Eagle Rock Energy Partners L P (EROC) 10-Q 2010 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, 2010

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)

1415 Louisiana Street, Suite 2700

Houston, Texas 77002

 (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 that 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 83,287,077 common units outstanding as of August 3, 2010.

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, 2010 and December 31, 2009	2
	Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2010 and 2009	3
	Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2010 and 2009	5
	Unaudited Condensed Consolidated Statements of Members’ Equity for the six months ended June 30, 2010 and 2009	6
	Notes to the Unaudited Condensed Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	40
Item 4.	Controls and Procedures	40
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	43
Item 1A.	Risk Factors	43
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44
Item 3.	Defaults Upon Senior Securities	44
Item 4.	[Removed and Reserved]	44
Item 5.	Other Information	45
Item 6.	Exhibits	45

1

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

EAGLE ROCK ENERGY PARTNERS, L.P.

 UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

($ in thousands)

	June 30,			December 31,
	2010			2009
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	6,321		$	2,732
Accounts receivable(1)		78,209			88,122
Risk management assets		10,035			2,479
Prepayments and other current assets		3,425			2,790
Assets held for sale		-			135,224
Total current assets		97,990			231,347
PROPERTY, PLANT AND EQUIPMENT — Net		1,139,337			1,155,733
INTANGIBLE ASSETS — Net		121,524			132,343
DEFERRED TAX ASSET		1,813			1,562
RISK MANAGEMENT ASSETS		16,857			3,410
OTHER ASSETS		10,854			9,933
TOTAL	$	1,388,375		$	1,534,328
LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	75,620		$	77,946
Due to affiliate		9,516			12,910
Accrued liabilities		10,206			11,110
Taxes payable		1,989			2,416
Risk management liabilities		34,514			51,650
Liabilities held for sale		-			150
Total current liabilities		131,845			156,182
LONG-TERM DEBT		565,383			754,383
ASSET RETIREMENT OBLIGATIONS		20,630			19,829
DEFERRED TAX LIABILITY		40,237			40,246
RISK MANAGEMENT LIABILITIES		25,146			32,715
OTHER LONG TERM LIABILITIES		566			575
COMMITMENTS AND CONTINGENCIES (Note 12)
MEMBERS’ EQUITY:
Common Unitholders(2)		610,131			484,282
Subordinated Unitholders(3)		-			52,058
General Partner(4)		(5,563	)		(5,942	)
Total members’ equity		604,568			530,398
TOTAL	$	1,388,375		$	1,534,328

(1) Net of allowable for bad debt of $4,968 as of June 30, 2010 and $4,818 as of December 31, 2009.

(2) 59,567,218 and 54,203,471 units were issued and outstanding as of June 30, 2010 and December 31, 2009, respectively.  These amounts do not include unvested restricted common units granted under the Partnership’s long-term incentive plan of 1,200,947 and 1,371,019 as of June 30, 2010 and December 31, 2009, respectively.   These amounts do not include the common units and warrants associated with the rights offering as they were issued subsequent to June 30, 2010 as discussed further in Notes 8 and 19.

(3) Zero and 20,691,495 units were issued and outstanding as of June 30, 2010 and December 31, 2009, respectively.   The subordinated units were contributed back to the Partnership during the three months ended June 30, 2010 as part of the Recapitalization and Related Transactions, as further described in Note 9.

(4) 844,551 units were issued and outstanding as of June 30, 2010 and December 31, 2009.

See notes to unaudited condensed consolidated financial statements.

2

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

($ in thousands)

	Three Months						Six Months
	Ended June 30,						Ended June 30,
	2010			2009			2010			2009
REVENUE:
Natural gas, natural gas liquids, oil, condensate and sulfur sales	$	170,998		$	153,320		$	370,294		$	311,810
Gathering, compression, processing and treating fees		16,541			11,562			29,374			23,229
Commodity risk management gains (losses)		35,592			(74,561	)		46,387			(48,305	)
Other revenue		(251	)		1,678			(215	)		1,720
Total revenue		222,880			91,999			445,840			288,454
COSTS AND EXPENSES:
Cost of natural gas and natural gas liquids		113,926			115,640			258,204			248,857
Operations and maintenance		20,364			18,751			39,599			36,921
Taxes other than income		2,811			2,878			6,348			5,856
General and administrative		12,806			11,866			25,817			24,379
Other operating income		-			(3,552	)		-			(3,552	)
Impairment		3,130			-			3,130			242
Depreciation, depletion and amortization		28,050			26,136			56,076			54,524
Total costs and expenses		181,087			171,719			389,174			367,227
OPERATING  INCOME (LOSS)		41,793			(79,720	)		56,666			(78,773	)
OTHER (EXPENSE) INCOME:
Interest income		173			141			175			172
Other (expense) income		(21	)		199			78			283
Interest expense		(3,833	)		(5,428	)		(7,978	)		(12,967	)
Interest rate risk management (losses) gains		(9,306	)		6,807			(19,018	)		6,424
Other expense		(551	)		(267	)		(820	)		(534	)
Total other (expense) income		(13,538	)		1,452			(27,563	)		(6,622	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		28,255			(78,268	)		29,103			(85,395	)
INCOME TAX (BENEFIT) PROVISION		(415	)		(1,512	)		296			(4,276	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		28,670			(76,756	)		28,807			(81,119	)
DISCONTINUED OPERATIONS, NET OF TAX		39,473			1,969			43,317			3,787
NET INCOME (LOSS)	$	68,143		$	(74,787	)	$	72,124		$	(77,332	)

See notes to unaudited condensed consolidated financial statements.

3

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (continued)

(In thousands, except per unit amounts)

	Three Months					Six Months
	Ended June 30,					Ended June 30,
	2010		2009			2010		2009
NET INCOME (LOSS) PER COMMON UNIT — BASIC:
Basic and diluted:
Income (loss) from continuing operations per unit
Common units	$	0.41	$	(1.02	)	$	0.40	$	(1.07	)
Subordinated units	$	0.38	$	(1.05	)	$	0.35	$	(1.12	)
General partner units	$	0.41	$	(1.02	)	$	0.40	$	(1.07	)
Discontinued operations per unit
Common units	$	0.56	$	0.03		$	0.58	$	0.05
Subordinated units	$	0.56	$	0.03		$	0.58	$	0.05
General partner units	$	0.56	$	0.03		$	0.58	$	0.05
Net income (loss) per unit
Common units	$	0.96	$	(0.99	)	$	0.98	$	(1.02	)
Subordinated units	$	0.94	$	(1.02	)	$	0.93	$	(1.07	)
General partner units	$	0.96	$	(0.99	)	$	0.98	$	(1.02	)
Weighted average number of basic outstanding (units in thousands)
Common units		56,597		53,147			55,344		53,093
Subordinated units		12,278		20,691			16,683		20,691
General partner units		845		845			845		845
Weighted average number diluted outstanding (units in thousands)
Common units		56,805		53,147			55,515		53,093
Subordinated units		12,278		20,691			16,683		20,691
General partner units		845		845			845		845

See notes to unaudited condensed consolidated financial statements.

4

 EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

($ in thousands)

	Six Months Ended June 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income	$	72,124		$	(77,332	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Discontinued operations		(43,317	)		(3,787	)
Depreciation, depletion and amortization		56,076			54,524
Impairment		3,130			242
Amortization of debt issuance costs		820			534
Equity in earnings of unconsolidated affiliates		-			(100	)
Distribution from unconsolidated affiliates—return on investment		67			17
Reclassing financing derivative settlements		(628	)		(6,774	)
Other operating income		-			(3,552	)
Equity-based compensation		3,358			4,120
Gain on sale of assets		(19	)		-
Other		801			(3,980	)
Changes in assets and liabilities—net of acquisitions:
Accounts receivable		9,696			31,826
Prepayments and other current assets		(635	)		(1,291	)
Risk management activities		(45,707	)		72,613
Accounts payable		(6,311	)		(45,126	)
Due to affiliates		(3,552	)		6,604
Accrued liabilities		(904	)		(5,173	)
Other assets		(84	)		(1,654	)
Other current liabilities		(697	)		-
Net cash provided by operating activities		44,218			21,711
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment		(23,910	)		(25,501	)
Proceeds from sale of assets		171,664			-
Purchase of intangible assets		(968	)		(1,109	)
Net cash provided by (used in) investing activities		146,786			(26,610	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt		36,000			123,000
Repayment of long-term debt		(225,000	)		(118,000	)
Proceeds from derivative contracts		628			6,774
Deferred transaction fees		(2,557	)		-
Repurchase of common units		(219	)		-
Distributions to members and affiliates		(3,024	)		(32,904	)
Net cash used in financing activities		(194,172	)		(21,130	)
CASH FLOWS FROM DISCONTINUED OPERATIONS:
Operating activities		6,861			10,637
Investing activities		(104	)		(393	)
Net cash provided by discontinued operations		6,757			10,244
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		3,589			(15,785	)
CASH AND CASH EQUIVALENTS—Beginning of period		2,732			17,916
CASH AND CASH EQUIVALENTS—End of period	$	6,321		$	2,131
Interest paid—net of amounts capitalized	$	8,325		$	10,828
Units issued in acquisition from escrow	$	2,089		$	-
Cash paid for taxes	$	1,437		$	114
Issuance of common units for transaction fee	$	29,000		$	-
Investments in property, plant and equipment, not yet paid	$	8,429		$	4,063
Deferred transaction fees, not yet paid	$	478		$	-

See notes to unaudited condensed consolidated financial statements.

5

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY

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 — January 1, 2009	$	(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

FOR THE SIX MONTH PERIOD ENDED JUNE 30, 2010

($ in thousands, except unit amounts)

	General Partner			Number of Common Units			Common Units			Number of Subordinated Units			Subordinated Units			Total
BALANCE — January 1, 2010	$	(5,942	)		54,203,471		$	484,282			20,691,495		$	52,058		$	530,398
Net income		823			-			53,159			-			18,142			72,124
Distributions		(483	)		-			(31,699	)		-			-			(32,182	)
Vesting of restricted units		-			243,774			-			-			-			-
Units released from escrow		-			330,604			2,089			-			-			2,089
Repurchase of common units		-			(35,842	)		(219	)		-			-			(219	)
Equity based compensation		39			-			2,525			-			794			3,358
Payment of transaction fee to Eagle Rock Holdings, L.P		-			4,825,211			29,000			-			-			29,000
Cancellation of subordinated units		-			-			70,994			(20,691,495	)		(70,994	)		-
BALANCE — June 30, 2010	$	(5,563	)		59,567,218		$	610,131			-		$	-		$	604,568

See notes to unaudited condensed consolidated financial statements.

6

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. ORGANIZATION AND DESCRIPTION OF BUSINESS

 Basis of Presentation and Principles of Consolidation—The accompanying financial statements include consolidated assets, liabilities and the results of operations of Eagle Rock Energy Partners, L.P. (“Eagle Rock Energy” or the “Partnership”). The general partner of Eagle Rock Energy is Eagle Rock Energy GP, L.P. The general partner of Eagle Rock Energy GP, L.P. is Eagle Rock Energy G&P, LLC, a wholly-owned subsidiary of Eagle Rock Holdings, L.P. (“Holdings”). On July 30, 2010, The Partnership exercised the GP Acquisition Option (as defined in Note 9) and acquired Eagle Rock Energy GP, L.P. and Eagle Ro ck Energy G&P, LLC. , as further discussed within Note 19.  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, 2009. 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, 2010 are not necessarily indicative of the results that may be expected for the year ending December 31, 2010.

 Recent Developments—On May 21, 2010, a majority of the unitholders not affiliated with the Partnership’s general partner approved the Recapitalization and Related Transactions, as defined and further discussed in Note 9.  As a result of this approval, the Partnership’s subordinated units and incentive distribution rights were cancelled (see Note 8), and the Partnership consummated the sale of its Minerals Business.  Operations related to the Minerals Business for the three and six months ended June 30, 2010, have been recorded as part of discontinued operations.  Financial information related to t he Minerals Business for the three months ended March 31, 2010 and the three and six months ended June 30, 2009 has been retrospectively adjusted to reflect as assets and liabilities held-for-sale and discontinued operations (see Notes 13 and 17).  In addition, the Partnership launched a rights offering to the holders of its common units and general partner units on June 1, 2010, in which it distributed transferable subscription rights (“Rights”) to subscribe for common units and warrants to purchase additional common units.  This rights offering expired on June 30, 2010, and the Partnership issued 21,557,164 common units and warrants on or about July 8, 2010.  See Notes 8 and 19 for a further discussion of the rights offering.

 Description of Business— The Partnership is a domestically-focused, 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;” and (ii) acquiring, developing and producing hydrocarbons in oil and natural gas properties, which the Partnership calls its “Upstream Business.” See Note 13 for a further description of the Partnership’s two businesses and its six reporting segments.

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

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

The Partnership has provided a discussion of significant accounting policies in its annual report on Form 10-K for the year ended December 31, 2009. 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 the oil and natural gas properties in its Upstream Business. Leasehold costs are capitalized when incurred. Costs incurred to drill and complete development wells, including dry holes, are capitalized. Unproved properties are assessed periodically within specific geographic areas and, if necessary, impairments are charged to expense. Geological and geophysical expenses and delay rentals are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if the well is determined to be unsuccessful. 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 producing oil and natural gas properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for acquisition costs using all proved reserves. Authoritative guidance requires that acquisition costs of proved properties be amortized on the basis of all proved reserves, (developed and undeveloped) and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves.

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

Impairment of Oil and Natural Gas Properties

 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 the 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 a continued decline in natural gas prices during the period.  No impairment charges were incurred during the three and six months ended June 30, 2010.  The Partnership cannot predict the amount of additional impairment charges that may be recorded in the future.

 Unproved leasehold costs are reviewed periodically and a loss is recognized to the extent, if any, that the cost of the property has been impaired. 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.

Other Significant Accounting Policies

Transportation and Exchange Imbalances—In the course of transporting natural gas and NGLs for others, the Partnership’s Midstream Business may receive for redelivery different quantities of natural gas or NGLs 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 NGLs 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 are 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, 2010, the Partnership had imbalance receivables totaling $0.9 million and imbalance payables totaling $1.0 million, respectively. For the Midstream Business, as of December 31, 2009, the Partnership had imbalance receivables totaling $0.3 million and imbalance payables totaling $2.9 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 NGLs sold.

7

 Impairment of Long-Lived Assets—Management evaluates whether the carrying value of non-oil and natural gas long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the assets. Management considers various factors when determining if these assets should be evaluated for impairment, including, but not limited to:

• significant adverse change in legal factors or in the business climate;

• a current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast which demonstrates continuing losses associated with the use of a long-lived asset;

• an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;

• significant adverse changes in the extent or manner in which an asset is used or in its physical condition;

• a significant change in the market value of an asset; or

• a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.

If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets.  During the three and six months ended June 30, 2010 the Partnership recorded impairment charges of $3.1 million related to its Mi dstream Business due to the loss of a significant gathering contract in its South Texas Segment.  During the three and six months ended June 30, 2009, the Partnership did not record any impairment charges related to its Midstream Business.

 Revenue Recognition—The Partnership’s primary types of sales and service activities reported as operating revenue include:

• sales of natural gas, NGLs, crude oil and condensate;

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

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

• royalties, overriding royalties and lease bonuses.

 Revenues associated with sales of natural gas, NGLs, crude oil and condensate are recognized when title passes to the customer, which is when the risk of ownership passes to the customer and physical delivery occurs. Revenues associated with transportation and processing fees are recognized when the service is provided.

 For gathering and processing services, the Partnership either receives fees or commodities from natural gas producers depending on the type of contract. Under the percentage-of-proceeds contract type, the Partnership is paid for its services by keeping a percentage of the NGLs produced and a percentage of the residue gas resulting from processing the natural gas. Commodities received are in turn sold and recognized as revenue in accordance with the criteria outlined above. Under the keep-whole contract type, Eagle Rock Energy purchases wellhead natural gas to return to the producer and sells processed natural gas and NGLs to third parties.

 Transportation, compression and processing-related revenues are recognized in the period when the service is provided and include the Partnership’s fee-based service revenue for services such as transportation, compression and processing.

 The Partnership’s Upstream Segment recognizes revenues based on actual volumes of crude oil and natural gas sold to purchasers. The volumes of natural gas sold may differ from the volumes to which the Partnership is entitled based on its interests in the properties. Differences between volumes sold and volumes based on entitlements create natural gas imbalances. Material imbalances are reflected as adjustments to reported natural gas reserves and future cash flows.  As of June 30, 2010, the Partnership’s Upstream Segment had an imbalance receivable balance of $1.6 million and an imbalance payable balance of $0.2 million.  As of December 31, 2009, the Partnership’s Upstream Segment had an imbalance receivable balance of $1.9 million and an imbalance payable balance of $0.5 million.

A significant portion of the Partnership’s sale and purchase arrangements are accounted for on a gross basis in the consolidated statements of operations as natural gas sales and costs of natural gas, respectively. These transactions are contractual arrangements which establish the terms of the purchase of natural gas at a specified location and the sale of natural gas at a different location at the same or at another specified date. These arrangements are detailed either jointly, in a single contract, or separately in individual contracts which are entered into concurrently or in contemplation of one another with a single or multiple counterparties. Both transactions require physical delivery of the natural gas and the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk and counterparty nonperformance risk. Under authoritative guidance, purchase and sale agreements with the same counterparty are required to be recorded on a net basis.  For the three and six months ended June 30, 2010 and 2009, the Partnership did not enter into any purchase and sale agreements with the same counterparty.

Derivatives—The Partnership recognizes all derivatives as either assets or liabilities in the statement of financial position and measures 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 any changes in fair value 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 r eported as a financing activity in the statements of cash flows. See Note 11 for a description of the Partnership’s risk management activities.

NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS

 The Financial Accounting Standards Board (the “FASB”) has codified a single source of U.S. Generally Accepted Accounting Principles (U.S. GAAP), the Accounting Standards Codification.  Unless needed to clarify a point to readers, the Partnership will refrain from citing specific section references when discussing application of accounting principles or addressing new or pending accounting rule changes.

 In June 2009, the FASB issued authoritative guidance which reflects the FASB’s response to issues entities have encountered when applying previous guidance.  In addition, this guidance addresses concerns expressed by the Securities and Exchange Commission (“SEC”), members of the United States Congress, and financial statement users about the accounting and disclosures required in the wake of the subprime mortgage crisis and the deterioration in the global credit markets.  In addition, because this guidance 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.   The guidance 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 the guidance was prohibited.   This guidance was effective for the Partnership as of January 1, 2010 and did not have a material impact on its consolidated financial statements.

 In June 2009, the FASB issued authoritative guidance, which amends the consolidation guidance applicable to variable interest entities (“VIEs”). The amendments will significantly affect the overall consolidation analysis.  While the FASB’s discussions leading up to the issuance of this guidance focused extensively on structured finance entities, the amendments to the consolidation guidance affect all entities and enterprises, as well as QSPEs that were excluded from previous guidance.  Accordingly, an enterprise will need to carefully reconsider its previous 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.  T his guidance is effective as of the beginning of the first fiscal year that begins after November 15, 2009, and early adoption was prohibited.  This guidance was effective for the Partnership as of January 1, 2010 and did not have a material impact on its consolidated financial statements.

 In September 2009, the FASB issued a consensus which revises the standards for recognizing revenue on arrangements with multiple deliverables.  Before evaluating how to recognize revenue for transactions with multiple revenue generating activities, an entity should identify all the deliverables in the arrangement and, if there are multiple deliverables, evaluate each deliverable to determine the unit of accounting and whether it should be treated separately or in combination.  The consensus removes certain thresholds for separation, provides criteria for allocation of revenue amongst deliverables and expands disclosure requirements.  The standards will be effective for fiscal years beginning on or after June 15, 2010 unless the Partnership elects to early adopt the standards. 
60; The Partnership has not determined if it will early adopt the standards but does not anticipate the standards to have a material impact on its consolidated financial statements.

8

In January 2010, the FASB issued additional guidance on fair value disclosures. The new guidance clarifies two existing disclosure requirements and requires new disclosures such as: (1) a “gross” presentation of activities (purchases, sales, and settlements) within the Level 3 rollforward reconciliation, which will replace the “net” presentation format; and (2) detailed disclosures about the transfers in and out of Level 1 and 2 measurements. This guidance is effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 rollforward information, which is required for annual reporting periods beginning after December 15, 2010, and for interim reporting periods within those years. The Partnership adopted the f air value disclosures guidance on January 1, 2010, except for the gross presentation of the Level 3 rollforward information which is not required to be adopted by the Partnership until January 1, 2011 (see Notes 10 and 11).

