Eagle Rock Energy Partners L P (EROC) 10-Q 2011 Q3 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 September 30, 2011

OR

o 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  o

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  x   No  o

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  o	Accelerated filer  x
Non-accelerated filer  o	Smaller Reporting Company  o
(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  o    No  x

The issuer had 128,422,812 common units outstanding as of November 1, 2011.

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements	2
	Unaudited Condensed Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010	2
	Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2011 and 2010	3
	Unaudited Condensed Consolidated Statement of Members' Equity for the nine months ended September 30, 2011	5
	Unaudited Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2011 and 2010	6
	Notes to the Unaudited Condensed Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	45
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	68
Item 4.	Controls and Procedures	70
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	71
Item 1A.	Risk Factors	71
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	71
Item 3.	Defaults Upon Senior Securities	71
Item 4.	[Removed and Reserved]	71
Item 5.	Other Information	71
Item 6.	Exhibits	72

1

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

($ in thousands)

	September 30, 2011		December 31, 2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	17,662	$	4,049
Accounts receivable(a)	93,434		75,695
Risk management assets	18,577		—
Prepayments and other current assets	5,943		2,498
Assets held for sale	—		8,615
Total current assets	135,616		90,857
PROPERTY, PLANT AND EQUIPMENT — Net	1,716,875		1,137,239
INTANGIBLE ASSETS — Net	111,264		113,634
DEFERRED TAX ASSET	1,765		1,969
RISK MANAGEMENT ASSETS	38,568		1,075
OTHER ASSETS	21,043		4,623
TOTAL	$	2,025,131	$	1,349,397
LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	135,311	$	91,886
Due to affiliate	41		56
Accrued liabilities	21,843		10,940
Taxes payable	707		1,102
Risk management liabilities	4,073		39,350
Liabilities held for sale	—		1,705
Total current liabilities	161,975		145,039
LONG-TERM DEBT	740,904		530,000
ASSET RETIREMENT OBLIGATIONS	30,303		24,711
DEFERRED TAX LIABILITY	38,444		38,662
RISK MANAGEMENT LIABILITIES	4,594		31,005
OTHER LONG TERM LIABILITIES	2,473		867
COMMITMENTS AND CONTINGENCIES (Note 13)
MEMBERS' EQUITY (b)	1,046,438		579,113
TOTAL	$	2,025,131	$	1,349,397

________________________ 

(a) Net of allowance for bad debt of $2,009 as of September 30, 2011 and $4,496 as of December 31, 2010.

(b) 125,269,779 and 83,425,378 common units were issued and outstanding as of September 30, 2011 and December 31, 2010, respectively. These amounts do not include unvested restricted common units granted under the Partnership's long-term incentive plan of 2,006,278 and 1,744,454 as of September 30, 2011 and December 31, 2010, respectively.

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 Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
REVENUE:
Natural gas, natural gas liquids, oil, condensate and sulfur sales	$	269,790		$	159,303		$	738,162		$	516,276
Gathering, compression, processing and treating fees	11,567			12,093			37,116			40,806
Commodity risk management gains (losses)	94,313			(18,579		)	68,206			27,808
Other revenue	141			100			1,406			(115		)
Total revenue	375,811			152,917			844,890			584,775
COSTS AND EXPENSES:
Cost of natural gas, natural gas liquids, and condensate	171,964			106,682			491,957			353,227
Operations and maintenance	24,897			18,714			66,323			57,511
Taxes other than income	4,556			2,609			13,061			8,949
General and administrative	16,068			10,674			43,746			36,491
Other operating income	—			—			(2,893		)	—
Impairment	9,870			3,432			14,754			6,562
Depreciation, depletion and amortization	35,040			25,892			90,314			80,805
Total costs and expenses	262,395			168,003			717,262			543,545
OPERATING INCOME	113,416			(15,086		)	127,628			41,230
OTHER INCOME (EXPENSE):
Interest income	7			9			13			184
Interest expense	(10,057		)	(3,258		)	(19,592		)	(12,056		)
Interest rate risk management losses	(6,878		)	(8,282		)	(11,183		)	(27,300		)
Other (expense) income	(3		)	(30		)	(167		)	48
Total other (expense) income	(16,931		)	(11,561		)	(30,929		)	(39,124		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	96,485			(26,647		)	96,699			2,106
INCOME TAX (BENEFIT) PROVISION	(1,077		)	(1,244		)	(1,810		)	(970		)
INCOME (LOSS) FROM CONTINUING OPERATIONS	97,562			(25,403		)	98,509			3,076
DISCONTINUED OPERATIONS, NET OF TAX	(197		)	166			210			43,811
NET INCOME (LOSS)	$	97,365		$	(25,237	)	$	98,719		$	46,887

