million and a realized loss of $5.1 million.  For the six months ended June 30, 2009, the Partnership recorded a fair value (unrealized) gain of $15.1 million and a realized loss of $8.6 million.  As of June 30, 2009, the fair value liability of these interest rate contracts totaled approximately $24.9 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. With respect to the sale of our NGLs and condensates, our principal customers are large natural gas liquids purchasers, fractionators and marketers, and large condensate aggregators that then 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.  Our credit risk monitoring is intended to mitigate our exposure to significant credit risk.

Our derivative counterparties, both commodity and interest rate, include BNP Paribas, Wells Fargo Bank N.A., Wachovia Bank N.A, Bank of Nova Scotia, Comerica Bank, Barclays Bank PLC, The Royal Bank of Scotland plc and its agent Sempra Energy Trading LLC, Bank of America N.A., J Aron and Company (an affiliate of Goldman Sachs) BBVA Compass Bank and Credit Suisse Energy LLC (an affiliate of Credit Suisse Group AG).

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

 Based on the evaluation of our disclosure controls and procedures (as defined in the Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) required by Exchange Act Rules 13a-15(b) or 15d-15(b), our principal executive officer and principal financial officer have concluded that as of the end of the period covered by this report, our disclosure controls and procedures were effective to ensure that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including the principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the Partnership’s most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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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.

We have voluntarily undertaken a self-audit of our compliance with air quality standards, including permitting in the Texas Panhandle Segment as well as a majority of our other Midstream Business locations and some of our Upstream Business locations in Texas. This auditing has been performed pursuant to the Texas Environmental, Health and Safety Audit Privilege Act, as amended. We have completed the disclosures to the Texas Commission on Environmental Quality (“TCEQ”), and we are addressing in due course the deficiencies that we disclosed therein.  We do not foresee at this time any impediment to the timely corrective efforts identified as a result of these audits.

Subsequent to December 31, 2008, we received additional Notices of Enforcement (“NOEs”) and a Notice of Violation (“NOV”) from the TCEQ related to air compliance matters.  We expect to receive additional NOEs or NOVs from the TCEQ from time to time throughout 2009.  Though the TCEQ has the discretion to adjust penalties and settlements upwards based on a compliance history containing multiple, successive NOEs, we do not expect that the resolution of any existing NOE or any future similar NOE will vary significantly from the administrative penalties and agreed settlements experienced by us to date.

Item 1A.                      Risk Factors.

Set forth below is a material update to the risk factors discussed in our annual report on Form 10-K for the year ended December 31, 2008.

Regulation of greenhouse gas emissions could adversely affect our revenues and costs of operation.

 On April 17, 2009, the U.S. Environmental Protection Agency (“EPA”) released a proposed finding that greenhouse gas (“GHG”) emissions cause or contribute to air pollution that endangers public health and welfare within the meaning of Section 202(a) of the Clean Air Act.  EPA’s proposed rule is in response to the U.S. Supreme Court’s 2007 decision in Massachusetts et al v. EPA, which held that the EPA can avoid taking action to regulate GHG emissions only if it determines that greenhouse gases do not contribute to climate change or if it provides some reasonable explanation as to why it cannot or will not exercise its discretion to determine whether they do. The proposed endangerment finding does not include proposed regulations of GHG emissions. The public comment period on the proposed rule ended June 23, 2009. EPA has not taken final action.

 On June 26, 2009, the U.S. House of Representatives passed The American Clean Energy and Security Act of 2009, also known as the Waxman-Markey Bill.   The legislation would, among other things, establish a cap-and-trade program to regulate emissions of greenhouse gases.  It would also preempt regulation of GHG emissions under state cap-and-trade programs and certain provisions of the Clean Air Act.  President Obama has expressed his support for House passage of the Waxman-Markey Bill.  The U.S. Senate is working on its own legislation to control GHG emissions.  If the Senate adopts different GHG legislation, the Senate legislation would need to be reconciled with the Waxman-Markey Bill and both chambers would be required to approve identical legislation before it could become law. 

 The EPA’s proposed endangerment finding and the House passage of the Waxman-Markey Bill increase the likelihood that the U.S. will implement a federal program to regulate GHG emissions.  Many significant uncertainties remain, however, about the timing, nature, and effect of any such action.  Although it is not possible at this time to predict whether or when new laws or regulations may be adopted to regulate GHG emissions, such actions would likely require us to incur increased operating costs, and could have an adverse effect on demand for the oil and natural gas we produce and distribute.

In addition, we disclosed in our Form 8-K filed with the Securities and Exchange Commission on April 29, 2009 additional risks relating to the ownership of common units of the Partnership.  We disclosed these additional risks in light of the distribution reduction we announced on April 29, 2009, for our distribution to be paid on May 15, 2009 with respect to the first quarter of 2009.  These additional risks are as follows:

We may not be able to pay the minimum quarterly distribution and any arrearages on the common units.

Based on current market conditions and the outlook for commodity prices, we recently announced that quarterly distributions on our common units are being reduced below the minimum quarterly distribution as defined in our partnership agreement.  As described in the partnership agreement, during the subordination period, our common units carry arrearage rights. Although the common unitholders have arrearage rights, the unitholders are not entitled to receive these arrearages, which may never be paid.  We can give no assurances that the minimum quarterly distribution and any arrearages will ever be paid on the common units.  However, we must first pay all arrearages in addition to current minimum quarterly distributions before distributions can be made to holders of our subordinated units and our incentive distribution rights, and we generally must first pay all arrearages before conversion of our subordinated units can occur.

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

 Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, limited partners will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if no cash distributions were received from us.  Our taxable income for a taxable year may include income without a corresponding receipt of cash by us, such as accrual of future income, original issue discount or cancellation of indebtedness income.  We may not pay cash distributions equal to a limited partner’s share of our taxable income or even equal to the actual tax liability that result from that income.

Except as disclosed above, the risks previously disclosed in our annual report on Form 10-K for the year ended December 31, 2008 have not changed in any material respect.

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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.

The following table sets forth certain information with respect to repurchases of common units during the three months ended June 30, 2009:

Period	Total Number of Units Purchased(1)		Average Price Paid per Unit		Total Number of Units Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Units that May yet Be Purchased Under the Plans or Programs
April 1 – April 30		—		—		—		—
May 1 – May 31		9,844	$	3.01		—		—
June 1 – June 30		—		—		—		—

(1)  All of the units were surrendered by employees to pay tax withholding in connection with the vesting of restricted common units awarded on May 15, 2007 and 2008. As a result, we are deeming the surrenders to be “repurchases.” These repurchases were not part of a publicly announced program to repurchase our common units, nor do we have a publicly announced program to repurchase our common units.

Item 3. Defaults Upon Senior Securities.

None.

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

None.

Item 5. Other Information.

          None.

Item 6. Exhibits.

31.1	Certification by Joseph A. Mills pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification by Jeffrey P. Wood pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification by Joseph A. Mills pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350.
32.2	Certification by Jeffrey P. Wood pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350.

43

SIGNATURES

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

Date: August 10, 2009	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/ Jeffrey P. Wood
		Jeffrey P. Wood
		Senior Vice President,
		Chief Financial Officer and Treasurer 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.

44

EAGLE ROCK ENERGY PARTNERS, L.P.

EXHIBIT INDEX

31.1	Certification by Joseph A. Mills pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certification by Jeffrey P. Wood pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1	Certification by Joseph A. Mills pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350
32.2	Certification by Jeffrey P. Wood pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350