NOTE 4. ACQUISITIONS

2008 Acquisitions

 Update on Millennium Acquisition.   On October 1, 2008, the Partnership completed the acquisition of 100% of the outstanding units of Millennium Midstream Partners, L.P. (“MMP”).   MMP is in the natural gas gathering and processing business, with assets located in East, Central and West Texas and South Louisiana.  With respect to the South Louisiana assets acquired in the acquisition, the Yscloskey and North Terrebonne facilities were flooded with three to four feet of water as a result of the storm surges caused by Hurricanes Ike and/or Gustav.  The North Terrebonne facility came back on-line in November 2008 and the Yscloskey facility came back on- line in January 2009.  The former owners of MMP provided 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.  As of December 31, 2009, the escrow account held 391,304 common units.  During the six months ended June 30, 2010, the Partnership released 330,604 units out of escrow to the former owners of MMP and recovered the remaining 60,700 units held in escrow.  As of June 30, 2010, the Partnership had an additional claim for $0.2 million cash out of escrow.

 As a result of releasing the 330,604 units out of escrow to the former owners of MMP, the Partnership adjusted its purchase price allocation with respect to the Millennium Acquisition.  As of June 30, 2010, the total purchase price was $212.9 million.  With respect to the Millennium Acquisition, the Partnership increased the amount allocated to pipelines, plants and intangibles by $1.2 million, $0.8 million and $0.3 million, respectively.

NOTE 5. FIXED ASSETS AND ASSET RETIREMENT OBLIGATIONS

Fixed assets consisted of the following:

	June 30,			December 31,
	2010			2009
	($ in thousands)
Land	$	2,566		$	1,559
Plant		243,971			242,223
Gathering and pipeline		678,273			675,474
Equipment and machinery		23,983			22,527
Vehicles and transportation equipment		4,226			4,232
Office equipment, furniture, and fixtures		1,296			1,248
Computer equipment		7,905			6,912
Corporate		126			126
Linefill		4,269			4,269
Proved properties		449,913			435,789
Unproved properties		5,534			7,264
Construction in progress		22,936			15,513
		1,444,998			1,417,136
Less: accumulated depreciation, depletion and amortization		(305,661	)		(261,403	)
Net property, plant and equipment	$	1,139,337		$	1,155,733

Depreciation expense for the three and six months ended June 30, 2010 and 2009 was approximately $13.5 million, $27.5 million, $12.6 million and $27.0 million, respectively. Depletion expense for the three and six months ended June 30, 2010 and 2009 was approximately $8.8 million, $17.0 million, $7.7 million and $16.0 million, respectively.  During the three and six months ended June 30, 2010, the Partnership recorded impairment charges of $2.0 million and $0.6 million to its pipeline and plant assets, respectively, due to the loss of a significant gathering contract in its South Texas Segment.  The Partnership did not incur any impairment charges in its Midstream Business during the three and six months ended June 30, 2009.  The Partnership incurred impairment charges of $0.2 million in its Upstream Segm ent as a result of a continued decline in natural gas prices during the six 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, 2010.   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 each of the three and six months ended June 30, 2010 and 2009, the Partnership capitalized interest costs of $0.1 million.

Asset Retirement Obligations—The Partnership recognizes asset retirement obligations for its oil and natural gas working interests associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. The Partnership records 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 the term “conditional asset retirement obligation,” which refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditiona l 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 upon initial recognition if the fair value of the liability can be reasonably estimated. As of June 30, 2010 and December 31, 2009, the Partnership had $1.0 million restricted in an escrow account for purposes of settling associated asset retirement obligations in the State of Alabama.

 A reconciliation of the Partnership’s liability for asset retirement obligations is as follows:

	2010			2009
	($ in thousands)
Asset retirement obligations -- January 1	$	19,829		$	19,872
Liabilities settled		(261	)		(831	)
Accretion expense		1,062			597
Asset retirement obligations -- June 30	$	20,630		$	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, $5.8 million and $11.6 million for the three and six months ended June 30, 2010 and 2009, respectively. The Partnership recorded impairment charges of $0.5 million related to rights-of-way in the three and six months ended June 30, 2010.  The Partnership did not incur impairment charges in the three and six months ended June 30, 2009.  Estimated aggregate amortization expense for 2010 and each of the four succeeding years is as follows: 2010—$22.4 million; 2011—$11.6 million; 2012& #8212;$11.6 million; 2013—$11.6 million; and 2014—$7.1 million. Intangible assets consisted of the following:

	June 30,			December 31,
	2010			2009
	($ in thousands)
Rights-of-way and easements—at cost	$	86,728		$	86,243
Less: accumulated amortization		(17,944	)		(15,600	)
Contracts		124,196			123,959
Less: accumulated amortization		(71,456	)		(62,259	)
Net intangible assets	$	121,524		$	132,343

 The amortization period for rights-of-way and easements is 20 years. The amortization period for contracts range from 5 to 20 years and are approximately 10 years on average as of June 30, 2010.

NOTE 7. LONG-TERM DEBT

As of June 30, 2010 and December 31, 2009, the Partnership had $565.4 million and $754.4 million outstanding, respectively, under its revolving credit facility.  The Partnership had approximately $306 million of unused capacity under the revolving credit facility (before taking into account covenant-based capacity limitations) as of June 30, 2010 on which the Partnership pays a 0.3% commitment fee per year.

 As of June 30, 2010, the Partnership was in compliance with the financial covenants under its revolving credit facility.  The Partnership believes that it will remain in compliance with its financial covenants through 2010.

 On March 8, 2010, the Partnership entered into the Second Amendment to its revolving credit facility (the “Credit Facility Amendment”), dated as of December 13, 2007, with Wachovia Bank, N.A.; Bank of America, N.A.; HSH NordBank AG, New York Branch; The Royal Bank of Scotland, PLC; BNP Paribas and the other lenders party thereto.  The Credit Facility Amendment modified the definition of “Change in Control” in such a way that the exercise of the GP Acquisition Option under the terms of the Global Transaction Agreement (as defined in Note 9) did not trigger a “Change in Control” event and potential default.  In connection with the Partnership’s unitholder approval of the transactions under the Recapital ization and Related Transactions, as further discussed in Note 9, the Credit Facility Amendment became effective.

In addition to modifying the definition of “Change in Control,” the Credit Facility Amendment also:

• Reduces the maximum permitted Senior Secured Leverage Ratio (as such term is defined in the revolving credit facility) from 4.25 under the current revolving credit facility to 3.75 as amended (and from 4.75 to 4.25 for specified periods following certain permitted acquisitions);  the Senior Secured Leverage Ratio covenant is only relevant if the Partnership has unsecured senior or subordinated notes outstanding;
• Obligated the Partnership to use $100 million of the proceeds from the Minerals Business sale to make a mandatory prepayment towards its outstanding borrowings under the revolving credit facility, which mandatory prepayment was made on May 25, 2010; and
• Reduced, upon such mandatory prepayment, the Partnership’s borrowing capacity under the revolving credit facility by the $100 million amount of such mandatory prepayment.

 On April 19, 2010, the Partnership announced that the borrowing base under its revolving credit facility, which relates to its Upstream Business, was set at $130 million from $135 million by its commercial lenders as part of the Partnership’s regularly scheduled semi-annual borrowing base redetermination.  The redetermined borrowing base was effective April 1, 2010, with no additional fees or increase in interest rate spread incurred.

NOTE 8. MEMBERS’ EQUITY

At June 30, 2010, there were 59,567,218 common units and 844,551 general partner units outstanding. In addition, there were 1,200,947 unvested restricted common units outstanding.

As part of the approval of certain of the Recapitalization and Related Transactions, as further discussed in Note 9, on May 24, 2010, the Partnership’s general partner and Holdings contributed to the Partnership all 20,691,495 of the outstanding subordinated units and all of the outstanding incentive distribution rights in the Partnership.  In connection with the contribution of the subordinated units and incentive distribution rights, the Partnership (i) issued 4,825,211 common units to Holdings as payment of the transaction fee contemplated by the Global Transaction Agreement (as defined in Note 9) and (ii) adopted and entered into a Second Amended and Restated Agreement of Limited Partnership.

Pursuant to the Partnership’s Second Amended and Restated Agreement of Limited Partnership, among other things, (i) the  subordinated units and incentive distribution rights were cancelled, (ii) the concepts of a subordination period and a minimum quarterly distribution (and, as a result, the concept of arrearages on the common units) were eliminated and (iii) provisions were included that provide the Partnership an option to acquire its general partner and its general partner entities, which were acquired on July 30, 2010, as further discussed in Note 19.

On June 1, 2010, the Partnership launched it rights offering and distributed 21,557,164 Rights to the holders of its common and general partner units as of close of business on May 27, 2010, the record date.  Each common and general partner unitholder received 0.35 Rights for each unit held as of the record date.   Each Right entitled the holder (including holders of Rights acquired during the subscription period) to purchase for $2.50 in cash (i) one common unit and (ii) one warrant to purchase one additional common unit at $6.00 on certain specified days beginning on August 15, 2010 and ending on May 15, 2012. The warrants are exercisable only on each March 15, May 15, August 15 and November 15 during the period in which the warrants remain outstanding.  The rights offering expired on June 30, 2010 and the Partnership issued 21,557,164 common units and warrants on or about July 8, 2010.  See Note 19 for a further discussion of the results of the rights offering.

During the three months ended June 30, 2010, the Partnership released 330,604 common units that were previously held in an escrow account related to its acquisition of MMP to the former owners of MMP.

On February 2, 2010, the Partnership declared its fourth 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 the close of business on February 8, 2010.  The distribution was paid on February 12, 2010, net of amounts retained to relieve outstanding amounts due from affiliates.

On April 27, 2010, the Partnership declared its first quarter 2010 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 the close of business on May 7, 2010.  The distribution was paid on May 14, 2010, net of amounts retained to relieve outstanding amounts due from affiliates.

On July 28, 2010, the Partnership declared its second quarter 2010 cash distribution of $0.025 per unit to its common unitholders of record as of the close of business on August 9, 2010.  The distribution will be paid on August 13, 2010.

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NOTE 9. RELATED PARTY TRANSACTIONS

 During the three and six months ended June 30, 2010 and 2009, the Partnership incurred $1.7 million, $4.0 million, $1.9 million and $4.7 million, respectively, in expenses with related parties, of which there was an outstanding accounts payable balance of $0.6 million and $0.7 million as of June 30, 2010 and December 31, 2009, respectively.

 Related to its investments in unconsolidated subsidiaries, during the three and six months ended June 30, 2010 and 2009, the Partnership recorded income of less than $0.1 million for each of the periods, of which there was no outstanding accounts receivable balances as of June 30, 2010 and December 31, 2009.

 During the three and six months ended June 30, 2010 and 2009, the Partnership incurred approximately $0.4 million, $1.1 million, $0.5 million and $0.7 million, respectively, for services performed by Stanolind Field Services (“SFS”), which is an entity controlled by Natural Gas Partners (“NGP”).  As of June 30, 2010 and December 31, 2009, there were no outstanding accounts payable balances.

 As of June 30, 2010 and December 31, 2009, Eagle Rock Energy G&P, LLC had $9.5 million and $12.9 million, respectively, of outstanding checks issued on behalf of the Partnership. This amount was recorded as Due to Affiliate on the Partnership’s balance sheet in current liabilities. As the checks are drawn against Eagle Rock Energy G&P, LLC’s cash accounts, the Partnership reimburses Eagle Rock Energy G&P, LLC.

 During 2009, the Partnership leased 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, 2010 and 2009. As of June 30, 2010 and December 31, 2009, no amounts were due to or from Montierra.

 As of June 30, 2010 and December 31, 2009, the Partnership had an outstanding receivable balance of $0.7 million due from an affiliate of NGP.

 Recapitalization and Related Transactions

 On December 21, 2009, the Partnership announced that it, through certain of its affiliates, had entered into definitive agreements with affiliates of NGP and Black Stone Minerals Company, L.P. (“Black Stone”) to improve its liquidity and simplify its capital structure.  The definitive agreements include:  (i) a Securities Purchase and Global Transaction Agreement, entered into between Eagle Rock Energy and NGP, including Eagle Rock Energy’s general partner entities controlled by NGP, and (ii) a Purchase and Sale Agreement (the “Minerals Business Sale Agreement”), entered into between Eagle Rock Energy and Black Stone for the sale of Eagle Rock Energy’s Minerals Business.  The Securities Purchase a nd Global Transaction Agreement was amended on January 12, 2010 to allow for greater flexibility in the payment of the contemplated transaction fee to Holdings, which is controlled by NGP (the Partnership refers to the amended Securities Purchase and Global Transaction Agreement as the “Global Transaction Agreement”).  The Partnership refers collectively to the transactions contemplated by the Global Transaction Agreement and Minerals Business Sale Agreement as the “Recapitalization and Related Transactions.”

 On May 21, 2010, at a reconvened special meeting of the Partnership’s common unitholders, a majority of the common unitholders not affiliated with the Partnership’s general partner approved, among other things, the Recapitalization and Related Transactions.

 The Recapitalization and Related Transactions included the following key provisions,

• An option in favor of the Partnership, exercisable until December 31, 2012 by the issuance of 1,000,000 newly-issued common units, to capture the value of its controlling interest through (i) acquiring the Partnership’s general partner, and such general partner’s general partner, and thereafter cancelling the 844,551 general partner units outstanding, and (ii) reconstituting its board of directors to allow its common unitholders to elect the majority of its directors (the “GP Acquisition Option”);

• The sale of the Partnership’s Minerals Business to Black Stone for total consideration of $174.5 million in cash, subject to customary adjustments;

• The simplification of the Partnership’s capital structure through the contribution, and resulting cancellation, of the incentive distribution rights and the approximate 20.7 million subordinated units held by Holdings;

• A rights offering for which Holdings and NGP agreed to fully participate with respect to 9.5 million common and general partner units owned or controlled by NGP as well as with respect to common units it received (see below) as payment of the transaction fee; and

• For a period of up to four months following unitholder approval of the amended Global Transaction Agreement, NGP’s commitment to back-stop (primarily through Holdings) up to $41.6 million, at a price of $3.10 per unit, an Eagle Rock Energy equity offering to be undertaken at the sole option of the Partnership’s Conflicts Committee.

 In exchange for NGP’s and Holdings’ contributions and commitments under the Global Transaction Agreement, Eagle Rock paid Holdings a transaction fee of $29 million in newly-issued common units.  The units were valued at $6.0101 per unit, based on 90% of the volume-adjusted trailing 10-day average of the trading price of Eagle Rock’s common units as of April 24, 2010, resulting in a total of approximately 4.8 million common units paid to Holdings upon completion of the Minerals Business sale on May 24, 2010.

 The sale of the Minerals Business was closed on May 24, 2010 and the final purchase price was $171.6 million (see Note 17).

 The subordinated units and incentive distribution rights were contributed and subsequently cancelled on May 24, 2010, (see Note 8).

 The rights offering was launched on June 1, 2010 and expired on June 30, 2010 (see Notes 8 and 19).

 The GP Acquisition Option was exercised by the Partnership on July 27, 2010 and closed, and the general partner units were cancelled, on July 30, 2010 (see Note 19).

 See Note 12 for a discussion of a lawsuit alleging certain claims related to the Recapitalization and Related Transactions.

 See Note 7 for a discussion of an amendment to the Partnership’s revolving credit facility related to the Recapitalization and Related Transactions.

 In connection with the Recapitalization and Related Transactions, the Partnership has incurred legal (not including related litigation costs), accounting, advisory and similar costs, beginning in May 2009 through June 30, 2010, totaling $6.4 million.  Of these costs, the Partnership has expensed, as part of General and Administrative expenses, $1.9 million and has capitalized $4.5 million as deferred transactions costs within Other Assets.

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NOTE 10. FAIR VALUE OF FINANCIAL INSTRUMENTS

Effective January 1, 2008, the Partnership adopted authoritative guidance which, among other things, requires enhanced disclosures about assets and liabilities carried at fair value.

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. The authoritative guidance 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 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 ex ecuted 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, 2010, 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.

The Partnership values its Level 2 and Level 3 derivatives using forward curves, volatility curves, volatility skew parameters, interest rate curves and model parameters.

The Partnership did not have any transfers of assets and liabilities between Level 1 and Level 2 of the fair value measurement hierarchy during the three and six months ended June 30, 2010.  If transfers were to occur, the Partnership would recognize such transfers at the beginning of the reporting period.

The following tables disclose the fair value of the Partnership’s derivative instruments as of June 30, 2010 and December 31, 2009:

	As of June 30, 2010
	Level 1		Level 2			Level 3			Total
	($ in thousands)
Assets:
Crude oil derivatives	$	-	$	11,614		$	-		$	11,614
Natural gas derivatives		-		14,554			-			14,554
NGL derivatives		-		-			724			724
Total	$	-	$	26,168		$	724		$	26,892
Liabilities:
Crude oil derivatives	$	-	$	(21,572	)	$	-		$	(21,572	)
Natural gas derivatives		-		1,087			-			1,087
NGL derivatives		-		-			(2,584	)		(2,584	)
Interest rate swaps		-		(36,591	)		-			(36,591	)
Total	$	-	$	(57,076	)	$	(2,584	)	$	(59,660	)
	As of December 31, 2009
	Level 1		Level 2			Level 3			Total
	($ in thousands)
Assets:
Crude oil derivatives	$	-	$	3		$	-		$	3
Natural gas derivatives		-		5,286			-			5,286
Interest rate swaps		-		600			-			600
Total	$	-	$	5,889		$	-		$	5,889
Liabilities:
Crude oil derivatives	$	-	$	(45,039	)	$	-		$	(45,039	)
Natural gas derivatives		-		3,475			-			3,475
NGL derivatives		-		-			(14,784	)		(14,784	)
Interest rate swaps		-		(28,017	)		-			(28,017	)
Total	$	-	$	(69,581	)	$	(14,784	)	$	(84,365	)

 As of June 30, 2010, risk management current assets in the unaudited condensed consolidated balance sheet include put premium and other derivative costs, net of amortization, of $0.9 million.

12

The following table sets forth a reconciliation of changes in the fair value of the NGL derivatives classified as Level 3 in the fair value hierarchy during the three and six months ended June 30, 2010 and 2009 (in thousands):

	Three Months						Six Months
	Ended June 30,						Ended June 30,
	2010			2009			2010			2009
Net asset (liability) balances at beginning of period	$	(7,658	)	$	11,447		$	(14,784	)	$	14,016
Settlements		2,265			(2,468	)		6,394			(910	)
Total gains (losses) realized and unrealized		3,533			(9,499	)		6,530			(13,626	)
Net liability balances at end of period	$	(1,860	)	$	(520	)	$	(1,860	)	$	(520	)

 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 Partnership recognized gains (losses) of $3.4 million, $5.1 million, $(8.2) million and $(7.1) million in the three and six months ended June 30, 2010 and 2009, respectively, that are attributable to the change in unrealized gains or losses related to those assets and liabilities still held at June 30, 2010, which are included in the unrealized commodity gains (losses).

 The following table discloses the fair value of the Partnership’s assets measured on a nonrecurring basis for the six months ended June 30, 2010 (in thousands):

	June 30, 2010		Level 1		Level 2		Level 3		Total Losses
Plant assets	$	91	$	-	$	-	$	91	$	576
Pipeline assets	$	318	$	-	$	-	$	318	$	2,006
Rights-of-way	$	85	$	-	$	-	$	85	$	548

 In connection with the preparation of these financial statements for the three and six months ended June 30, 2010, the Partnership wrote down plant assets with a carrying value of $0.7 million to their fair value of $0.1 million, pipeline assets with a carrying value of $2.3 million to their fair value of $0.3 million, and rights-of-way with a carrying value of $0.6 million to their fair value of $0.1 million, resulting in an impairment charge of $3.1 million being included in earnings for the three and six months ended June 30, 2010.  This impairment charge related specifically to the Midstream Business due to the loss of a significant contract within its South Texas Segment.  The Partnership calculated the fair value of the impaired assets using discounted cash flow analysis to determine the excess of the asset’s carrying value over its fair value.

 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.

 The Partnership believes that the fair value of its revolving credit facility does not approximate its carrying value as of June 30, 2010 and December 31, 2009 because the applicable floating rate margin on the revolving credit facility was a below-market rate. The fair value of the revolving credit facility has been estimated based on similar transactions that occurred during the twelve months ended December 31, 2009 and the six months ended June 30, 2010. The Partnership estimates the fair value of the borrowings under its revolving credit facility as of June 30, 2010 was $538.7 million versus a carrying value of $565.4 million.  The Partnership estimated the fair value of the borrowings under its revolving credit facility as of December 31, 2009 was $713.2 million versus a carrying value of $754.4 mil lion.

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.

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 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, 2010:

Effective Date	Expiration Date	Notional Amount		Fixed Rate (a)
12/31/2008	12/31/2012	$	150,000,000		2.360 % / 2.560	%
9/30/2008	12/31/2012		150,000,000		4.105 % / 4.295	%
10/3/2008	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.