 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 Ended September 30,					Nine Months Ended September 30,
	2011		2010			2011		2010
NET INCOME PER COMMON UNIT—BASIC AND DILUTED:
Income from Continuing Operations
Common units - Basic	$	0.78	$	(0.31	)	$	0.92	$	0.05
Common units - Diluted	$	0.76	$	(0.31	)	$	0.88	$	0.05
Subordinated units - Basic and diluted								$	(0.02	)
General partner units - Basic and diluted			$	(0.34	)			$	0.05
Discontinued Operations
Common units - Basic	$	—	$	—		$	—	$	0.57
Common units - Diluted	$	—	$	—		$	—	$	0.57
Subordinated units - Basic and diluted								$	0.57
General partner units - Basic and diluted			$	—				$	0.57
Net Income
Common units - Basic	$	0.78	$	(0.31	)	$	0.92	$	0.62
Common units - Diluted	$	0.76	$	(0.31	)	$	0.88	$	0.62
Subordinated units - Basic and diluted								$	0.55
General partner units - Basic and diluted			$	(0.33	)			$	0.62
Weighted Average Units Outstanding (in thousands)
Common units - Basic	122,575		80,224			105,042		63,770
Common units - Diluted	128,077		80,224			111,657		63,950
Subordinated units - Basic and diluted								10,914
General partner units - Basic and diluted			275					653

See notes to unaudited condensed consolidated financial statements.  

4

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF MEMBERS’ EQUITY

(in thousands, except unit amounts)

	Number of Common Units		Common Units
BALANCE — January 1, 2011	83,425,378		$	579,113
Net income	—		98,719
Distributions	—		(49,080		)
Vesting of restricted units	62,071		—
Exercised warrants	13,039,928		78,239
Repurchase of common units	(10,772	)	(119		)
Equity based compensation	—		3,441
Units issued for acquisitions	28,753,174		336,125
BALANCE — September 30, 2011	125,269,779		$	1,046,438

 See notes to unaudited condensed consolidated financial statements.  

5

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

($ in thousands)