 The Partnership’s interest rate derivative counterparties include Wells Fargo Bank, N.A.; Wachovia Bank, N.A and The Royal Bank of Scotland, PLC.  As of June 30, 2010, the notional amount of the Partnership’s interest rate swaps was in excess of its outstanding borrowings by approximately $34.6 million.

 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 it s expected production in order to meaningfully reduce its future cash flow volatility.  The Partnership 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, 2010 and 2011 hedging activity.  At times, the Partnership’s strategy may involve entering into hedges with strike prices above current future prices or resetting existing hedges to higher price levels in order to meet its cash flo w objectives or to stay in compliance with its revolving credit facility.  In addition, the Partnership may also terminate or unwind hedges or portions of hedges when the expected future volumes do not support the level of hedges or otherwise.  Expected future production for its Upstream Business 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 Business 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 exp ected 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 ethan e production because forward prices for ethane are often heavily discounted from their 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 its 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.

 The Partnership’s commodity derivative counterparties include BNP Paribas; Wachovia Bank, N.A.; Comerica Bank; Barclays Bank PLC; Bank of Nova Scotia; 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).

 The following table, as of June 30, 2010, sets forth certain information regarding the Partnership’s commodity derivatives that will mature during the year ended December 31, 2010 (excluding transactions and volumes that settled or were unwound during the three and six months ended June 30, 2010):   

Underlying	Period	Notional Volumes (units)	Type	Floor Strike Price ($/unit)		Cap Strike Price ($/unit)
Natural Gas:
NYMEX Henry Hub	Jul-Dec 2010	660,000  mmbtu	Costless Collar	$	7.70	$	9.10
NYMEX Henry Hub	Jul-Dec 2010	750,000  mmbtu	Swap		6.65
NYMEX Henry Hub	Jul-Dec 2010	1,020,000  mmbtu	Swap		6.57
Crude Oil:
NYMEX WTI	Jul-Dec 2010	30,000  bbls	Costless Collar		50.00		67.50
NYMEX WTI	Jul-Dec 2010	54,000  bbls	Costless Collar		90.00		99.80
NYMEX WTI	Jul-Dec 2010	30,000  bbls	Put		100.00
NYMEX WTI	Jul-Dec 2010	36,000  bbls	Put		90.00
NYMEX WTI	Jul-Dec 2010	18,000  bbls	Swap		78.35
NYMEX WTI	Jul-Dec 2010	150,000  bbls	Swap		70.00
NYMEX WTI	Jul-Dec 2010	240,000  bbls	Swap		51.40
NYMEX WTI	Jul-Dec 2010	270,000  bbls	Swap		53.55
Natural Gas Liquids:
OPIS Ethane Mt Belv non TET	Jul-Dec 2010	2,268,000  gallons	Costless Collar		0.43		0.53
OPIS Ethane Mt Belv non TET	Jul-Dec 2010	2,268,000  gallons	Swap		0.58
OPIS IsoButane Mt Belv non TET	Jul-Dec 2010	1,260,000  gallons	Costless Collar		0.82		1.02
OPIS IsoButane Mt Belv non TET	Jul-Dec 2010	2,091,600  gallons	Swap		1.4045
OPIS NButane Mt Belv non TET	Jul-Dec 2010	2,772,000  gallons	Costless Collar		0.82		1.02
OPIS NButane Mt Belv non TET	Jul-Dec 2010	4,233,600  gallons	Swap		1.3745
OPIS Propane Mt Belv non TET	Jul-Dec 2010	2,520,000  gallons	Costless Collar		0.705		0.81
OPIS Propane Mt Belv non TET	Jul-Dec 2010	2,520,000  gallons	Swap		0.755
OPIS Propane Mt Belv non TET	Jul-Dec 2010	8,870,400  gallons	Swap		1.0915
OPIS Natural Gasoline Mt Belv non TET	Jul-Dec 2010	1,108,800  gallons	Swap		1.6562

 During the six months ended June 30, 2010, the Partnership entered into the following derivative transactions for its 2011 calendar year: a 12,000 barrel per month NYMEX WTI costless collar with a floor strike price at $75.00 per barrel and a cap strike price of $89.85 per barrel on February 16, 2010 and a 17,000 barrel per month NYMEX WTI swap at $83.30 on June 18, 2010.

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 The following table, as of June 30, 2010, sets forth certain information regarding the Partnership’s commodity derivatives that will mature during the year ended December 31, 2011:

Underlying	Period	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		7.09
NYMEX Henry Hub	Jan-Dec 2011	2,280,000  mmbtu	Swap		6.14
Crude Oil:
NYMEX WTI	Jan-Dec 2011	139,152  bbls	Costless Collar		75.00		85.70
NYMEX WTI	Jan-Dec 2011	360,000  bbls	Costless Collar		80.00		92.40
NYMEX WTI	Jan-Dec 2011	144,000  bbls	Costless Collar		75.00		89.85
NYMEX WTI	Jan-Dec 2011	125,256  bbls	Swap		80.00
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
NYMEX WTI	Jan-Dec 2011	360,000  bbls	Swap		65.60
NYMEX WTI	Jan-Dec 2011	204,000  bbls	Swap		83.30

 During the six months ended June 30, 2010, the Partnership entered into a 16,000 barrel per month NYMEX WTI costless collar with a floor strike price at $75.00 per barrel and a cap strike price of $94.75 per barrel for its 2012 calendar year on February 17, 2010.

 The following table, as of June 30, 2010, sets forth certain information regarding the Partnership’s commodity derivatives that will mature during the year ending December 31, 2012:

Underlying	Period	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
NYMEX Henry Hub	Jan-Dec 2012	3,120,000  mmbtu	Swap		6.77
Crude Oil:
NYMEX WTI	Jan-Dec 2012	135,576  bbls	Costless Collar		75.30		86.30
NYMEX WTI	Jan-Dec 2012	360,000  bbls	Costless Collar		80.00		98.50
NYMEX WTI	Jan-Dec 2012	192,000  bbls	Costless Collar		75.00		94.75
NYMEX WTI	Jan-Dec 2012	108,468  bbls	Swap		80.30
NYMEX WTI	Jan-Dec 2012	240,000  bbls	Swap		68.30
NYMEX WTI	Jan-Dec 2012	240,000  bbls	Swap		76.50
NYMEX WTI	Jan-Dec 2012	240,000  bbls	Swap		82.02
NYMEX WTI	Jan-Dec 2012	240,000  bbls	Swap		82.02

 During the six months ended June 30, 2010, the Partnership entered into the following derivative transactions for its 2013 calendar year: a 20,000 barrel per month of NYMEX WTI crude oil swap at $90.20 per barrel on April 9, 2010 and a 60,000 barrel per month NYMEX WTI crude oil swap at $89.85 per barrel on April 19, 2010.

 The following table, as of June 30, 2010, sets forth certain information regarding the Partnership’s commodity derivatives that will mature during the year ending December 31, 2013:

Underlying	Period	Notional Volumes (units)	Type	Floor Strike Price ($/unit)		Cap Strike Price ($/unit)
Crude Oil:
NYMEX WTI	Jan-Dec 2013	240,000  bbls	Swap	$	90.20
NYMEX WTI	Jan-Dec 2013	720,000  bbls	Swap		89.85

 On July 23, 2010, the Partnership enhanced its commodity derivative portfolio by adjusting the strike price of certain hedges to the forward market prices as of the date the hedges were executed.  Specifically, the Partnership paid $5.9 million to adjust the strike price from $53.55 to $79.80 per barrel on existing NYMEX WTI crude oil swaps of 45,000 barrels per month for the five months ended December 31, 2010.

 On August 3, 2010, the Partnership entered into a forward NYMEX WTI swap covering 29,000 barrels per month for the first half of calendar 2011 and 23,000 barrels per month for the second half of calendar 2011 with a strike price of $86.20 per barrel.  On the same date, the Partnership entered into a forward NYMEX WTI swap covering 10,000 barrels per month for the full calendar year 2013 with a strike price of $88.20 per barrel.

 On August 4, 2010, the Partnership entered into a forward NYMEX Henry Hub swap covering 50,000 MMBtu per month for the full calendar year 2013 with a strike price of $5.645 per MMBtu.

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 Fair Value of Interest Rate and Commodity Derivatives

 Fair values of interest rate and commodity derivative instruments not designated as hedging instruments in the unaudited condensed consolidated balance sheet as of June 30, 2010 and December 31, 2009:

	As of June 30, 2010
	Derivative Assets				Derivative Liabilities
	Balance Sheet Classification	Fair Value			Balance Sheet Classification	Fair Value
	($ in thousands)
Interest rate derivatives – assets		$	-			$	-
Interest rate derivatives – liabilities			-		Current liabilities		(17,507	)
Interest rate derivatives – liabilities			-		Long-term liabilities		(19,084	)
Commodity derivatives – assets	Current assets		11,642		Current liabilities		2,916
Commodity derivatives – assets	Long-term assets		27,198				-
Commodity derivatives – liabilities	Current assets		(1,607	)	Current liabilities		(19,923	)
Commodity derivatives – liabilities	Long-term assets		(10,341	)	Long-term liabilities		(6,062	)
Total derivatives		$	26,892			$	(59,660	)
	As of December 31, 2009
	Derivative Assets				Derivative Liabilities
	Balance Sheet Classification	Fair Value			Balance Sheet Classification	Fair Value
	($ in thousands)
Interest rate derivatives – assets	Long-term assets	$	600			$	-
Interest rate derivatives – liabilities			-		Current liabilities		(16,988	)
Interest rate derivatives – liabilities			-		Long-term liabilities		(11,029	)
Commodity derivatives – assets	Current assets		3,494		Current liabilities		9,842
Commodity derivatives – assets	Long-term assets		2,830		Long-term liabilities		1,684
Commodity derivatives – liabilities	Current assets		(1,015	)	Current liabilities		(44,504	)
Commodity derivatives – liabilities	Long-term assets		(20	)	Long-term liabilities		(23,370	)
Total derivatives		$	5,889			$	(84,365	)

 The following table sets forth the classification of gains and losses for derivatives not designated as hedging instruments within the Partnership’s unaudited condensed consolidated statement of operations:

Classification of Gain or (Loss) Recognized in Income on Derivatives	Amount of Gain or (Loss) Recognized in Income on Derivatives
	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	($ in thousands)
Interest rate risk management (losses) gains	$	(9,306	)	$	6,807		$	(19,018	)	$	6,424
Commodity risk management gains (losses)		35,592			(74,561	)		46,387			(48,305	)
Total	$	26,286		$	(67,754	)	$	27,369		$	(41,881	)

 The Partnership’s hedge counterparties are participants in its credit agreement, and the collateral for the outstanding borrowings under its credit agreement is used as collateral for its hedges.  The Partnership does not have rights to collateral from its counterparties, nor does the Partnership have rights of offset against borrowings under its 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 and $0.1 million as of June 30, 2010 and December 31, 2009, respectively, 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. For the se indemnified lawsuits, the Partnership has not established any accruals because the Partnership considers remote the likelihood of these lawsuits being successful in amounts in excess of the indemnification limits. These matters are not expected to have a material adverse effect on the Partnership’s financial position, results of operations or cash flows.

On February 9, 2010, a lawsuit, alleging certain claims related to the Recapitalization and Related Transactions (see Note 9), was filed on behalf of one of the Partnership’s public unitholders in the Court of Chancery of the State of Delaware naming the Partnership, its general partner, certain affiliates of its general partner, including the general partner of its general partner, and each member of the Partnership’s Board of Directors as defendants.  The complaint alleged a breach by the defendants of their fiduciary duties to the Partnership and the public unitholders and sought to enjoin the Recapitalization and Related Transactions.  The Partnership believes the allegations in the complaint are without merit.  On March 11, 2010, in an effort to minimize the further cost, expens e, burden and distraction of any litigation relating to the lawsuit, the parties to the lawsuit entered into a Memorandum of Understanding regarding the terms of a potential settlement of the lawsuit.  If the settlement is consummated it, among other things, would resolve the allegations by the plaintiff against the defendants in connection with the Recapitalization and Related Transactions and would provide a release and settlement by a proposed class of the Partnership common unitholders during the period from September 17, 2009 through and including the date of the closing of the transactions of all claims against the defendants as they relate to the Recapitalization and Related Transactions.  During the six months ended June 30, 2010, the Partnership established an accrual of $1.6 million related to this claim, against which it has already incurred $0.8 million of costs during the same period.  Thus, as of June 30, 2010, the Partnership’s accrual relating to this matter was $0.8 mill ion.  In addition, the Partnership has recorded a receivable related to this matter of approximately $0.9 million for amounts it expects to recover under its Directors and Officers insurance.  In the event that the settlement is not consummated, the Partnership intends to vigorously defend against the lawsuit.

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)& #160;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 coverages are subject to industry accepted policy terms, conditions, limits and deductibles comparable to that obtained by other energy companies with similar operations. The cost of insurance for the energy industry continued to fluctuate over the past year, reflecting the changing conditions in the insurance markets.

 Regulatory Compliance—In the ordinary course of business, 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 regu lations 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, 2010 and December 31, 2009, the Partnership had accrued approximately $4.0 million and $4.4 million, respectively, for environmental matters.

 During 2009, the Partnership completed voluntary self-audits of its compliance with air quality standards, which included 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. These audits were performed pursuant to the Texas Environmental, Health and Safety Audit Privilege Act, as amended. The Partnership completed the disclosures to the Texas Commission on Environmental Quality (“TCEQ”), and the Partnership has substantially addressed the deficiencies that it disclosed therein.  The Partnership does not foresee at this time any impediment in timely addressing the remaining deficiencies identified as a result of these audits.

 Since January 1, 2010, the Partnership has received additional Notices of Enforcement (“NOEs”) and Notices of Violation (“NOVs”) from the TCEQ related to air compliance matters and expects to receive additional NOEs or NOVs from the TCEQ from time to time throughout 2010.  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, these retained revenue interests are in effect for any calendar year in which the Partnership surpasses certain average net production rates, while for the Partnership’s Big Escambia field, the retained revenue interest, which commenced in 2010, is in effect if the Partnership surpasses certain average net production rates, but only continues 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 $1.7 million, $3.5 million, $2.2 million and $4.2 million for the three and six months ended June 30, 2010 and 2009, 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

On May 24, 2010, the Partnership completed the sale of its fee mineral and royalty interests as well as its equity investment in Ivory Working Interests, L.P. (collectively, the “Minerals Business”).  As authoritative guidance requires the operations for components of entities disposed of be recorded as part of discontinued operations, operating results for the Minerals Business for the three and six months ended June 30, 2010 and 2009 have been excluded from the Partnership’s segment presentation below.  See Note 17 for a further discussion of the sale of the Partnership’s Minerals Business.

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 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; and

 (vi) Corporate Segment:

risk management and other corporate activities such as general and administrative expenses.

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The Partnership’s chief operating decision-maker (“CODM”) currently reviews its operations using these segments. The CODM 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 Business	Texas Panhandle		South Texas				East Texas/ Louisiana				Gulf of Mexico			Total Midstream
Three Months Ended June 30, 2010	Segment		Segment				Segment				Segment			Business
($ in thousands)
Sales to external customers	$	84,003	$	20,817			$	50,779			$	7,428		$	163,027
Cost of natural gas and natural gas liquids		54,732		18,324				34,477				6,393			113,926
Operating costs and other expenses		8,413		1,097				4,210				531			14,251
Depreciation, depletion, amortization and impairment		11,639		4,322				4,112				1,567			21,640
Operating income (loss) from continuing operations	$	9,219	$	(2,926	)		$	7,980			$	(1,063	)	$	13,210
Capital Expenditures	$	7,743	$	55			$	5,267			$	5		$	13,070
Segment Assets	$	523,867	$	52,932			$	316,744			$	82,821		$	976,364
Total Segments	Total Midstream		Upstream				Corporate				Total
Three Months Ended June 30, 2010	Business		Segment				Segment				Segments
($ in thousands)
Sales to external customers	$	163,027	$	24,261			$	35,592		(a)	$	222,880
Cost of natural gas and natural gas liquids		113,926		-				-				113,926
Operating costs and other expenses		14,251		8,924		(b)		12,806				35,981
Depreciation, depletion, amortization and impairment		21,640		9,058				482				31,180
Operating income from continuing operations	$	13,210	$	6,279			$	22,304			$	41,793
Capital Expenditures	$	13,070	$	7,414			$	259			$	20,743
Segment Assets	$	976,364	$	358,908			$	53,103			$	1,388,375
Midstream Business	Texas Panhandle		South Texas				East Texas/ Louisiana				Gulf of Mexico			Total Midstream
Three Months Ended June 30, 2009	Segment		Segment				Segment				Segment			Business
($ in thousands)
Sales to external customers	$	68,974	$	26,057			$	48,620			$	7,740		$	151,391
Cost of natural gas and natural gas liquids		49,407		23,819				37,233				5,181			115,640
Operating costs and other expenses		8,056		989				4,608				658			14,311
Depreciation, depletion, and amortization		10,962		1,284				4,240				1,477			17,963
Operating income (loss) from continuing operations	$	549	$	(35	)		$	2,539			$	424		$	3,477
Capital Expenditures	$	766	$	75			$	4,820			$	-		$	5,661
Segment Assets	$	552,898	$	68,532			$	327,036			$	89,078		$	1,037,544
Total Segments	Total Midstream		Upstream				Corporate				Total
Three Months Ended June 30, 2009	Business		Segment				Segment				Segments
($ in thousands)
Sales to external customers	$	151,391	$	15,169			$	(74,561	)	(a)	$	91,999
Cost of natural gas and natural gas liquids		115,640		-				-				115,640
Operating costs and other expenses		14,311		3,766		(b)		11,866				29,943
Depreciation, depletion, amortization and impairment		17,963		7,955				218				26,136
Operating income (loss) from continuing operations	$	3,477	$	3,448			$	(86,645	)		$	(79,720	)
Capital Expenditures	$	5,661	$	1,988			$	529			$	8,178
Segment Assets	$	1,037,544	$	378,124			$	118,660			$	1,534,328

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

(b)   Includes sulfur disposal costs of $0.9 million and $0.7 million for the three months ended June 30, 2010 and 2009, respectively.

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Midstream Business	Texas Panhandle			South Texas				East Texas/ Louisiana				Gulf of Mexico			Total Midstream
Six Months Ended June 30, 2010	Segment			Segment				Segment				Segment			Business
($ in thousands)
Sales to external customers	$	177,678		$	47,400			$	111,142			$	16,287		$	352,507
Cost of natural gas and natural gas liquids		121,702			41,962				80,682				13,858			258,204
Operating costs and other expenses		16,511			1,950				8,419				1,036			27,916
Depreciation, depletion, amortization and impairment		23,229			5,809				8,540				3,170			40,748
Operating income (loss) from continuing operations	$	16,236		$	(2,321	)		$	13,501			$	(1,777	)	$	25,639
Capital Expenditures	$	9,947		$	31			$	6,808			$	18		$	16,804
Segment Assets	$	523,867		$	52,932			$	316,744			$	82,821		$	976,364
Total Segments	Total Midstream			Upstream				Corporate				Total
Six Months Ended June 30, 2010	Business			Segment				Segment				Segments
($ in thousands)
Sales to external customers	$	352,507		$	46,946			$	46,387		(a)	$	445,840
Cost of natural gas and natural gas liquids		258,204			-				-				258,204
Operating costs and other expenses		27,916			18,031		(b)		25,817				71,764
Depreciation, depletion, amortization and impairment		40,748			17,623				835				59,206
Operating income from continuing operations	$	25,639		$	11,292			$	19,735			$	56,666
Capital Expenditures	$	16,804		$	12,392			$	893			$	30,089
Segment Assets	$	976,364		$	358,908			$	53,103			$	1,388,375
Midstream Business	Texas Panhandle			South Texas				East Texas/ Louisiana				Gulf of Mexico			Total Midstream
Six Months Ended June 30, 2009	Segment			Segment				Segment				Segment			Business
($ in thousands)
Sales to external customers	$	134,737		$	59,405			$	103,280			$	14,050		$	311,472
Cost of natural gas and natural gas liquids		101,354			54,888				82,242				10,373			248,857
Operating costs and other expenses		16,201			2,050				9,160				1,076			28,487
Depreciation, depletion, and amortization		22,058			2,708				9,011				2,965			36,742
Operating income (loss) from continuing operations	$	(4,876	)	$	(241	)		$	2,867			$	(364	)	$	(2,614	)
Capital Expenditures	$	3,709		$	15			$	14,077			$	141		$	17,942
Segment Assets	$	552,898		$	68,532			$	327,036			$	89,078		$	1,037,544
Total Segments	Total Midstream			Upstream				Corporate				Total
Six Months Ended June 30, 2009	Business			Segment				Segment				Segments
($ in thousands)
Sales to external customers	$	311,472		$	25,287			$	(48,305	)	(a)	$	288,454
Cost of natural gas and natural gas liquids		248,857			-				-				248,857
Operating costs and other expenses		28,487			10,738		(b)		24,379				63,604
Depreciation, depletion, amortization and impairment		36,742			17,593				431				54,766
Operating income (loss) from continuing operations	$	(2,614	)	$	(3,044	)		$	(73,115	)		$	(78,773	)
Capital Expenditures	$	17,942		$	3,580			$	1,424			$	22,946
Segment Assets	$	1,037,544		$	378,124			$	118,660			$	1,534,328

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

(b)   Includes sulfur disposal costs of $0.7 million and $1.2 million for the three and six months ended June 30, 2010 and 2009, respectively.

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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 and statutory depletion carryforwards of $0.9 million, $1.8 million, $1.9 million, and $3.1 million were used during the three and six months ended June 30, 2010 and 2009, respectively, which resulted in a release of the valuation allowance established for the net operating losses as of December 31, 2009.

 Effective Rate - The effective rate for the six month period ended June 30, 2010 was 1.0% compared to 5.1% for the six month period ended June 30, 2009.   Due to the fact that the effective rate is a ratio of total tax expense compared to pre-tax book income, the change is due primarily to the fact that the Partnership was in a loss position during the six months ended June 30, 2009 versus an income position in the six months ended June 30, 2010.

 Deferred Taxes - As of June 30, 2010, the net deferred tax liability was $38.4 million compared to $38.7 million as of December 31, 2009 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.

 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 Partnership makes appropriate accruals for this tax during the reporting period.

Accounting for Uncertainty in Income Taxes - The Partnership adopted authoritative guidance related to accounting for uncertainty in income taxes on January 1, 2007.  The Partnership has taken a position which is deemed to be “more likely than not” to be upheld upon review, if any, with respect to the deductibility of certain costs for the purpose of its franchise tax liability on a state franchise return.   The Partnership has recorded a provision of the portion of this tax liability equal to the probability of recognition. The Partnership has not accrued interest and penalties as the amounts are estimated to be de minimis. The amount stated below relates to the tax return filed for 2008 which is still open under current statute. A reconcili ation of the beginning and ending amount of the unrecognized tax liabilities is as follows (in thousands):

Balance as of December 31, 2009	$	(267	)
Increases related to prior year tax positions		-
Increases related to current year tax positions		-
Balance as of June 30, 2010	$	(267	)

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NOTE 15. EQUITY-BASED COMPENSATION

Eagle Rock Energy G&P, LLC, the general partner of the general partner for the Partnership has a long-term incentive plan as amended (“LTIP”)  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. In July 2010, the Partnership announced an amendment and restatement of the Partnership’s LTIP.  See Note 19 for further discussion.

A summary of the LTIP restricted common units’ activity for the six months ended June 30, 2010, is provided below:

	Number of Restricted Units			Weighted Average Fair Value
Nonvested at December 31, 2009		1,371,019		$	9.35
Granted		97,511			5.94
Vested		(243,774	)		17.54
Forfeitures		(23,809	)		15.87
Nonvested at June 30, 2010		1,200,947			7.28

For the three and six months ended June 30, 2010 and 2009, non-cash compensation expense of approximately $1.5 million, $3.3 million, $1.9 million and $3.7 million, respectively, was recorded for the granted restricted units under the LTIP.

As of June 30, 2010, unrecognized compensation costs related to the outstanding restricted units under the LTIP totaled approximately $6.6 million. The remaining expense is to be recognized over a weighted average of 1.77 years.

In connection with the vesting of certain restricted units during the three months ended June 30, 2010, 35,842 of the newly-vested common units were cancelled by the Partnership in satisfaction of $0.2 million 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.

In addition to equity awards under the LTIP, 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 three month period ended March 31, 2009, Holdings granted 160,000 “Tier I” incentive interests to one Eagle Rock Energy employee.  In addition, during the three month period ended June 30, 2010, Holdings granted a total of 40,000 Tier I incentive units to two Eagle Rock Energy employees.  The Partnership recorded a portion of the value of the incentive units as compensation expense in the Partnership’s condensed consolidated financial statements.  This allocation is based on manage ment’s estimation of the total value of the incentive unit grant and of the grantees’ portion of time dedicated to the Partnership.  The Partnership recorded non-cash compensation expense of $0.1 million and $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, 2010 and 2009, respectively.

NOTE 16.  EARNINGS PER UNIT

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

As of June 30, 2010 and 2009, the Partnership has unvested restricted common units outstanding.  These units will be considered in the diluted weighted average common unit outstanding number in periods of net income.  In periods of net losses, these units are excluded from the diluted weighted average common unit outstanding number.

For the three and six months ended June 30, 2010, the Partnership determined that it is more dilutive to apply the two-class method versus the treasury stock method in calculating dilutive earnings per unit.  Thus, the unvested restricted common units are included in the computation of the diluted weighted average common unit outstanding calculation, but the denominator in the computation of diluted earnings per unit only includes the basic weighted average common units outstanding.

 Under the Partnership’s original partnership agreement, which was amended and restated on May 24, 2010, in connection with approval of the Recapitalization and Related Transactions, for any quarterly period, incentive distribution rights (“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 and six months ended June 30, 2010 and 2009, the Partnership did not declare a quarterly distribution for the IDRs.  On May 24, 2010, the Partnership’s general partner contributed all of the outstanding IDRs to the Partnership (see Notes 8 and 9), and they were eliminated.

 In addition, all of the subordinated units, as discussed in Notes 8 and 9, were contributed to the Partnership and cancelled on May 24, 2010.  As a result, the number of subordinated units used in the calculation of earnings per unit for the three and six months ended June 30, 2010 is based on the amount of time they were outstanding during those periods.

 The restricted common units granted under the LTIP, as discussed in Note 15, contain non-forfeitable rights to the distributions declared by the Partnership and therefore meet the definition of participating securities.  Participating securities are required to be included in the computation of earnings per unit computation pursuant to the two-class method.

22

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
Basic weighted average units outstanding:
Common units		56,597		53,147		55,344		53,093
Subordinated units		12,278		20,691		16,683		20,691
General partner units		845		845		845		845
Diluted weighted average units outstanding:
Common units		56,805		53,147		55,515		53,093
Subordinated units		12,278		20,691		16,683		20,691
General partner units		845		845		845		845

 The following table presents the Partnership’s basic and diluted income per unit for the three months ended June 30, 2010:

	Total		Common Units		Restricted common Units		Subordinated Units		General Partner Units
	($ in thousands, except for per unit amounts)
Income from continuing operations	$	28,670
Distributions declared		1,462	$	1,415	$	26	$	-	$	21
Assumed income from continuing operations after distribution to be allocated		27,208		21,687		492		4,705		324
Assumed allocation of income from continuing operations		28,670		23,102		518		4,705		345
Discontinued operations		39,473		31,463		714		6,826		470
Assumed net income to be allocated	$	68,143	$	54,565	$	1,232	$	11,531	$	815
Basic and diluted income from continuing operations per unit			$	0.41			$	0.38	$	0.41
Basic and diluted discontinued operations per unit			$	0.56			$	0.56	$	0.56
Basic and diluted income per unit			$	0.96			$	0.94	$	0.96

 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	$	(76,756	)
Distributions declared		1,368		$	1,331		$	16	$	-		$	21
Assumed loss from continuing operations after distribution to be allocated		(78,124	)		(55,596	)		-		(21,645	)		(883	)
Assumed allocation of loss from continuing operations		(76,756	)		(54,265	)		16		(21,645	)		(862	)
Discontinued operations		1,969			1,401			-		546			22
Assumed net loss to be allocated	$	(74,787	)	$	(52,864	)	$	16	$	(21,099	)	$	(840	)
Basic and diluted loss from continuing operations per unit				$	(1.02	)			$	(1.05	)	$	(1.02	)
Basic and diluted discontinued operations per unit				$	0.03				$	0.03		$	0.03
Basic and diluted loss per unit				$	(0.99	)			$	(1.02	)	$	(0.99	)

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 The following table presents the Partnership’s basic and diluted income per unit for the six months ended June 30, 2010:

	Total		Common Units		Restricted common Units		Subordinated Units		General Partner Units
	($ in thousands, except for per unit amounts)
Income from continuing operations	$	28,807
Distributions declared		2,867	$	2,770	$	55	$	-	$	42
Assumed income from continuing operations after distribution to be allocated		25,940		19,346		467		5,832		295
Assumed allocation of income from continuing operations		28,807		22,116		522		5,832		337
Discontinued operations		43,317		32,306		779		9,739		493
Assumed net income to be allocated	$	72,124	$	54,422	$	1,301	$	15,571	$	830
Basic and diluted income from continuing operations per unit			$	0.40			$	0.35	$	0.40
Basic and diluted discontinued operations per unit			$	0.58			$	0.58	$	0.58
Basic and diluted income per unit			$	0.98			$	0.93	$	0.98

 The following table presents the Partnership’s basic and diluted income 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	$	(81,119	)
Distributions declared		2,736		$	2,657		$	37	$	-		$	42
Assumed loss from continuing operations after distribution to be allocated		(83,855	)		(59,656	)		-		(23,250	)		(949	)
Assumed allocation of loss from continuing operations		(81,119	)		(56,999	)		37		(23,250	)		(907	)
Discontinued operations		3,787			2,694			-		1,050			43
Assumed net loss to be allocated	$	(77,332	)	$	(54,305	)	$	37	$	(22,200	)	$	(864	)
Basic and diluted loss from continuing operations per unit				$	(1.07	)			$	(1.12	)	$	(1.07	)
Basic and diluted discontinued operations per unit				$	0.05				$	0.05		$	0.05
Basic and diluted loss per unit				$	(1.02	)			$	(1.07	)	$	(1.02	)

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NOTE 17.  DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE

 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 received a contingency payment of $0.1 million in October 2009. The Partnership will also continue to receive a monthly payment equivalent to $0.01 per MMbtu on the volume of gas that flows pursuant to the assigned contracts through March 31, 2011.  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 three and six months ended June 30, 2010, this business generated revenues of less than $0.1 million and no cost of natural gas and NGLs.  During the three and six months ended June 30, 2009, this business generated revenues of $19.2 million and cost of natural gas and NGLs of $19.0 million.  For the three and six months ended June 30, 2010, less than $0.1 million of revenues minus the cost of natural gas and NGLs have been reported as discontinued operations, as compared to revenues minus the cost of natural gas and NGLs of $0.2 million for the three and six months ended June 30, 2009.

 On May 24, 2010, the Partnership completed the sale of all of its fee mineral and royalty interests as well as its equity investment in Ivory Working Interests, L.P. (collectively, the “Minerals Business”), for which it received net proceeds of approximately $171.6 million in cash after purchase price adjustments made to reflect an effective date of January 1, 2010 for the sale, as established in the agreement governing the sale. The Partnership retained approximately $2.9 million of cash from net revenues received from the Minerals Business after the effective date.  The Partnership recorded a gain of $37.7 million on the sale, which is recorded as part of discontinued operations for the three and six months ended June 30, 2010.  Further upward or downward adjustments to the purcha se price may occur post-closing to reflect customary true-ups.  For the three and six months ended June 30, 2010, the Minerals Business generated revenues of $3.3 million and $8.9 million, respectively, and income (loss) from operations of $1.8 million and $5.6 million, respectively.   For the three and six months ended June 30, 2009, the Minerals Business generated revenues of $3.5 million and $6.7 million, respectively, and income from operations of $1.7 million and $2.8 million, respectively.  During the three and six months ended June 30, 2010 and 2009, the Minerals Business incurred state tax expense on discontinued operations of $0.4 million, $0.4 million, less than $0.1 million and $0.1 million, respectively. During the three and six months ended June 30, 2010 and 2009, the Minerals Business recorded a gain to discontinued operations of $2.2 million, $6.0 million, $2.0 million and $3.5 million, respectively, excluding the gain recognized by the Partnership on the sal e of the Minerals Business.

 Assets and liabilities held for sale represent the assets and liabilities of the Partnership’s Minerals Business.  As of December 31, 2009, assets held for sale consists of the following: (i) accounts receivable of $3.0 million, (ii) net proved reserves of $55.2 million, (iii) unproved reserves of $64.9 million and (iv) the Partnership’s equity investment in Ivory Working Interests, L.P. of $12.0 million.  As of December 31, 2009, liabilities held for sale was made up of accounts payable.

NOTE 18.  SUBSIDIARY GUARANTORS

 In the future, the Partnership may issue registered debt securities guaranteed by its subsidiaries.  The Partnership expects that all guarantors would be wholly-owned and that such guarantees would be joint and several and full and unconditional.  In accordance with practices accepted by the SEC, the Partnership has prepared Condensed Consolidated Financial Statements as supplemental information.  The following Condensed Consolidated Balance Sheets at June 30, 2010 and December 31, 2009 and Condensed Consolidated Statements of Operations and Condensed Consolidated Statements of Cash Flows for the three and six months ended June 30, 2010 and 2009, present financial information for Eagle Rock Energy Partners, L.P. as the Parent on a stand-alone basis (carrying any investments in subsidi aries under the equity method), financial information for the subsidiary guarantors, which are all fully owned by the Parent, on a stand-alone basis, financial information for the subsidiary non-guarantors, which are all partially owned by the Parent and not consolidated, on a stand-alone basis, and the consolidation and elimination entries necessary to arrive at the information for the Partnership on a consolidated basis.  The subsidiary guarantors are not restricted from making distributions to the Partnership.

Unaudited Condensed Consolidated Balance Sheet
June 30, 2010
($ in thousands)	Parent Issuer		Subsidiary Guarantors		Non-guarantor investments		Consolidating Entries			Total
ASSETS:
Accounts receivable – related parties	$	-	$	110,638	$	-	$	(110,638	)	$	-
Other current assets		19,123		78,867		-		-			97,990
Total property, plant and equipment, net		663		1,138,674		-		-			1,139,337
Investment in subsidiaries		1,287,372		-		-		(1,287,372	)		-
Total other long-term assets		24,396		125,502		1,150		-			151,048
Total assets	$	1,331,554	$	1,453,681	$	1,150	$	(1,398,010	)	$	1,388,375
LIABILITIES AND EQUITY:
Accounts payable – related parties	$	110,638	$	-	$	-	$	(110,638	)	$	-
Other current liabilities		33,034		98,811		-		-			131,845
Other long-term liabilities		17,931		68,648		-		-			86,579
Long-term debt		565,383		-		-		-			565,383
Equity		604,568		1,286,222		1,150		(1,287,372	)		604,568
Total liabilities and equity	$	1,331,554	$	1,453,681	$	1,150	$	(1,398,010	)	$	1,388,375

Unaudited Condensed Consolidated Balance Sheet
December 31, 2009
($ in thousands)	Parent Issuer		Subsidiary Guarantors		Non-guarantor investments		Consolidating Entries			Total
ASSETS:
Accounts receivable – related parties	$	87,433	$	-	$	-	$	(87,433	)	$	-
Assets held for sale		-		135,224		-		-			135,224
Other current assets		5,171		90,952		-		-			96,123
Total property, plant and equipment, net		212		1,155,521		-		-			1,155,733
Investment in subsidiaries		1,245,589		-		-		(1,245,589	)		-
Total other long-term assets		4,415		141,628		1,205		-			147,248
Total assets	$	1,342,820	$	1,523,325	$	1,205	$	(1,333,022	)	$	1,534,328
LIABILITIES AND EQUITY:
Accounts payable – related parties	$	-	$	87,433	$	-	$	(87,433	)	$	-
Liabilities held for sale		-		150		-		-			150
Other current liabilities		42,099		113,933		-		-			156,032
Other long-term liabilities		15,940		77,425		-		-			93,365
Long-term debt		754,383		-		-		-			754,383
Equity		530,398		1,244,384		1,205		(1,245,589	)		530,398
Total liabilities and equity	$	1,342,820	$	1,523,325	$	1,205	$	(1,333,022	)	$	1,534,328

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Unaudited Condensed Consolidated Statement of Operations
For the three months ended June 30, 2010
($ in thousands)	Parent Issuer			Subsidiary Guarantors			Non-guarantor investments			Consolidating Entries			Total
Total revenues	$	28,515		$	194,365		$	-		$	-		$	222,880
Cost of natural gas and natural gas liquids		-			113,926			-			-			113,926
Operations and maintenance		-			20,364			-			-			20,364
Taxes other than income		1			2,810			-			-			2,811
General and administrative		2,249			10,557			-			-			12,806
Depreciation, depletion, and impairment		78			31,102			-			-			31,180
Income from operations		26,187			15,606			-			-			41,793
Interest expense, net		(3,833	)		-			-			-			(3,833	)
Other non-operating income		2,049			650			(21	)		(2,526	)		152
Other non-operating expense		(4,184	)		(8,199	)		-			2,526			(9,857	)
Income before income taxes		20,219			8,057			(21	)		-			28,255
Income tax provision (benefit)		-			(415	)		-			-			(415	)
Equity in earnings of subsidiaries		47,924			-			-			(47,924	)		-
Income from continuing operations		68,143			8,472			(21	)		(47,924	)		28,670
Discontinued operations		-			39,473			-			-			39,473
Net income	$	68,143		$	47,945		$	(21	)	$	(47,924	)	$	68,143

Unaudited Condensed Consolidated Statement of Operations
For the three months ended June 30, 2009
($ in thousands)	Parent Issuer			Subsidiary Guarantors			Non-guarantor investments		Consolidating Entries			Total
Total revenues	$	(18,691	)	$	110,690		$	-	$	-		$	91,999
Cost of natural gas and natural gas liquids		-			115,640			-		-			115,640
Operations and maintenance		-			19,049			-		-			19,049
Taxes other than income		-			2,580			-		-			2,580
General and administrative		354			11,512			-		-			11,866
Other operating income		-			(3,552	)							(3,552	)
Depreciation, depletion, and impairment		-			26,136			-		-			26,136
Loss from operations		(19,045	)		(60,675	)		-		-			(79,720	)
Interest expense, net		(5,428	)		-			-		-			(5,428	)
Other non-operating income		1,727			712			56		(2,155	)		340
Other non-operating expense		1,173			3,212			-		2,155			6,540
Income (loss) before income taxes		(21,573	)		(56,751	)		56		-			(78,268	)
Income tax benefit		(33	)		(1,479	)		-		-			(1,512	)
Equity in earnings of subsidiaries		(53,247	)		-			-		53,247			-
Income (loss) from continuing operations		(74,787	)		(55,272	)		56		53,247			(76,756	)
Discontinued operations		-			1,969			-		-			1,969
Net income (loss)	$	(74,787	)	$	(53,303	)	$	56	$	53,247		$	(74,787	)

Unaudited Condensed Consolidated Statement of Operations
For the six months ended June 30, 2010
($ in thousands)	Parent Issuer			Subsidiary Guarantors			Non-guarantor investments			Consolidating Entries			Total
Total revenues	$	30,037		$	415,803		$	-		$	-		$	445,840
Cost of natural gas and natural gas liquids		-			258,204			-			-			258,204
Operations and maintenance		-			39,599			-			-			39,599
Taxes other than income		2			6,346			-			-			6,348
General and administrative		4,985			20,832			-			-			25,817
Depreciation, depletion, and impairment		82			59,124			-			-			59,206
Income from operations		24,968			31,698			-			-			56,666
Interest expense, net		(7,978	)		-			-			-			(7,978	)
Other non-operating income		4,053			1,221			(15	)		(5,006	)		253
Other non-operating expense		(8,213	)		(16,631	)		-			5,006			(19,838	)
Income before income taxes		12,830			16,288			(15	)		-			29,103
Income tax provision		827			(531	)		-			-			296
Equity in earnings of subsidiaries		60,121			-			-			(60,121	)		-
Income from continuing operations		72,124			16,819			(15	)		(60,121	)		28,807
Discontinued operations		-			43,317			-			-			43,317
Net income	$	72,124		$	60,136		$	(15	)	$	(60,121	)	$	72,124

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Unaudited Condensed Consolidated Statement of Operations
For the six months ended June 30, 2009
($ in thousands)	Parent Issuer			Subsidiary Guarantors			Non-guarantor investments		Consolidating Entries			Total
Total revenues	$	(25,771	)	$	314,225		$	-	$	-		$	288,454
Cost of natural gas and natural gas liquids		-			248,857			-		-			248,857
Operations and maintenance		-			37,690			-		-			37,690
Taxes other than income		-			5,087			-		-			5,087
General and administrative		396			23,983			-		-			24,379
Other operating income		-			(3,552	)		-		-			(3,552	)
Depreciation, depletion, and impairment		-			54,766			-		-			54,766
Loss from operations		(26,167	)		(52,606	)		-		-			(78,773	)
Interest expense, net		(12,967	)		-			-		-			(12,967	)
Other non-operating income		3,435			1,234			85		(4,299	)		455
Other non-operating expense		288			1,303			-		4,299			5,890
Income (loss) before income taxes		(35,411	)		(50,069	)		85		-			(85,395	)
Income tax provision (benefit)		19			(4,295	)		-		-			(4,276	)
Equity in earnings of subsidiaries		(41,902	)		-			-		41,902			-
Income (loss) from continuing operations		(77,332	)		(45,774	)		85		41,902			(81,119	)
Discontinued operations		-			3,787			-		-			3,787
Net income (loss)	$	(77,332	)	$	(41,987	)	$	85	$	41,902		$	(77,332	)

Condensed Consolidated Statement of Cash Flows
For the six months ended June 30, 2010
($ in thousands)	Parent Issuer			Subsidiary Guarantors			Non-guarantor investments			Consolidating Entries		Total
Net cash flows provided by (used in) operating activities	$	199,456		$	(155,292	)	$	54		$	-	$	44,218
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment		(532	)		(23,378	)		-			-		(23,910	)
Purchase of intangible assets		-			(968	)		-			-		(968	)
Proceeds from sale of asset		-			171,664			-			-		171,664
Net cash flows provided by (used in) investing activities		(532	)		147,318			-			-		146,786
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt		36,000			-			-			-		36,000
Repayment of long-term debt		(225,000	)		-			-			-		(225,000	)
Proceeds from derivative contracts		-			628			-			-		628
Deferred transaction fees		(2,557	)		-			-			-		(2,557	)
Repurchase of common units		(219	)		-			-			-		(219	)
Distributions to members and affiliates		(3,024	)		-			-			-		(3,024	)
Net cash flows (used in) provided by financing activities		(194,800	)		628			-			-		(194,172	)
Net cash flows provided by discontinued operations		-			6,757			-			-		6,757
Net (decrease) increase in cash and cash equivalents		4,124			(589	)		54			-		3,589
Cash and cash equivalents at beginning of year		4,922			(2,179	)		(11	)		-		2,732
Cash and cash equivalents at end of year	$	9,046		$	(2,768	)	$	43		$	-	$	6,321

Condensed Consolidated Statement of Cash Flows
For the six months ended June 30, 2009
($ in thousands)	Parent Issuer			Subsidiary Guarantors			Non-guarantor investments			Consolidating Entries		Total
Net cash flows (used in) provided by operating activities	$	3,113		$	18,609		$	(11	)	$	-	$	21,711
CASH FLOWS FROM INVESTING ACTIVITIES:					-
Additions to property, plant and equipment		(472	)		(25,029	)		-			-		(25,501	)
Purchase of intangible assets		-			(1,109	)		-			-		(1,109	)
Net cash flows used in investing activities		(472	)		(26,138	)		-			-		(26,610	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt		123,000			-			-			-		123,000
Repayment of long-term debt		(118,000	)		-			-			-		(118,000	)
Proceeds from derivative contracts		-			6,774			-			-		6,774
Distributions to members and affiliates		(32,904	)		-			-			-		(32,904	)
Net cash flows (used in) provided by financing activities		(27,904	)		6,774			-			-		(21,130	)
Net cash flows provided by discontinued operations		-			10,244			-			-		10,244
Net (decrease) increase in cash and cash equivalents		(25,263	)		9,489			(11	)		-		(15,785	)
Cash and cash equivalents at beginning of year		29,272			(11,356	)		-			-		17,916
Cash and cash equivalents at end of year	$	4,009		$	(1,867	)	$	(11	)	$	-	$	2,131

NOTE 19.  SUBSEQUENT EVENTS

On July 8, 2010, the Partnership received gross proceeds of $53.9 million and issued 21,557,164 common units and 21,557,164 warrants pursuant to the rights offering, which expired on June 30, 2010.  In July 2010, the Partnership used the proceeds received from the rights offering to repay an additional $50.0 million towards its outstanding borrowings under the revolving credit facility.

On July 27, 2010, the Partnership exercised the GP Acquisition Option. The transaction was closed on July 30, 2010 and the Partnership issued 1,000,000 common units to Holdings to acquire the Partnership’s general partner entities.  As a result, the Partnership’s 844,551 outstanding general partner units were cancelled.  The acquisition of its general partner triggered a change of control under certain award agreements for outstanding restricted common units awarded under the Partnership’s LTIP and the accelerated vesting of the 315,607 affected outstanding restricted units.  As a result, the Partnership will recognize an additional $2.8 million in equity-based compensation in the third quarter of 2010.  Of these newly vested common units, 84,086 were cancelled by the Part nership  in satisfaction of $0.5 million related employee tax liability paid by the Partnership.   In connection with the completion of the GP Acquisition Option, the Partnership's board of directors (the "Board") was expanded to include two additional independent directors who were appointed by the Conflicts Committee on July 30, 2010.

 On July 28, 2010, the Partnership announced that its Board had approved and adopted an amendment and restatement of the Partnership's LTIP, subject to unitholder approval at a special meeting of its unitholders to be held on September 17, 2010  (the “LTIP Proposal”). Approval of the LTIP Proposal requires an affirmative vote of a majority of the votes cast by unitholders at the special meeting, and the Partnership requires 50% of its outstanding common units, present in person or represented by proxy, to constitute a quorum.

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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, 2009, 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 two 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; and

• Upstream Business—acquiring, developing and producing hydrocarbons from oil and natural gas property interests.

 We report on our businesses in six 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, 2010, our Midstream Business generated operating income from continuing operations of $13.2 million and $25.6 million, respectively, compared to operating income from continuing operations of $3.5 million and an operating loss from continuing operations of $2.6 million during the three and six months ended June 30, 2009, 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.  During the three and six months ended June 30, 2010, our Upstream Business generated operating income of $6.3 million and $11.3 million, respectively, compared to operating income of $3.4 million and an operating loss of $3.0 million, respectively, during the three and six months ended June 30, 2009.  O f important note, sales of sulfur generated revenue of $2.1 million and $3.2 million, respectively, during the three and six months ended June 30, 2010, compared to disposal costs of sulfur, in excess of the revenue, of $0.7 million and $1.2 million, respectively, during the three and six months ended June 30, 2009.

 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, 2010, our Corporate Segment generated operating income of $22.3 million and $19.7 million, respectively, compared to an operating loss of $86.6 million and $73.1 million during the three and six months ended June 30, 2009, respectively.  Within these numbers were gains, realized and unrealized, on commodity derivatives of $35.6 million and $46.4 million during the three and six months ended June 30, 2010, respectively, compared to 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.

 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 (both entities which we, directly or indirectly, own effective as of July 30, 2010, collectively the  “general partner”), who in turn is managed by the nine members of its board of directors (the “Board of Directors”), three of whom are appointed by Natural Gas Partners, one of whom is our Chief Executive Officer, and the other five of whom are elected by our unitholders staggered over a three year period.  For more information regarding our Board of Directors or our ownership of our general partner and its general partner, see “Subsequent Events” below.

Impairment

 In connection with the preparation of our unaudited condensed consolidated financial statements for the three and six months ended June 30, 2010, we recorded $3.1 million in impairment charges within our Midstream Segment due to the loss of a significant gathering contract in our South Texas Segment.  In addition, for the three and six months ended June 30, 2009, we recorded $0.2 million in impairment charges 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.

 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 or upstream 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 debt or equity securities, or the incurrence of additional debt under our revolving credit facility, on terms acceptable to us.  See further discussion under “Liquidity and Capital Resources.”

Recent Transactions

Borrowing Base Redetermination

 On April 19, 2010, we announced that the borrowing base under our revolving credit facility, which relates to our Upstream Business, was set at $130 million from $135 million by our commercial lenders as part of our regularly scheduled semi-annual borrowing base redetermination.  The redetermined borrowing base was effective April 1, 2010, with no additional fees or increase in interest rate spread incurred.

Recapitalization and Related Transactions

 On December 21, 2009, we announced that we, through certain of our affiliates, had entered into definitive agreements with affiliates of Natural Gas Partners ("NGP" and collectively with such affiliates, the “NGP Parties”) and Black Stone to improve our liquidity and simplify our capital structure.  The definitive agreements include:  (i) a Securities Purchase and Global Transaction Agreement, entered into between us and the NGP Parties, including our general partner entities controlled by NGP, and (ii) a Purchase and Sale Agreement (the “Minerals Business Sale Agreement”), entered into between us and Black Stone for the sale of our Minerals Business.  The Securities Purchase and Global Transaction Agreement was amended and restated on January 12, 2010 to allow for greater flexibility in the payment of the contemplated transaction fee to Eagle Rock Holdings, L.P. ("Holdings"), which is controlled by NGP (we refer to the amended Securities Purchase and Global Transaction Agreement throughout this document as the “Global Transaction Agreement”).

 We filed a copy of the Minerals Business Sale Agreement, and the Global Transaction Agreement and related ancillary agreements, on Form 8-K with the SEC on December 21, 2009 and January 12, 2010, respectively.

28

 On May 21, 2010, a majority of our unitholders who are not affiliated with our general partner approved, among other things, the Global Transaction Agreement, which contemplates a series of transactions that seek to simplify and recapitalize the Partnership, including:

·   the simplification of our capital structure through the contribution, and resulting cancellation, of our incentive distribution rights and 20,691,495 subordinated units held by Holdings;

·   the sale of our minerals business to Black Stone Minerals Company, L.P.;

·   the rights offering, for which Holdings and the NGP Parties agreed to fully participate by exercising all rights issued in respect of 14,369,931 common and general partner units owned by them (which includes 4,825,211 common units issued to them on May 24, 2010 in payment of a transaction fee contemplated by the Global Transaction Agreement); and

·   the GP Acquisition Option, exercisable by the issuance of 1,000,000 newly-issued common units to Holdings, to capture the value of the controlling interest in us through (a) acquiring our general partner entities from Holdings and immediately thereafter eliminating our 844,551 outstanding general partner units and (b) reconstituting our Board to allow our common unitholders not affiliated with NGP to elect the majority of our directors.  The GP Acquisition Option was closed on July 30, 2010.

 In addition, pursuant to the Global Transaction Agreement, until September 21 (or until October 21 under certain circumstances) NGP is obligated, at the sole discretion of our conflicts committee, to purchase up to $41.6 million, at a price of $3.10 per unit, of an Eagle Rock Energy equity offering.  As of the date of this filing, our Conflicts Committee has determined that it is not in our best interests to either initiate marketing of an equity offering or require NGP to purchase equity in its back-stop, but our conflicts committee will continue to review the matter during the remaining time period covering NGP’s equity back-stop.

 The sale of the Minerals Business was closed on May 24, 2010 and the final purchase price was $171.6 million.

 The subordinated units and incentive distribution rights were contributed and subsequently cancelled on May 24, 2010.

 The rights offering was launched on June 1, 2010 and expired on June 30, 2010.

Minerals Business Sale

  �� On May 24, 2010, we completed the sale of all of our fee mineral and royalty interests as well as our equity investment in Ivory Working Interests, L.P. (collectively, the “Minerals Business”), for which we received net proceeds of approximately $171.6 million in cash after purchase price adjustments made to reflect an effective date of January 1, 2010 for the sale, as established in the agreement governing the sale. We retained approximately $2.9 million net of cash from net revenues received from the Minerals Business after the effective date, making our total proceeds from the Minerals Business $174.5 million since January 1, 2010. Further upward or downward adjustments to the purchase price may occur post-closing to reflect customary true-ups.
60; Operations related to the Minerals Business for the three and six months ended June 30, 2010, have been recorded as part of the discontinued operations.  Financial information related to the Minerals Business for the three months ended March 31, 2010 and the three and six months ended June 30, 2009 has been retrospectively adjusted to reflect assets and liabilities held-for-sale and discontinued operations.  See further discussion within Item 2. “Results of Operations – Corporate Segment”.

 Simplification of Capital Structure; Payment of Transaction Fee

 Pursuant to the Global Transaction Agreement, on May 24, 2010, our general partner and Holdings contributed to us all 20,691,495 of our outstanding subordinated units and all of our outstanding incentive distribution rights.  In connection with the contribution of the subordinated units and incentive distribution rights, we (i) issued 4,825,211 common units to Holdings as payment of the transaction fee contemplated by the Global Transaction Agreement and (ii) adopted and entered into a Second Amended and Restated Agreement of Limited Partnership.

 Pursuant to our Second Amended and Restated Agreement of Limited Partnership, among other things, (i) our subordinated units and incentive distribution rights were cancelled, (ii) the concepts of a subordination period and a minimum quarterly distribution (and, as a result, the concept of arrearages on the common units) were eliminated and (iii) provisions were included that provided for us, upon exercise of the GP Acquisition Option, to acquire our general partner entities which, we acquired on July 30, 2010, and is discussed further in “Subsequent Events” below.

 For more information about the simplification transactions and the Second Amended and Restated Agreement of Limited Partnership, please see our Current Report on Form 8-K filed with the Securities and Exchange Commission on May 25, 2010.

Credit Facility Amendment

 On March 8, 2010, we entered into the Second Amendment (the “Credit Facility Amendment”) to our credit agreement, dated as of December 13, 2007, with Wachovia Bank, N.A., Bank of America, N.A., HSH NordBank AG, New York Branch, The Royal Bank of Scotland, PLC, BNP Paribas and the other lenders party thereto.  In connection with our unitholders’ approval of the Global Transaction Agreement and related matters, the Credit Facility Amendment became effective.

 The Credit Facility Amendment modified the definition of “Change in Control” in such a way that our exercise of the GP Acquisition Option did not trigger a “Change in Control” event and potential default; see “—General Partner Acquisition Option.”  In addition to modifying the definition of “Change in Control,” the Credit Facility Amendment also:

·   reduces the maximum permitted Senior Secured Leverage Ratio (as such term is defined in our credit agreement) from 4.25 to 1.0 under the current credit agreement to 3.75 to 1.0 (and from 4.75 to 1.0 to 4.25 to 1.0 for specified periods following certain permitted acquisitions). The Senior Secured Leverage Ratio covenant is only relevant if we have unsecured senior or subordinated notes outstanding;

·   obligated us to use $100 million of the proceeds from the sale of our Minerals Business (described above) to make a mandatory prepayment towards our outstanding borrowings under the revolving credit facility, which mandatory prepayment was made on May 25, 2010; and

·   reduced, upon such mandatory prepayment, our borrowing capacity under the revolving credit facility by the $100 million amount of such mandatory prepayment; however, this did not impact our availability under our revolving credit facility because it is limited by compliance with financial covenants.

 The Credit Facility Amendment further clarifies that the proceeds from the sale of our Minerals Business in excess of $100 million may be used to immediately reduce debt, but will not result in a mandatory prepayment unless such proceeds are not reinvested in Property (as defined in our credit agreement) within the 270-day post-closing period (i.e. by February 18, 2011) provided in our credit agreement.  On May 28, 2010, we repaid an additional $72 million towards our outstanding borrowings under the revolving credit facility from proceeds from the sale of our Minerals Business.

Subsequent Events

On July 8, 2010, we received gross proceeds of $53.9 million and issued 21,557,164 common units and 21,557,164 warrants pursuant to the rights offering, which expired on June 30, 2010.  In July 2010, we used the proceeds received from the rights offering to repay an additional $50.0 million towards our outstanding borrowings under our revolving credit facility.  It is our intention to use proceeds from warrants being exercised, if any, to pay down borrowings outstanding under our revolving credit facility, absent any organic growth or acquisition opportunities.

On July 27, 2010, we exercised the GP Acquisition Option.  The transaction was closed on July 30, 2010 and we issued 1,000,000 common units to Holdings to acquire our general partner entities.  As a result, our 844,551 outstanding general partner units were cancelled.  The acquisition of our general partner triggered a change of control under certain award agreements for outstanding restricted common units awarded under our long-term incentive plan (“LTIP”); as a result, the vesting of the 315,607 affected outstanding restricted units was accelerated, causing us to recognize an additional $2.8 million in equity-based compensation in our upcoming third quarter.  Of these newly vested common units, 84,086 were cancelled by us in satisfaction of $0.5 million related employee tax liability pa id by us.   In connection with the completion of the GP Acquisition Option, our board of directors (the "Board") was expanded to include two additional independent directors who were appointed by the Conflicts Committee on July 30, 2010,  and we entered into the following amendments and agreements: (i) Amendment to the Second Amended and Restated Agreement of Limited Partnership, dated as of July 27, 2010; (ii) Third Amended and Restated Limited Liability Company Agreement of Eagle Rock Energy G&P, LLC, dated as of July 30, 2010; and (iii) Administrative Services Agreement, dated as of July 30, 2010, between us and Eagle Rock G&P, LLC, which replaces the Omnibus Agreement between us and Eagle Rock Energy G&P, LLC. For more information about these amendments and agreements, please see our Current Report on Form 8-K filed with the Securities and Exchange Commission on July 30, 2010.

On July 28, 2010, we announced that our Board had approved and adopted an amendment and restatement of the Partnership's LTIP, subject to unitholder approval of a special meeting of our unitholders to be held on September 17, 2010 where holders of record on July 30, 2010 will vote on the approval (the "LTIP Proposal") of the amendment and restatement of the Partnership's LTIP. Approval of the LTIP Proposal requires an affirmative vote of a majority of the votes cast by unitholders at the special meeting and we require 50% of our outstanding common units, present in person or represented by proxy, to constitute a quorum.

29

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”).

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, 2009. In particular, we continue to be affected by: volatility in commodity prices including the prices for crude oil, natural gas, NGLs, condensate, and sulfur, among others; the 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; and 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 or our interpretations of available information prove to be incorrect, our actual results may vary materially f rom our expected results.

Cautionary Note Regarding Forward-Looking Statements

 Certain matters discussed in this report, excluding historical information, include certain “forward-looking” statements. 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.&# 160; 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, 2009, filed with the Securities and Exchange Commission on March 9, 2010, as well as the risks disclosed in Part II, Item 1A below.

30

RESULTS OF OPERATIONS

Summary of Consolidated Operating Results

Below is a summary table of our consolidated operating results for the three and six months ended June 30, 2010 and 2009, respectively. Operating results for our individual operating segments are presented in tables in this Item 2.

	Three Months						Six Months
	Ended June 30,						Ended June 30,
	2010			2009			2010			2009
	($ in thousands)
REVENUE:
Natural gas, natural gas liquids, oil, condensate and sulfur sales	$	170,998		$	153,320		$	370,294		$	311,810
Gathering, compression, processing and treating fees		16,541			11,562			29,374			23,229
Unrealized commodity derivative gains (losses)		41,405			(97,044	)		54,883			(101,566	)
Realized commodity derivative (losses) gains		(5,813	)		22,483			(8,496	)		53,261
Other revenue		(251	)		1,678			(215	)		1,720
Total revenue		222,880			91,999			445,840			288,454
COSTS AND EXPENSES:
Cost of natural gas and natural gas liquids		113,926			115,640			258,204			248,857
Operations and maintenance		20,364			18,751			39,599			36,921
Taxes other than income		2,811			2,878			6,348			5,856
General and administrative		12,806			11,866			25,817			24,379
Other operating income		-			(3,552	)		-			(3,552	)
Impairment		3,130			-			3,130			242
Depreciation, depletion and amortization		28,050			26,136			56,076			54,524
Total costs and expenses		181,087			171,719			389,174			367,227
OPERATING  INCOME (LOSS)		41,793			(79,720	)		56,666			(78,773	)
OTHER INCOME (EXPENSE):
Interest income		173			141			175			172
Other (expense) income		(21	)		199			78			283
Interest expense		(3,833	)		(5,428	)		(7,978	)		(12,967	)
Realized interest rate derivative losses		(4,952	)		(5,147	)		(9,842	)		(8,629	)
Unrealized interest rate derivative (losses) gains		(4,354	)		11,954			(9,176	)		15,053
Other expense		(551	)		(267	)		(820	)		(534	)
Total other (expense) income		(13,538	)		1,452			(27,563	)		(6,622	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		28,255			(78,268	)		29,103			(85,395	)
INCOME TAX (BENEFIT) PROVISION		(415	)		(1,512	)		296			(4,276	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		28,670			(76,756	)		28,807			(81,119	)
DISCONTINUED OPERATIONS, NET OF TAX		39,473			1,969			43,317			3,787
NET INCOME (LOSS)	$	68,143		$	(74,787	)	$	72,124		$	(77,332	)
ADJUSTED EBITDA (a)	$	32,085		$	41,594		$	63,780		$	79,956

(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.

 Adjusted EBITDA, for the three and six months ended June 30, 2010 and 2009, excludes amortization of commodity hedge costs (including costs of hedge reset transactions) of $0.4 million, $3.1 million, $11.1 million and $23.3 million, respectively.  Including these amortization costs, our Adjusted EBITDA for the three and six months ended June 30, 2010 and 2009 would have been $31.7 million, $60.7 million, $30.5 million and $56.7 million, respectively.

31

Midstream Business (Four Segments)

Texas Panhandle Segment

	Three Months						Six Months
	Ended June 30,						Ended June 30,
	2010			2009			2010			2009
	($ in thousands, except prices and volumes)
REVENUE:
Natural gas, natural gas liquids, oil, condensate and sulfur sales	$	80,955		$	66,373		$	171,688		$	129,323
Gathering and treating services		3,048			2,601			5,990			5,414
Total revenue		84,003			68,974			177,678			134,737
Cost of natural gas and natural gas liquids		54,732			49,407			121,702			101,354
Operating costs and expenses:
Operations and maintenance		8,413			8,056			16,511			16,201
Depreciation, depletion and amortization		11,639			10,962			23,229			22,058
Total operating costs and expenses		20,052			19,018			39,740			38,259
Operating income (loss)	$	9,219		$	549		$	16,236		$	(4,876	)
Capital expenditures	$	7,743		$	766		$	9,947		$	3,709
Realized average prices:
Oil and condensate (per Bbl)	$	67.37		$	59.08		$	67.89		$	53.69
Natural gas (per MMbtu)	$	3.45		$	2.66		$	4.28		$	3.06
NGLs (per Bbl)	$	45.95		$	29.82		$	47.08		$	27.26
Production volumes:
Gathering volumes (Mcf/d) (a)		132,625			143,281			130,570			143,740
NGLs (net equity gallons) (b)		9,856,420			11,815,414			19,412,403			22,450,463
Condensate (net equity gallons) (b)		11,312,296			9,813,579			20,013,928			16,006,005
Natural gas short position (MMbtu/d) (a)		(7,134	)		(5,748	)		(5,725	)		(5,943	)

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

(b)   Installation of additional measurement facilities in January 2010 has improved the measurement of NGLs and condensate volumes resulting in increased equity condensate volumes and a corresponding decrease in equity NGL volumes.

Revenues and Cost of Natural Gas and Natural Gas Liquids. For the three and six months ended June 30, 2010, revenues minus cost of natural gas and NGLs for our Texas Panhandle Segment operations totaled $29.3 million and $56.0 million, respectively, compared to $19.6 million and $33.4 million, respectively, for the three and six months ended June 30, 2009.  The increase is primarily driven by the higher NGL, natural gas and condensate pricing as compared to pricing in 2009.  This increase for the six months ended June 30, 2010 was partially offset by inclement weather during the first quarter of 2010, which management estimates negatively impacted operating income in the Texas Panhandle Segment by approximately $1.0 million.

The lower gathering volumes during the three and six months ended June 30, 2010 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 and early 2010.   The dramatic fall in commodity prices experienced in the latter part of 2008 and continuing throughout 2009 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 and six months ended June 30, 2009, natural gas prices have not recovered to levels that have caused our producers to increase drilling activity back to the levels experienced in 2008.

 Our Texas Panhandle Segment primarily covers ten counties in Texas and consists of our East Panhandle System and our West Panhandle System. 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 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 and continuing through the first nine months of 2009, we experienced a significant decline in drilling activity in this area.

 Drilling in the Granite Wash play during 2010, utilizing horizontal drilling technologies, has resulted in initial natural gas production rates ranging from 2 MMcf/d to 18 MMcf/d of natural gas.  Operators in the Granite Wash play 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 we will benefit in the future due to the application of this technology in the Granite Wash play with increased natural gas and co ndensate production in the East Panhandle System.  In February 2010, we announced our intention to deploy a currently idle high-efficiency cryogenic plant to the Texas Panhandle in order to increase efficiency and accommodate volume growth from the Granite Wash Play. Deployment of the cryogenic plant (the “Phoenix Plant”), in replacement of an aging facility, is phase two of our Texas Panhandle consolidation and processing capacity expansion project originally announced in February 2008.  The project is scheduled to be completed in late third quarter 2010.   The Phoenix plant will have initial capacity of 50 MMcf/d with the ability to expand to 80 MMcf/d.  Following the completion and startup of the Phoenix Plant, we will idle our Canadian Plant Facility and consolidate its volumes back to our new Phoenix Plant. This consolidation will result in improved recoveries at the Phoe nix Plant as well as cost savings ranging from $0.2 million to $0.5 million annually due to idling the Canadian facility.  In support of this project we are installing a three mile pipeline to interconnect our System 97 gathering system to the new Phoenix Plant providing access to drilling activity in Wheeler County where the highest Granite Wash drilling activity has been occurring.

 The liquids content of the natural gas is lower in the Granite Wash Play across 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, were $8.4 million and $16.5 million, respectively, for the three and six months ended June 30, 2010, compared to $8.1 million and $16.2 million, respectively, for the three and six months ended June 30, 2009.  The $0.3 million increase for three and six months ended June 30, 2010 can be primarily attributed to higher maintenance costs.

Depreciation and Amortization. Depreciation and amortization expenses for the three and six months ended June 30, 2010 were $11.6 million and $23.2 million, respectively, compared to $11.0 million and $22.1 million, respectively, for the three and six months ended June 30, 2009.  The major item impacting the $0.7 million and $1.2 million increases was depreciation expense associated with the capital expenditures placed into service during the period.

Capital Expenditures. Capital expenditures for the three and six months ended June 30, 2010 were $7.7 million and $9.9 million, respectively, compared to $0.8 million and $3.7 million, respectively, for the three and six months ended June 30, 2009. The increase in capital expenditures for the three and six months ended June 30, 2010 was primarily driven by spending related to our Phoenix Plant.

32

 East Texas/Louisiana Segment

	Three Months				Six Months
	Ended June 30,				Ended June 30,
	2010		2009		2010		2009
	($ in thousands, except prices and volumes)
REVENUE:
Natural gas, natural gas liquids, oil, condensate and sulfur sales	$	38,623	$	41,245	$	90,464	$	88,696
Gathering and treating services		12,156		7,375		20,678		14,584
Total revenue		50,779		48,620		111,142		103,280
Cost of natural gas and natural gas liquids		34,477		37,233		80,682		82,242
Operating costs and expenses:
Operations and maintenance		4,210		4,608		8,419		9,160
Depreciation, depletion and amortization		4,112		4,240		8,540		9,011
Total operating costs and expenses		8,322		8,848		16,959		18,171
Operating income	$	7,980	$	2,539	$	13,501	$	2,867
Capital expenditures	$	5,267	$	4,820	$	6,808	$	14,077
Realized average prices:
Oil and condensate (per Bbl)	$	75.48	$	60.87	$	73.99	$	56.13
Natural gas (per MMbtu)	$	4.94	$	3.45	$	5.45	$	3.90
NGLs (per Bbl)	$	33.26	$	22.23	$	36.03	$	20.66
Production volumes:
Gathering volumes (Mcf/d) (a)		211,157		265,740		212,027		268,654
NGLs (net equity gallons)		4,246,347		6,166,467		8,925,929		8,842,886
Condensate (net equity gallons)		352,446		466,348		823,739		901,639
Natural gas short position (MMbtu/d) (a)		719		2,798		1,270		3,036

(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.

Revenues and Cost of Natural Gas and Natural Gas Liquids. For the three and six months ended June 30, 2010, revenues minus cost of natural gas and NGLs for our East Texas/Louisiana Segment totaled $16.3 million and $30.5 million, respectively, compared to $11.4 million and $21.0 million, respectively, for the three and six months ended June 30, 2009.  During the three and six months ended June 30, 2010 and 2009, we received deficiency payments of $6.5 million, $8.1 million, $0.3 million and $0.3 million, respectively, from certain of our producers due to lower than anticipated volumes.  These amounts are included within gathering and treating services revenue.  Excluding these deficiency payments, revenues minus cost of natural gas and NGLs for the three and six months ended June 30, 2010 would have been $9.8 million and $22.4 million, respectively.  The decrease for the three months ended June 30, 2010 compared to the three months ended June 30, 2009, excluding the impact of the deficiency payments, is primarily due to the decrease in volumes, partially offset by higher commodity prices.  The increase for the six months ended June 30, 2010 compared to the six months ended June 30, 2009, excluding the impact of the deficiency payments, is primarily due to higher commodity prices and higher NGL equity gallons due to recovery of additional ethane gallons.  During the first two months of 2009, we were operating our facilities in ethane rejection mode.  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 tailgate of our plants.  We operate in this manner when the value of ethane is worth more in the gas stream than as a separate component.

Our gathering volumes for the three and six months ended June 30, 2010 decreased by 21% and 21%, respectively, as compared to the three and six months ended June 30, 2009.   This decline is due to natural declines in the underlying existing wells in addition to reduced drilling activity during 2009 and early 2010.   The dramatic fall in commodity prices experienced in the latter part of 2008 and into 2009 resulted in many of our producer customers significantly reducing drilling, 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 and six months ended June 30, 2009, natural gas prices have not recovered to levels that have caused our producers to increase drilling activity back to the 20 08 levels.

Operating Expenses. Operating expenses for the three and six months ended June 30, 2010 were $4.2 million and $8.4 million, respectively, compared to $4.6 million and $9.2 million, respectively, for the three and six months ended June 30, 2009. The major items impacting the $0.4 million and $0.8 million decreases in operating expense for the three and six months ended June 30, 2010 was due to overall cost reduction initiatives implemented across the segment in operating expenses.

Depreciation and Amortization. Depreciation and amortization expenses for the three and six months ended June 30, 2010 were $4.1 million and $8.5 million, respectively, compared to $4.2 million and $9.0 million, respectively, for the three and six months ended June 30, 2009. The major item impacting the $0.1 million and $0.5 million decreases for the three and six months ended June 30, 2010 was the impairment taken in the fourth quarter of 2009 resulting in decreased depreciable bases.

Capital Expenditures. Capital expenditures for the three and six months ended June 30, 2010 were $5.3 million and $6.8 million, respectively, compared to $4.8 million and $14.1 million for the three and six months ended June 30, 2009. The increase in capital spending for the three months ended June 30, 2010, can primarily be attributed to spending on the planned expansion of our ETML gas gathering system.  The decrease of $7.3 million for the six months ended June 30, 2010 compared to the six months ended June 30, 2009 is due primarily to our overall lower capital spending on account of the reduced drilling activity of our producer customers.  During the three and six months ended June 30, 2009, we were finalizing the construction of gathering lines to producers in the Brookeland and Tyler County gathering systems. In April 2010, we announced plans to begin construction on an expansion of our ETML gas gathering system in East Texas to provide multi-market capability for producers in the growing Haynesville and Middle Bossier shale plays in Nacogdoches and San Augustine Counties. We have elected not to initiate construction of the pipeline at this time due to the lack of firm volume commitments at fees that provide what we believe is an acceptable rate of return.  As the shale play continues to move west, we will take advantage of our existing asset base along with life-of-lease dedicated acreage that will benefit from the future drilling.  We remain committed to servicing our customers in this area and will continue to evaluate growth opportunities in the area that meet our rate of return and accretion targets.  We are evaluating the disposition of the pipelines acquired to date, and we expect to recover substantially all of our pipeline costs at this time.

33

South Texas Segment

	Three Months						Six Months
	Ended June 30,						Ended June 30,
	2010			2009			2010			2009
	($ in thousands, except prices and volumes)
REVENUE:
Natural gas, natural gas liquids, oil, condensate and sulfur sales	$	19,653		$	24,751		$	45,302		$	56,539
Gathering and treating services		1,164			1,306			2,098			2,863
Other revenue		-			-			-			3
Total revenue		20,817			26,057			47,400			59,405
Cost of natural gas and natural gas liquids		18,324			23,819			41,962			54,888
Operating costs and expenses:
Operations and maintenance		1,097			989			1,950			2,050
Impairment		3,130			-			3,130			-
Depreciation, depletion and amortization		1,192			1,284			2,679			2,708
Total operating costs and expenses		5,419			2,273			7,759			4,758
Operating income (loss) from continuing operations		(2,926	)		(35	)		(2,321	)		(241	)
Discontinued Operations		-			(67	)		28			240
Operating loss	$	(2,926	)	$	(102	)	$	(2,293	)	$	(1	)
Capital expenditures	$	55		$	75		$	31		$	15
Realized average prices:
Oil and condensate (per Bbl)	$	72.51		$	55.55		$	75.21		$	40.80
Natural gas (per MMbtu)	$	3.85		$	3.31		$	4.66		$	3.87
NGLs (per Bbl)	$	43.91		$	29.68		$	46.95		$	27.96
Production volumes:
Gathering volumes (Mcf/d) (a)		69,786			90,395			71,943			93,885
NGLs (net equity gallons)		313,271			452,942			618,970			677,447
Condensate (net equity gallons)		528,120			309,186			1,012,186			956,646
Natural gas short position (MMbtu/d) (a)		1,152			500			1,108			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.

Revenues and Cost of Natural Gas and Natural Gas Liquids. During the three and six months ended June 30, 2010, the South Texas Segment contributed $2.5 million and $5.4 million, respectively, in revenues minus cost of natural gas and NGLs as compared to $2.2 million and $4.5 million, respectively, for the three and six months ended June 30, 2009.  We were negatively impacted by declining gathering volumes, offset by increased commodity prices during the three and six months ended June 30, 2010, as compared to the same periods in 2009.

Operating Expenses. Operating expenses for the three and six months ended June 30, 2010 were $1.1 million and $2.0 million, respectively, compared to $1.0 million and $2.1 million for the three and six months ended June 30, 2009.  Operating expenses were higher during the three months ended June 30, 2010 due to pipeline integrity work.

Impairment.  We recorded impairment expense of $3.1 million in the three and six months ended June 30, 2010 due to the loss of a significant gathering contract.  No impairment charges were incurred in the three and six months ended June 30, 2009.

Depreciation and Amortization. Depreciation and amortization expense for the three and six months ended June 30, 2010 was $1.2 million and $2.7 million, respectively, compared to $1.3 million and $2.7 million, respectively, for the three and six months ended June 30, 2009.

Discontinued Operations.  On April 1, 2009, we sold our producer services line of business, and we have classified the revenues minus the cost of natural gas and NGLs as discontinued operations.  During the three and six months ended June 30, 2010, this business generated revenues of less than $0.1 million and no cost of natural gas and NGLs.  During the three and six months ended June 30, 2009, this business generated revenues of $19.2 million and cost of natural gas and NGLs of $19.0 million.  For the three and six months ended June 30, 2010, less than $0.1 million of revenues minus the cost of natural gas and NGLs have been reported as discontinued operations, as compared to revenues minus the cost of natural gas and NGLs of $0.2million for the three and six months ended June 30, 2009.

34

Gulf of Mexico Segment

	Three Months					Six Months
	Ended June 30,					Ended June 30,
	2010			2009		2010			2009
	($ in thousands, except prices and volumes)
REVENUE:
Natural gas, natural gas liquids, oil, condensate and sulfur sales	$	7,255		$	5,844	$	15,679		$	12,066
Gathering and treating services		173			280		608			368
Other revenue		-			1,616		-			1,616
Total revenue		7,428			7,740		16,287			14,050
Cost of natural gas and natural gas liquids		6,393			5,181		13,858			10,373
Operating costs and expenses:
Operations and maintenance		531			658		1,036			1,076
Depreciation, depletion and amortization		1,567			1,477		3,170			2,965
Total operating costs and expenses		2,098			2,135		4,206			4,041
Operating income (loss)	$	(1,063	)	$	424	$	(1,777	)	$	(364	)
Capital expenditures	$	5		$	-	$	18		$	141
Realized average prices:
NGLs (per Bbl)	$	43.86		$	29.57	$	46.24		$	28.76
Production volumes:
Gathering volumes (Mcf/d) (a)		97,926			98,619		100,096			107,559
NGLs (net equity gallons)		1,011,256			1,192,008		2,098,573			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.

Revenues and Cost of Natural Gas and Natural Gas Liquids. During the three and six months ended June 30, 2010, the Gulf of Mexico Segment contributed $1.0 million and $2.4 million, respectively, in revenues minus cost of natural gas and NGLs compared to $2.6 million and $3.7 million, respectively, during the three and six months ended June 30, 2009.  During the three and six months ended June 30, 2009, we recorded other revenue of approximately $1.6 million from business interruption insurance related to damages caused by Hurricanes Gustav and Ike.  Excluding this other revenue, revenues minus cost of natural gas and NGLs would have been $0.9 million and $2.1 million, respectively, for the three and six months ended June 30, 2009.  The increase, exclus ive of the business interruption insurance recovery, can be attributed to higher condensate and NGL prices during the three and six months ended June 30, 2010 as compared to the three and six months ended June 30, 2009 offset by a reduction in volumes and NGLs.  The reduction in volumes is due to natural declines in the underlying existing wells, reduced drilling activity during 2009 and 2010, workovers and new shallow water drilling being generally delayed due to the uncertainty caused by the federal offshore drilling moratorium and an adjustment downward in our ownership percentage at the North Terrebonne Plant.  Our ownership percentage in North Terrebonne adjusts up or down annually based upon our volume of gas from committed leases as compared to the total volumes of gas from all plant owners committed leases.

 Operating Expenses.  Operating expenses for the three and six months ended June 30, 2010 were $0.5 million and $1.0 million, respectively, compared to $0.7 million and $1.1 million, respectively, for the three and six months ended June 30, 2009.

 Depreciation and Amortization. Depreciation and amortization expenses for the three and six months ended June 30, 2010 was $1.6 million and $3.2 million, respectively, compared to $1.5 million and $3.0 million, respectively, for the three and six months ended June 30, 2009.

 Capital Expenditures.  Capital expenditures were less than $0.1 million for the both the three and six month periods ended June 30, 2010, compared to less than $0.1 million and $0.1 million, respectively for the three and six months ended June 30, 2009.

35

Upstream Business (One segment)

	Three Months						Six Months
	Ended June 30,						Ended June 30,
	2010			2009			2010			2009
	($ in thousands, except prices and volumes)
REVENUE:
Oil and condensate sales (a)	$	12,377		$	8,598		$	23,362		$	14,556
Natural gas sales (b)		4,733			2,965			9,365			4,860
Natural gas liquids sales (c)		5,290			3,544			11,254			5,770
Sulfur sales		2,112			-			3,180			-
Other		(251	)		62			(215	)		101
Total revenue		24,261			15,169			46,946			25,287
Operating costs and expenses:
Operations and maintenance		8,010			6,601			17,302			13,133
Sulfur disposal costs (e)		914			717			729			1,157
Impairment		-			-			-			242
Other operating income		-			(3,552	)					(3,552	)
Depreciation, depletion and amortization		9,058			7,955			17,623			17,351
Total operating costs and expenses		17,982			11,721			35,654			28,331
Operating income (loss)	$	6,279		$	3,448		$	11,292		$	(3,044	)
Capital expenditures	$	7,414		$	1,988		$	12,392		$	3,580
Realized average prices: (d)
Oil and condensate (per Bbl)	$	60.10		$	43.76		$	58.32		$	35.99
Natural gas (per Mcf)	$	4.06		$	2.91		$	4.60		$	3.58
NGLs (per Bbl)	$	43.92		$	27.57		$	47.28		$	23.18
Sulfur (per Long ton) (e)	$	102.96		$	-		$	73.34		$	-
Production volumes:
Oil and condensate (Bbl)		203,767			203,225			401,232			410,115
Natural gas (Mcf)		1,022,627			918,048			1,965,090			1,803,957
NGLs (Bbl)		132,085			121,783			252,503			247,686
Total (Mcfe)		3,037,739			2,868,094			5,887,500			5,750,760
Sulfur (per Long ton) (e)		33,191			39,823			52,307			68,428

(a)   Revenues include a change in the value of product imbalances of $181, $0, $(247) and $(260) for the three and six months ended June 30, 2010 and 2009, respectively.

(b)   Revenues include a change in the value of product imbalances of $845, $567, $284 and $(1,563) for the three and six months ended June 30, 2010 and 2009, respectively.

(c)   Revenues include a change in the value of product imbalances of $167 and $28 for the three and six months ended June 30, 2009.

(d)   Calculation does not include impact of product imbalances.  In addition, volumes and realized price for the three and six months ended June 30, 2009 and the three months ended March 31, 2010 have been revised from prior period reported amounts due to the reversal and rebooking of our Big Escambia Creek field.

(e)   During the six months ended June 30, 2010, an adjustment was made to decrease sulfur volumes by 5,230 long tons related to a prior period adjustment.  This adjustment is excluded from the calculation of realized prices.

Revenue. For the three and six months ended June 30, 2010, the Upstream Segment contributed $24.3 million and $46.9 million of revenue, respectively, compared to $15.2 million and $25.3 million, respectively, for the three and six months ended June 30, 2009.   The increase in revenue was due to substantially higher realized prices for oil, natural gas, NGLs and sulfur and increased production volumes of natural gas and NGLs during the three and six months ended June 30, 2010 compared to the three and six months ended June 30, 2009.  This increase was partially offset by the turnaround at our Big Escambia Creek facility during the three months ended June 30, 2010, as discussed below.  During the three and six months ended June 30, 2010, producti on averaged 11.2 MMcf/d of natural gas and 10.9 MMcf/d of natural gas, respectively, 2.2 MBO/d of oil and condensate and 2.2 MBO/d of oil and condensate, respectively, 1.5 MB/d of NGLs and 1.4 MB/d of NGLs, respectively, and 365 LT/d of sulfur and 318 LT/d of sulfur, respectively.

During late April and early May 2010, we completed a scheduled turnaround (i.e., a complete shutdown of the facility) of our Big Escambia Creek facility to conduct certain standard plant repairs and routine inspections of equipment. During the plant turnaround, all wells in the Big Escambia Creek field were shut-in. The duration of both the plant turnaround and the well shut-in was approximately 12 days.  The negative impact to our production during this period was a loss of approximately 48 MMcf of residue gas, 14 MBbls of oil, 8.7 MBbls of plant liquids and 2,000 long tons of sulfur. The revenue impact of the loss in production was approximately $1.8 million during the three and six months ended June 30, 2010.  In addition, during the th ree months ended June 30, 2010, we completed a reversal and rebooking of our Big Escambia Creek wells for the period from August 2007 through March 2010 due to corrections of well tests, product reallocations and product pricing.  As a result of this reversal and rebooking, our revenues for the three and six months ended June 30, 2010 were negatively impacted by $1.3 million.

During the three and six months ended June 30, 2010, sulfur revenue was $2.1 million and $3.2 million, respectively compared to the cost to dispose of sulfur which exceeded the sales price by $0.7 million and $1.2 million, respectively during the three and six months ended June 30, 2009.  In addition, during the three and six months ended June 30, 2010, we recorded sulfur disposal costs of $0.9 million and $0.7 million to adjust for an under accrual of sulfur disposal costs in a prior period.  Historically, sulfur was viewed as a low value by-product in the production of oil and natural gas.  In 2009, deterioration in the sulfur market during the three and six months ended June 30, 2009 caused the price at the Tampa, Florida mark et to decline to $5 per long ton, and we incurred costs to dispose of our sulfur at that time.   During the six months ended June 30, 2010, sulfur began to recover and priced at $90 per long ton on February 1, 2010 and $145 per long ton in the three months ended June 30, 2010 at the Tampa, Florida market. Our net realized price will always be lower than the price set at the Tampa, Florida hub due to transportation and marketing deductions and charges.  These charges vary depending on the distance our product is produced from the Tampa, Florida market.

 Operating Expenses. Operating expenses, including severance and ad valorem taxes, totaled $8.0 million and $17.3 million, respectively, for the Upstream Segment during the three and six months ended June 30, 2010, as compared to $6.6 million and $13.1 million for the three and six months ended June 30, 2009.  The increase in operating expense for the three and six months ended June 30, 2010 can be attributed to two well workovers in our Alabama operations incurred during the first three months of 2010 and approximately $1.3 million of expenses incurred related to our turnaround at our Big Escambia Creek Facility, as discussed above, during the three months ended June 30, 2010, as compared to the same period in the prior year.  In addition, during the three and six months ended June 30, 2010, we recorded a reversal of $0.6 million of operating costs due to the reversal and rebooking of our Big Escambia Creek wells, as discussed above.   Also, during the three and six months ended June 30, 2010, our severance taxes increased due to (i) the increase in revenue from the same periods in the prior year and (ii) additional severance taxes as a result of the reversal and rebooking discussed above.  This increase was offset by a refund of severance taxes from the state of Alabama during the three months ended June 30, 2010 for overpayment in prior periods.

 Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense for the three and six months ended June 30, 2010 was $9.1 million and $17.6 million, respectively, as compared to $8.0 million and $17.4 million for the three and six months ended June 30, 2009, respectively.  The increase for the three and six months ended June 30, 2010 compared to the comparable period in 2009 is due to increases in production.

 Impairment. No impairment charges were incurred during the three and six months ended June 30, 2010 and the three months ended June 30, 2009.  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.

 Other Operating Income.  No other operating income was recorded during the three and six months ended June 30, 2010.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 liabilitie s.

Capital Expenditures.  Capital expenditures for the three and six months ended June 30, 2010 were $7.4 million and $12.4 million, respectively, as compared to $2.0 million and $3.6 million, respectively, for the three and six months ended June 30, 2009.  The increase in capital expenditures is due to drilling activity in our Permian operations, recompletions in the Jourdanton field and the acquisition of compression equipment for the planned turnaround at our Big Escambia Creek facility that was completed during the three months ended June 30, 2010.   We are installing two new compressors that will provide improved reliability and backup for the existing residue gas and plant inlet compression. The new backup compression will be placed in servi ce in August 2010.  During the three and six months ended June 30, 2010, we drilled and completed two and three wells, respectively.  As of June 30, 2010, we were in the process of drilling or completing three additional wells in our Ward Estes field.

36

Corporate Segment

	Three Months						Six Months
	Ended June 30,						Ended June 30,
	2010			2009			2010			2009
	($ in thousands)
REVENUE:
Unrealized commodity derivative gains (losses)	$	41,405		$	(97,044	)	$	54,883		$	(101,566	)
Realized commodity derivative (losses) gains		(5,813	)		22,483			(8,496	)		53,261
Total revenue		35,592			(74,561	)		46,387			(48,305	)
Operating costs and expenses:
General and administrative		12,806			11,866			25,817			24,379
Depreciation, depletion and amortization		482			218			835			431
Total costs and expenses		13,288			12,084			26,652			24,810
Operating (loss) income		22,304			(86,645	)		19,735			(73,115	)
Other income (expense):
Interest income		173			141			175			172
Other income		(21	)		199			78			283
Interest expense		(3,833	)		(5,428	)		(7,978	)		(12,967	)
Realized interest rate derivative losses		(4,952	)		(5,147	)		(9,842	)		(8,629	)
Unrealized interest rate derivative (losses) gains		(4,354	)		11,954			(9,176	)		15,053
Other expense		(551	)		(267	)		(820	)		(534	)
Total other income (expense)		(13,538	)		1,452			(27,563	)		(6,622	)
(Loss) income from continuing operations before taxes		8,766			(85,193	)		(7,828	)		(79,737	)
Income tax provision (benefit)		(415	)		(1,512	)		296			(4,276	)
(Loss) income from continuing operations		9,181			(83,681	)		(8,124	)		(75,461	)
Discontinued Operations, net of tax		39,473			2,036			43,289			3,547
Operating income (loss)	$	48,654		$	(81,645	)	$	35,165		$	(71,914	)

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, increased to gains of $35.6 million and $46.4 million for the three and six months ended June 30, 2010, from losses of $74.6 million and $48.3 million for the three and six months ended June 30, 2009.  As a result of our commodity hedging activities, revenues include realized losses of $5.8 million and $8.5 million on risk management activity that was settled during the three and six months ended June 30, 2010 and unrealized mark-to-market gains of $41.4 million and $54.9 million for the three and six months ended June 30, 2010 as compared to 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 and unrealized mark-to-market losses of $97.0 million and $101.6 million for the three and six months ended June 30, 2009.  Included with our unrealized commodity derivative gains (losses) are the amortization of put premiums and other derivative costs of $0.4 million, $3.1 million, $11.1 million and $23.3 million, respectively, during the three and six months ended June 30, 2010 and 2009.

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, 2010 reflect forward curve price movements from the beginning to the end of the three and six month periods for commodities underlying the derivative instruments.  The unrealized mark-to-market results for the three and six months ended June 30, 2010 and 2009 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 were $12.8 million and $25.8 million for the three and six months ended June 30, 2010 as compared to $11.9 million and $24.4 million for the three and six months ended June 30, 2009.  Equity-based compensation expense decreased by approximately $0.3 million and $0.8 million during the three and six months ended June 30, 2010 as compared to the three and six months ended June 30, 2009.  This decrease during the three and six months ended June 30, 2010 was the result of natural run-off (through vesting) of restricted units granted in prior periods at higher prices and due to the three and six months ended June 30, 2010 and 2009 including an allocation of expense of $0.1 million and $0.4 mi llion, respectively, from Holdings due to its issuance of Tier I units to certain of our executives.  Excluding the decrease in equity-based compensation expense, other compensation expense increased by $0.9 million and $1.1 million during the three and six months ended June 30, 2010.  These increases were primarily the result of increased headcount and increased health insurance costs as well as legal and advisory costs related to our Recapitalization and Related Transactions. This increase in headcount resulted in an increase during the three months ended June 30, 2010 of about $0.6 million of contract labor and other professional services expenses.  Included within our other professional services expenses for the three and six months ended June 30, 2010, are non-capitalizable legal and other professional advisory fees of $0.6 million and $1.5 million, respectively, related to the Recapitalization and Related Transactions and the related lawsuit.

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.

Total Other Income (Expense). Total other income (expense) includes both realized and unrealized gains and losses from our interest rate swaps. We incurred expense of $13.5 million and $27.6 million, respectively, for the three and six months ended June 30, 2010 as compared to income of $1.5 million for the three months ended June 30, 2009 and expense of $6.6 million during the six months ended June 30, 2009.  During the three and six months ended June 30, 2010, we incurred realized losses from our interest rate swaps of $5.0 million and $9.8 million, respectively, as compared to realized losses of $5.1 million and $8.6 million during the three and six months ended June 30, 2009. We also incurred unrealized mark-to-market losses during the three and six months ended Ju ne 30, 2010 of $4.4 million and $9.2 million, respectively, as compared to unrealized mark-to-market gains of $12.0 million and $15.1 million, respectively, during the three and six months ended June 30, 2009.  The unrealized mark-to-market results for the three and six months ended June 30, 2010 and 2009 had no impact on cash activities for those periods and are excluded from our calculation of Adjusted EBITDA.

 Interest expense decreased to $3.8 million and $8.0 million for the three and six months ended June 30, 2010 as compared to $5.4 million and $13.0 million, respectively, during the three and six months ended June 30, 2009.  Interest expense 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 is due to lower LIBOR rates during the three and six months ended June 30, 2010 as compared to the same period in 2009 and lowe r debt balances as a result of paying down debt over the last fifteen months.

 Income Tax Provision (Benefit). Income tax provision for the three and six months ended June 30, 2010 and 2009 relates to (i) state taxes due by us and (ii) federal taxes due by Eagle Rock Energy Acquisition Co., Inc. (acquiring entity of certain entities acquired in the acquisition of Redman Energy Corporation “Redman Acquisition” in 2007) 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”).  During the three and six months ended June 30, 2010, our tax provision increased by $1.4 million and $4.9 million as compared to the same periods in the prior year.  These increases were the result of 2010 income projected for the C Corporations resulting from utilization of our remaining net operating loss carryforwards during the year ended December 31, 2009.

 Discontinued Operations. On May 24, 2010, we completed the sale of all of our fee mineral and royalty interests as well as our equity investment in Ivory Working Interests, L.P. (collectively, the “Minerals Business”), for which we received net proceeds of approximately $171.6 million in cash after purchase price adjustments made to reflect an effective date of January 1, 2010 for the sale, as established in the agreement governing the sale. We retained approximately $2.9 million of cash from net revenues received from the Minerals Business after the effective date.  We recorded a gain of $37.7 million on the sale, which is recorded as part of discontinued operations for the three and six months ended June 30, 2010.   Further upward or downward adjustments to the purchase price may occur post-closing to reflect customary true-ups.  For the three and six months ended June 30, 2010, we generated revenues of $3.3 million and $8.9 million, respectively, and income from operations of $1.8 million and $5.6 million, respectively.   For the three and six months ended June 30, 2009, we generated revenues of $3.5 million and $6.7 million, respectively, and income (loss) from operations of $1.7 million and $2.8 million, respectively.  During the three and six months ended June 30, 2010 and 2009, the Partnership incurred state tax expense on discontinued operations of $0.4 million, $0.4 million, less than $0.1 million and $0.1 million, respectively.  During the three and six months ended June 30, 2010 and 2009, we recorded a gain (loss) to discontinued operations, excluding the gain recognized by us on the sale of the Minerals Business, of $2.2 million, $6.0 million, $2.0 milli on and $3.5 million, respectively.

37

Adjusted EBITDA

Adjusted EBITDA, as defined under “Non-GAAP Financial Measures,” decreased by $9.5 million and $16.2 million from $41.6 million and $80.0 million, respectively for the three and six months ended June 30, 2009 to $32.1 million and $63.8 million, respectively, for the three and six months ended June 30, 2010.

           As described above, for the three and six months ended June 30, 2010, revenues minus cost of natural gas and NGLs for the Midstream Business (including the Texas Panhandle, East Texas/Louisiana, South Texas and the Gulf of Mexico Segment) increased by $13.3 million and $31.7 million, respectively, as compared to the three and six months ended June 30, 2009. For the three and six months ended June 30, 2010, revenues for our Upstream Segment increased by $9.1 million and $21.7 million, respectively, as compared to the same period in the prior year.  Our Corporate Segment’s realized commodity derivatives loss decreased from a gain by $28.3 million and $61.8 million, respectively, as compared to the three and six months ended June 30, 2009. This resulted in a decline of $5.9 million and $8.4 million, respectively, of total incremental revenues minus cost of natural gas and NGLs for the three and six months ended June 30, 2010 as compared to the same period in the prior year.   The incremental revenue amounts are adjusted to exclude the impact of unrealized commodity derivatives and the non-cash mark-to-market Upstream Segment imbalances, which are not included in the calculation of Adjusted EBITDA.

 Operating expenses (including taxes other than income) for the three and six months ended June 30, 2010 decreased by $0.1 million and $0.6 million, respectively, for our Midstream Business, while operating expenses for our Upstream Segment increased by $1.6 million and $3.7 million as compared to the three and six months ended June 30, 2009.

General and administrative expense, captured in the Corporate Segment, increased by $1.3 million and $2.2 million, respectively, for the three and six months ended June 30, 2010, as compared to the same period in the prior year.  These amounts are 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 NGLs decreased by $5.9 million and $8.4 million, respectively, operating expenses increased by $1.5 million and $3.2 million, respectively, and general and administrative expenses increased by $1.3 million and $2.2 million, respectively resulting in the decrease to Adjusted EBITDA during the three and six months ended June 30, 2010 as compared to the three and six months ended June 30, 2009.

Adjusted EBITDA, for the three and six months ended June 30, 2010 and 2009, excludes amortization of commodity hedge costs (including, for the six months ended June 30, 2010 and the three and six months ended 2009, costs of hedge reset transactions) of $0.4 million, $3.1 million, $11.1 million and $23.3 million, respectively.  Including these amortization costs, our Adjusted EBITDA for the three and six months ended June 30, 2010 and 2009 would have been $31.7 million, $60.7 million, $30.5 million and $56.7 million, respectively.

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 and our requirements for short-term working capital and long-term capital expenditures.

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.

 The actual distributions we will declare will be subject to our operating performance, prevailing market conditions (including forward oil, natural gas and sulfur prices), the impact of unforeseen events and the approval of our Board of Directors and will be done pursuant to our distribution policy.

 In response to, in part, a lack of liquidity due to our high leverage levels and restricted access to the capital markets during 2009, our Board determined to reduce the quarterly distribution (and sustain such reduced quarterly distribtuion) with respect to each quarter of 2009 and the first two quarters of 2010, to $0.025 per common and general partner unit, as compared to $0.41 per common, subordinated and general partner unit paid with respect to the fourth quarter of 2008.  This decision was made 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 distri buted has been used to reduce our outstanding debt under our revolving credit facility, to continue to execute our hedge strategy to maintain future cash flows and/or to fund growth capital expenditures.

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 our ratio of outstanding debt to Adjusted EBITDA, or “leverage ratio,” with respect to our Midstream Business, which as of June 30, 2010 was 3.55, to approximately 3.0 to 3.5 on a sustained basis, including without limitation, by reducing outstanding indebtedness.  We believe this leverage ratio range to be appropriate for our business and more in-line with historical midstream industry standards.  Our leverage ratio was negatively impacted in 2009 by the effect of lower commodity prices on our Adjusted E BITDA.  In response, we took steps to reduce our outstanding indebtedness under our revolving credit facility and to improve our Adjusted EBITDA position through prudent management of our hedging portfolio, including by hedge reset transactions.  During the six months ended June 30, 2010, we reduced our outstanding debt under the revolving credit facility by $189.0 million from $754.4 million to $565.4 million and since March 31, 2009, we reduced our outstanding indebtedness under the revolving credit facility by $272.0 million.  The actual amount and timing of further debt repayment, if any, 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.  We also plan to reduce our leverage ratio by investing in attractive organic growth and acquisition opportunities in our Midstream and Upstream Businesses which will increase our Adjusted EBITDA.  Based on our strategy, we believe that we will remain in compliance with our financial covenants through 2010.

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, 2009 and below under “Revolving Credit Facility and Debt Covenants” and under Item 1.01 in our current report on Form 8-K filed with the SEC on March 9, 2010.

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.

On February 2, 2010, we declared our fourth quarter 2009 cash distribution of $0.025 per unit to our general partner (as to our general partner units) and our common unitholders of record as of the close of business on February 8, 2010.  The distribution was paid on February 12, 2010.

 On April 27, 2010, we declared our first quarter 2010 cash distribution of $0.025 per unit to our general partner (as to our general partner units) and our common unitholders of record as of the close of business on May 7, 2010.  The distribution was paid on May 14, 2010.

 On July 28, 2010, we declared our second quarter 2010 cash distribution of $0.025 per unit to our common unitholders of record as of the close of business on August 9, 2010.  This distribution will be paid on August 13, 2010.

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, 2010, working capital was ($33.9) million as compared to ($57.0) million as of December 31, 2009, excluding assets and liabilities held for sale.

The net increase in working capital of $23.1 million from December 31, 2009 to June 30, 2010, resulted primarily from the following factors:

·   cash balances and marketable securities, net of due to affiliates, increased overall by $7.0 million and was impacted primarily by the results of operations, timing of capital expenditures payments, and financing activities including our debt activities (the due to affiliate liability of $9.5 million as of June 30, 2010 is owed to Eagle Rock Energy G&P, LLC);

·   trade accounts receivable decreased by $9.9 million primarily from the impact of slightly lower revenues, increased collection effects and realized settlement losses on our commodity derivatives;

·   risk management net working capital balance increased by a net $24.7 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 $2.3 million primarily as a result of activities and timing of payments, including capital expenditures; and

·   accrued liabilities decreased by $0.9 million primarily reflecting payment of employee benefit accruals, lower interest payments 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, 2010 Compared to the Six months ended June 30, 2009

Cash Flow from Operating Activities. Cash flows from operating activities increased $22.5 million during the six months ended June 30, 2010 as compared to the six months ended June 30, 2009 as a result of higher commodity prices across our two businesses.  These higher commodity prices resulted in higher cash flows from the sale of our equity crude oil, natural gas and NGLs volumes and higher cash flows from the sale of sulfur.  Higher commodity prices also resulted in us realizing net settlement losses during the six months ended June 30, 2010, of which $0.6 million of cash received was reclassified to cash from financing activities, compared to $6.8 million of cash received being reclassified during the six months ended June 30, 2009. 

Cash Flows from Investing Activities. Cash flows provided by investing activities for the six months ended June 30, 2010 were $146.8 million, as compared to cash flows used in investing activities of $26.6 million for the six months ended June 30, 2009 due to the sale of our Minerals Business during the six months ended June 30, 2010.  In addition, the increase was also impacted by slightly lower cash outlays for capital expenditures and intangible assets during the six months ended June 30, 2010 compared to the six months ended June 30, 2009.

Cash Flows from Financing Activities. Cash flows used in financing activities during the six months ended June 30, 2010 as compared to the six months ended June 30, 2009 increased by $173.0 million. Key differences between periods include net repayments to our revolving credit facility of $189.0 million during the six months ended June 30, 2010 as compared to net proceeds of $5.0 million from our revolving credit facility during the six months ended June 30, 2009.  We used the proceeds received from the sale of our Minerals Business to pay down borrowings outstanding under our revolving credit facility.  Distributions to members decreased to cash outflows of $3.0 million during the six months ended June 30, 2010 as compared to $32.9 million during the si x months ended June 30, 2009 as a result of reducing our quarterly distribution to $0.025 for the payments made in the first quarter of 2010 (for the fourth quarter of 2009 and first quarter of 2010) from $0.41 paid in the first quarter of 2009 (for the fourth quarter of 2008), coupled with $0.025 paid in the second quarter of 2009 (for the first quarter of 2009).

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 revolving credit facility covenants and continue to execute on our distribution objectives.  In addition, we may also terminate or unwind hedges or portions of hedges when the expected future volumes do not support the level of hedges or otherwise.  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.
60; These transactions also increase our exposure to the counterparties through which we execute the hedges.  As part of this strategy, on July 23, 2010, we enhanced our commodity derivative portfolio by adjusting the strike price of certain hedges to the forward market prices as of the date the hedges were executed.  Specifically, we paid $5.9 million to adjust the strike price from $53.55 to $79.80 per barrel on existing NYMEX WTI crude oil swaps of 45,000 barrels per month for the five months ended December 31, 2010.

 On August 3, 2010, we entered into a forward NYMEX WTI swap covering 29,000 barrels per month for the first half of calendar year 2011 and 23,000 barrels per month for the second half of calendar year 2011 with a strike price of $86.20 per barrel.  On the same date, we entered into a forward NYMEX WTI swap covering 10,000 barrels per month for the full calendar year 2013 with a strike price of $88.20 per barrel.

 On August 4, 2010, we entered into a forward NYMEX Henry Hub swap covering 50,000 MMBtu per month for the full calendar year 2013 with a strike price of $5.645 per MMBtu.

Revolving Credit Facility and Debt Covenants

 As of June 30, 2010, unused capacity available to us under our credit agreement, based on outstanding debt and compliance with financial covenants as of that date, was approximately $177.8 million.  The credit agreement is scheduled to mature on December 13, 2012.

Our revolving credit facility accommodates, through the use of a borrowing base for our Upstream Business and traditional cash-flow based covenants for our Midstream Business, the allocation of indebtedness to either our Upstream Business (to be measured against the borrowing base) or to our Midstream Business (to be measured against cash-flow based covenants).  Effective April 1, 2010, our borrowing base was redetermined from $135 million to $130 million.At June 30, 2010, we were in compliance with our covenants under the revolving credit facility. Our interest coverage ratio, as defined in the credit agreement (i.e., Consolidated EBITDA divided by Consolidated Interest Expense), was 4.68 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 3.55 as compared to a maximum leverage ratio of 5.0.  

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) and Upstream 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 2010 capital budget anticipates that we will spend approximately $55.9 million in total for the year on our existing assets.  Our 2010 capital budget has been revised downward from amounts previously reported primarily due to ur election not to continue expansion of the ETML gas system.  Our capital expenditures were approximately $20.7 million and $30.1 million for the three and six months ended June 30, 2010.  We anticipate a higher level of capital expenditures in our Upstream segment during 2010 associated with additional drilling in our Permian area, and the plant turnaround at our Big Escambia Creek facility, compared to 2009 capital expenditures.

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 in the near future.

Since our inception in 2002, we have made substantial growth capital expenditures. We anticipate that we will continue to make growth capital expenditures and acquisitions; however, we anticipate that our growth capital expenditures and acquisitions in 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.

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 revolving credit facility (although such expenditures were often funded out of internally generated cash flow as an interim step).  We anticipate funding our growth capital expenditures, for the foreseeable future, out of cash flow generated from operations, withdrawals from our revolving credit facility and, to the extent necessary, the issuance of equity or debt in the capital markets.

Off-Balance Sheet Obligations

We have no off-balance sheet transactions or obligations.

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RECENT ACCOUNTING PRONOUNCEMENTS

 The Financial Accounting Standards Board (the “FASB”) has codified a single source of U.S. Generally Accepted Accounting Principles (U.S. GAAP), the Accounting Standards Codification.  Unless needed to clarify a point to readers, the Partnership will refrain from citing specific section references when discussing application of accounting principles or addressing new or pending accounting rule changes.

 In June 2009, the FASB issued authoritative guidance which reflects the FASB’s response to issues entities have encountered when applying previous guidance.  In addition, this guidance addresses concerns expressed by the SEC, members of the United States Congress, and financial statement users about the accounting and disclosures required in the wake of the subprime mortgage crisis and the deterioration in the global credit markets.  In addition, because this guidance 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.   The guidance is effective for financial asset transfers occurring after the beginning of an entityR 17;s first fiscal year that begins after November 15, 2009.  Early adoption of was prohibited.   This guidance was effective for us as of January 1, 2010 and did not have a material impact on our consolidated financial statements.

 In June 2009, the FASB issued authoritative guidance, which amends the consolidation guidance applicable to variable interest entities (VIEs). The amendments will significantly affect the overall consolidation analysis.  While the FASB’s discussions leading up to the issuance of this guidance focused extensively on structured finance entities, the amendments to the consolidation guidance affect all entities and enterprises, as well as QSPEs that were excluded from previous guidance.  Accordingly, an enterprise will need to carefully reconsider its previous 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.  This guidance is effective as of the beginning of the first fiscal year that begins after November 15, 2009, and early adoption was prohibited.  This guidance was effective for us as of January 1, 2010 and did not have a material impact on our consolidated financial statements.

 In September 2009, the FASB issued a consensus which revises the standards for recognizing revenue on arrangements with multiple deliverables.  Before evaluating how to recognize revenue for transactions with multiple revenue generating activities, an entity should identify all the deliverables in the arrangement and, if there are multiple deliverables, evaluate each deliverable to determine the unit of accounting and whether it should be treated separately or in combination.  The consensus removes certain thresholds for separation, provides criteria for allocation of revenue amongst deliverables and expands disclosure requirements.  The standards will be effective for fiscal years beginning on or after June 15, 2010 unless we elect to early adopt the standards.  We have not determined if it will early adopt the standards but do not anticipate the standards to have a material impact on our consolidated financial statements.

In January 2010, the FASB issued additional guidance on fair value disclosures. The new guidance clarifies two existing disclosure requirements and requires new disclosures such as: (1) a “gross” presentation of activities (purchases, sales, and settlements) within the Level 3 rollforward reconciliation, which will replace the “net” presentation format; and (2) detailed disclosures about the transfers in and out of Level 1 and 2 measurements. This guidance is effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 rollforward information, which is required for annual reporting periods beginning after December 15, 2010, and for interim reporting periods within those years. We adopted the fair value dis closures guidance on January 1, 2010, except for the gross presentation of the Level 3 rollforward information which is not required to be adopted by us until January 1, 2011 (see Notes 10 and 11).

NON-GAAP FINANCIAL MEASURES

We include in this filing Adjusted EBITDA, a non-GAAP financial measure. 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 also us ed as a supplemental financial measure by external users of Eagle Rock’s financial statements such as investors, commercial banks and research analysts.  For example, Eagle Rock’s lenders under its revolving credit facility use a variant of Eagle Rock’s Adjusted EBITDA in a compliance covenant designed to measure the viability of Eagle Rock and its ability to perform under the terms of its revolving credit facility; Eagle Rock, therefore, uses Adjusted EBITDA to measure its compliance with its revolving credit facility.  We believe that investors benefit from having access to the same financial measures that our management team 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 also describes more accurately the underlying performance of our operating assets by isolating the performance of our operating assets from the impact of an unrealized, non-cash measure designed to describe the fluctuating inherent value of a financial asset. Similarly, by excluding the impact of non-recurring discontinued operations, Adjusted EBITDA provides users of our financial statements a more accurate picture of our current assets’ cash generation ability, independently from that of assets which are no longer a part of our operations. Eagle Rock’s Adjusted EBITDA definition may not be comparable to Adjusted EBITDA or similarly titled measur es of other entities, as other entities may not calculate Adjusted EBITDA in the same manner as Eagle Rock. 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 prices higher than those reflected in the forward curve at the time of the transaction or to 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 incomes 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 Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	($ in thousands)						($ in thousands)
Net cash flows provided by operating activities	$	25,951		$	32,073		$	44,218		$	21,711
Add (deduct):
Discontinued operations		39,473			1,969			43,317			3,787
Depreciation, depletion, amortization and impairment		(31,180	)		(26,136	)		(59,206	)		(54,766	)
Amortization of debt issuance costs		(551	)		(267	)		(820	)		(534	)
Risk management portfolio value changes		37,051			(85,088	)		45,707			(72,613	)
Reclassing financing derivative settlements		323			2,457			628			6,774
Other		(1,726	)		3,190			(4,207	)		3,495
Accounts receivables and other current assets		(8,372	)		(8,727	)		(9,061	)		(30,535	)
Accounts payable, due to affiliates and accrued liabilities		8,058			2,681			10,767			43,695
Other assets and liabilities		(884	)		3,061			781			1,654
Net income (loss)		68,143			(74,787	)		72,124			(77,332	)
Add (deduct):
Interest (income) expense, net		9,163			10,701			18,465			21,958
Depreciation, depletion and amortization		31,180			26,136			59,206			54,766
Income tax (benefit) provision		(415	)		(1,512	)		296			(4,276	)
EBITDA		108,071			(39,462	)		150,091			(4,884	)
Add (deduct):
Risk management portfolio value changes		(37,051	)		85,090			(45,707	)		86,513
Restricted unit compensation expense		1,550			1,889			3,358			4,120
Non-cash mark-to-market Upstream imbalances		(1,033	)		(203	)		(567	)		1,829
Discontinued operations, net of tax		(39,473	)		(1,969	)		(43,317	)		(3,787	)
Other income		21			(199	)		(78	)		(283	)
Other operating income		-			(3,552	)		-			(3,552	)
ADJUSTED EBITDA	$	32,085		$	41,594		$	63,780		$	79,956
	Three Months Ended						Six Months Ended
	June 30,						June 30,
		2010			2009			2010			2009
Amortization of commodity derivative costs	$	430		$	11,137		$	3,078		$	23,296

 Adjusted EBITDA, for the three and six months ended June 30, 2010 and 2009, excludes amortization of commodity hedge costs (including costs of hedge reset transactions).  Including these amortization costs, our Adjusted EBITDA for the three and six months ended June 30, 2010 and 2009 would have been $31.7 million, $60.7 million, $30.5 million and $56.7 million, respectively.

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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 a uthority 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, with primary oversight by the Audit committee of the Board, is responsible for the overall management of commodity price risk, interest rate risk and credit risk, including monitoring exposure limits.

 In addition, our Enterprise Risk Committee, which is comprised of our chief executive officer and other members of the senior management, provides enterprise-wide monitoring of risk for each of our departments through various management committees, including the Risk Management Committee.  Each of these management committees provides reports and information to the Enterprise Risk Committee which, in turn, reports material information to our Board and Board committees.

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, NGLs 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. 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, 2010, we recorded a gain on risk management instruments of $35.6 million, representing a fair value (unrealized) gain of $41.8 million, amortization of put premiums and other derivative costs of $0.4 million and a net (realized) settlement loss of $5.8 million.  For the six months ended June 30, 2010, we recorded a gain on risk management instruments of $46.4 million, representing a fair value (unrealized) gain of $58.0 million, amortization of put premiums and other derivative costs of $3.1 million and net (realized) settlement gains of $8.5 million.  As of June 30, 2010, the fair value net asset of these commodity contracts, including put premiums and other derivative costs, totaled approximately $3.8 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 revolving credit agreement. To mitigate its interest rate risk, we have entered into various interest rate swaps. These swaps convert the variable-rate term loan into a fixed-rate obligation. The purpose of entering into these swaps is to eliminate interest rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments through the end of 2012. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense. As of June 30, 2010, the notional amount of our interest rate swaps was in excess of our outstanding borrowings by approximately $34.6 million.  Absent any change to our near term borrowing expe ctations, we plan to terminate a portion of our interest swaps to eliminate our over-hedged interest rate exposure.

 We have not designated our contracts as accounting hedges. 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, 2010, the Partnership recorded a fair value (unrealized) loss of $4.4 million and a realized loss of $5.0 million.  For the six months ended June 30, 2010, we recorded a fair value (unrealized) loss of $9.2 million and a realized loss of $9.8 million.  As of June 30, 2010, the fair value liability of these interest rate contracts totaled approximately $36.6 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 NGLs 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, NGLs, 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; Wachovia Bank, N.A.; Comerica Bank; Barclays Bank PLC; Bank of Nova Scotia; 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).

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 at the reasonable assurance level 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.

On February 9, 2010 a lawsuit, alleging certain claims related to the Recapitalization and Related Transactions (see Note 9), was filed on behalf of one of our public unitholders in the Court of Chancery of the State of Delaware naming the Partnership, its general partner, certain affiliates of its general partner, including the general partner of its general partner, and each member of our Board of Directors as defendants.  The complaint alleged a breach by the defendants of their fiduciary duties to the Partnership and the public unitholders and sought to enjoin the Recapitalization and Related Transactions.  We believe the allegations in the complaint are without meri t.  On March 11, 2010, in an effort to minimize the further cost, expense, burden and distraction of any litigation relating to the lawsuit, the parties to the lawsuit entered into a Memorandum of Understanding regarding the terms of a potential settlement of the lawsuit.  If the settlement is consummated it, among other things, would resolve the allegations by the plaintiff against the defendants in connection with the Recapitalization and Related Transactions and would provide a release and settlement by a proposed class of our common unitholders during the period from September 17, 2009 through and including the date of the closing of the transactions of all claims against the defendants as they relate to the Recapitalization and Related Transactions.  In the event that the settlement is not consummated, we intend to vigorously defend against the lawsuit.

During 2009, we completed voluntary self-audits of our compliance with air quality standards, which included 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. These audits were performed pursuant to the Texas Environmental, Health and Safety Audit Privilege Act, as amended. We completed the disclosures to the Texas Commission on Environmental Quality (“TCEQ”), and we have substantially addressed the deficiencies that we disclosed therein.  We do not foresee at this time any impediment in timely addressing the remaining deficiencies identified as a result of these audits.

 Since January 1, 2010, we have received additional Notices of Enforcement (“NOEs”) and Notices of Violation (“NOVs”) from the TCEQ related to air compliance matters and expect to receive additional NOEs or NOVs from the TCEQ from time to time throughout 2010.  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 it to date.

Item 1A.                      Risk Factors.

 There have been no material changes to the risk factors described in the Partnership’s Annual Report on Form 10-K, for the year ended December 31, 2009, except as stated below.

Recent federal legislation could have an adverse impact on our ability to hedge risks associated with our business.

We enter into oil and natural gas derivative contracts from time to time with respect to a portion of our expected production of oil and natural gas in order to hedge against commodity price uncertainty and enhance the predictability of cash flows from the sale of our production. We limit the counterparties for our derivative transactions to the lenders in our revolving credit facility, in part because we are not required to post additional collateral related to the derivatives (as our lenders hold a first lien on substantially all of our assets). 

On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”). Title VII of the Dodd-Frank Act (titled “Wall Street Transparency and Accountability”) repeals prior regulatory exemptions for over-the-counter (OTC) derivatives and, for the first time, creates a comprehensive framework for the regulation of the derivatives market and, in connection therewith, expands the power of the SEC and, in particular, the Commodity Futures Trading Commission (“CFTC”). Among the provisions of the Dodd-Frank Act that may affect derivatives transactions are those requiring non-exempt derivatives transactions to be cleared with a clearinghouse and traded through an exch ange; establishing capital and margin requirements for certain derivatives participants; establishing business conduct standards, recordkeeping and reporting requirements; providing the CFTC with authority to impose position limits in the OTC derivatives markets; and requirements that could result in lending institutions spinning-off or otherwise separating their derivatives desks. The Dodd-Frank Act does contain an exemption for certain non-financial end-users hedging their own commercial risks that may limit the impact of these reforms on our hedging activities; however, many key concepts and processes under the Dodd-Frank Act are not defined and must be delineated by rules and regulations to be adopted by applicable regulatory agencies.  Even if we are successful in asserting an end-user exemption, for example, it is not possible at th is time to predict the effects that the Dodd-Frank Act may have on our hedging activities. If the Dodd-Frank Act requires our lending institutions to spin-off or otherwise separate their derivatives desks, we may no longer be able to utilize the security interests underlying our credit facility as collateral for our derivative transactions.

To the extent that we are subject to capital or margin requirements relating to or restrictions on, our hedging activities or the costs of our hedging activities increases as a consequence of our, or our hedge counterparties, compliance with the Dodd-Frank Act, it could have an adverse effect on our ability to hedge the risks associated with our business.

Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation. 

 In February 2009, the Obama administration released its budget proposals for the fiscal year 2010, which included numerous proposed tax changes.  In April 2009, legislation was introduced to further these objectives and in February 2010, the Obama administration released similar budget proposals for the fiscal year 2011.  The proposed budget and legislation would repeal many tax incentives and deductions that are currently used by U.S. oil and gas companies and impose new taxes.  Among others, the provisions include: elimination of the ability to fully deduct intangible drilling costs in the year incurred; repeal of the percentage depletion deduction for oil and gas properties; repeal of the manufacturing tax deduction for oil and gas companies; and an increase in the geological and geophysical amortization period for independent producers.  It is unclear whether any such changes will be enacted or how soon any such changes would become effective.  The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect the taxable income allocable to the unitholders. 

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

 On May 24, 2010, in connection with the execution and delivery of the Contribution Agreement pursuant to the Global Transaction Agreement, the Partnership issued 4,825,211 common units to Holdings as payment of the transaction fee contemplated by the Global Transaction Agreement.  The transaction fee of 4,825,211 common units was calculated by dividing the $29 million transaction fee by a unit price of $6.0101, which represents 90% of the 10-day volume weighted average trading price as of April 24, 2010.

 Pursuant to the terms of the Global Transaction Agreement, the NGP Parties exercised in full all rights received in respect of the 14,369,931 common and general partner units owned by them, resulting in the NGP Parties purchasing an aggregate of 5,029,472 common units and 5,029,472 warrants for aggregate cash consideration of $12,573,680.  The NGP Parties also exercised their oversubscription privileges resulting in the NGP Parties purchasing an additional aggregate of 473,758 common units and 473,758 warrants for aggregate cash consideration of $1,184,395.  These units were issued on or about July 8, 2010.

 On July 27, 2010, pursuant to the Global Transaction Agreement, we delivered notice to Holdings of our exercise of the option to purchase the interests in our general partner and our general partner’s general partner (the “GP Acquisition Option”).  As consideration for the exercise of the GP Acquisition Option, we issued 1,000,000 common units to Holdings on July 30, 2010.  The 844,551 general partner units were cancelled as a result of the exercise of the GP Acquisition Option.

 Because the issuance of the common units to Holdings as payment of the transaction fee, the issuance of the common units to the NGP Parties in connection with the rights offering and the issuance of the common units to Holdings in exchange for the general partner entities did not involve a public offering, the transactions are exempt from the registration requirements of the Securities Act of 1933 pursuant to Section 4(2) thereunder.

 The following table sets forth certain information with respect to repurchases of common units during the three months ended June 30, 2010:

Period	Total Number of Units Purchased		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, 2010 to April 30, 2010		—		—		—		—
May 1, 2010 to May 31, 2010		35,842	$	6.10		—		—
June 1, 2010 to June 30, 2010		—		—		—		—
Total		35,842	$	6.10		—		—

All of the units were surrendered by employees to pay tax withholding in connection with the vesting of restricted common units.  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. [Removed and Reserved.]

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Item 5.Other Information.

None.

Item 6. Exhibits.

3.1	Second Amended and Restated Agreement of Limited Partnership of the Partnership (incorporated by reference to Exhibit 3.1 of the registrant’s current report on Form 8-K filed with the Commission on May 25, 2010).
4.1	Subscription Agent Agreement, dated May 27, 2010, by and between the Partnership and American Stock Transfer & Trust Company, LLC (incorporated by reference to Exhibit 4.1 of the registrant’s current report on Form 8-K filed with the Commission on May 27, 2010).
4.2	Form of Transferable Subscription Rights Certificate to Purchase common units and warrants (incorporated by reference to Exhibit 4.2 of the registrant’s current report on Form 8-K filed with the commission on May 27, 2010).
4.3	Form of Warrant Agreement between the Partnership and American Stock Transfer & Trust Company, LLC (incorporated by reference to Exhibit 4.3 of the registrant’s current report on Form 8-K filed with the Commission on May 27, 2010).
10.1	Contribution Agreement, dated May 24, 2010, by and among the Partnership, Eagle Rock Holdings, L.P. and Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 10.1 of the registrant’s current report on Form 8-K filed with the Commission on May 25, 2010).
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.

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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 6, 2010	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.

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EAGLE ROCK ENERGY PARTNERS, L.P.

EXHIBIT INDEX

3.1	Second Amended and Restated Agreement of Limited Partnership of the Partnership (incorporated by reference to Exhibit 3.1 of the registrant’s current report on Form 8-K filed with the Commission on May 25, 2010).
4.1	Subscription Agent Agreement, dated May 27, 2010, by and between the Partnership and American Stock Transfer & Trust Company, LLC (incorporated by reference to Exhibit 4.1 of the registrant’s current report on Form 8-K filed with the Commission on May 27, 2010).
4.2	Form of Transferable Subscription Rights Certificate to Purchase common units and warrants (incorporated by reference to Exhibit 4.2 of the registrant’s current report on Form 8-K filed with the commission on May 27, 2010).
4.3	Form of Warrant Agreement between the Partnership and American Stock Transfer & Trust Company, LLC (incorporated by reference to Exhibit 4.3 of the registrant’s current report on Form 8-K filed with the Commission on May 27, 2010).
10.1	Contribution Agreement, dated May 24, 2010, by and among the Partnership, Eagle Rock Holdings, L.P. and Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 10.1 of the registrant’s current report on Form 8-K filed with the Commission on May 25, 2010).
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.