	Nine Months Ended September 30,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	98,719		$	46,887
Adjustments to reconcile net income to net cash provided by operating activities:
Discontinued operations	(210		)	(43,811		)
Depreciation, depletion and amortization	90,314			80,805
Impairment	14,754			6,562
Amortization of debt discount	67			—
Amortization of debt issuance costs	1,194			1,062
Write-off of debt issuance costs	427			—
Equity in earnings of unconsolidated affiliates	12			—
Distribution from unconsolidated affiliates—return on investment	55			67
Reclassing financing derivative settlements	(3,706		)	(1,001		)
Equity-based compensation	3,441			4,652
Loss on sale of assets	701			32
Other operating income	(2,893		)	—
Other	(1,338		)	954
Changes in assets and liabilities—net of acquisitions:
Accounts receivable	(1,020		)	21,108
Prepayments and other current assets	(180		)	1,001
Risk management activities	(114,403		)	(31,482		)
Accounts payable	(11,063		)	(11,020		)
Due to affiliates	(15		)	4
Accrued liabilities	10,987			1,542
Other assets	(376		)	1,043
Other current liabilities	(516		)	(1,598		)
Net cash provided by operating activities	84,951			76,807
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(79,811		)	(42,799		)
Acquisitions, net of cash acquired	(220,326		)	(4,139		)
Proceeds from sale of assets	5,712			171,686
Purchase of intangible assets	(3,122		)	(1,930		)
Net cash (used in) provided by investing activities	(297,547		)	122,818
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	826,379			37,000
Repayment of long-term debt	(913,379		)	(276,000		)
Proceeds from senior notes	297,837			—
Payment of debt issuance costs	(16,800		)	—
Proceeds from derivative contracts	3,706			1,001
Proceeds from rights offering	—			53,893
Exercise of warrants	78,239			1,708
Payment of transaction costs	—			(3,015		)
Repurchase of common units	(119		)	(724		)
Distributions to members and affiliates	(49,080		)	(5,102		)
Net cash provided by (used in) financing activities	226,783			(191,239		)
CASH FLOWS FROM DISCONTINUED OPERATIONS:
Operating activities	(574		)	9,034
Investing activities	—			(104		)
Net cash (used in) provided by discontinued operations	(574		)	8,930
NET INCREASE IN CASH AND CASH EQUIVALENTS	13,613			17,316
CASH AND CASH EQUIVALENTS—Beginning of period	4,049			2,732
CASH AND CASH EQUIVALENTS—End of period	$	17,662		$	20,048
NONCASH INVESTING AND FINANCING ACTIVITIES:
Units issued for acquisitions	$	336,125		$	2,089
Issuance of common units for transaction fee	$	—		$	29,000
Transaction fees, not paid	$	706		$	51
Investments in property, plant and equipment, not paid	$	28,860		$	8,714
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid—net of amounts capitalized	$	8,700		$	11,339
Cash paid for taxes	$	1,205		$	1,820

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., and the general partner of Eagle Rock Energy GP, L.P. is Eagle Rock Energy G&P, LLC, both of which are wholly-owned subsidiaries of Eagle Rock Energy. 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, 2010. 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 of the appropriate adjustments, all of which are normally recurring adjustments unless otherwise noted, considered necessary to present fairly the financial position of the Partnership and its consolidated subsidiaries and the results of operations and cash flows for the respective periods. Operating results for the three and nine months endedSeptember 30, 2011 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2011.

Description of Business—Eagle Rock Energy is a growth-oriented limited partnership engaged in (i) the business of gathering, compressing, treating, processing, transporting, marketing and trading natural gas; fractionating, transporting and marketing natural gas liquids ("NGLs"); and crude oil logistics and marketing (the “Midstream Business”); and (ii) the business of acquiring, developing and producing interests in oil and natural gas properties (the “Upstream Business”). The Partnership's natural gas pipelines gather natural gas from designated points near producing wells and transport these volumes to third-party pipelines, the Partnership's gas processing plants, utilities and industrial consumers. Natural gas transported to the Partnership's gas processing plants, either in the Partnership's pipelines or third party pipelines, is treated to remove contaminants and conditioned or processed into marketable natural gas and NGLs. The Partnership conducts its midstream operations within Louisiana and three geographic areas of Texas and accordingly reports its Midstream Business results through four segments: the Texas Panhandle Segment, the South Texas Segment, the East Texas/Louisiana Segment and the Gulf of Mexico Segment.  The Partnership reports its Upstream Business through one segment.

Other Reclassifications—Certain prior period financial statement balances have been reclassified to conform to the current year presentation. These reclassifications had no material effect on the recorded net income and are not significant.

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP"). Eagle Rock Energy is the owner of a non-operating undivided interest in the Indian Springs gas processing plant and the Camp Ruby gas gathering system. Eagle Rock Energy owns these interests as tenants-in-common with the majority owner-operator of the facilities. Accordingly, Eagle Rock Energy includes its pro-rata share of assets, liabilities, revenues and expenses related to these assets in its financial statements. All intercompany accounts and transactions are eliminated in the consolidated financial statements.

The preparation of financial statements in conformity with U.S. GAAP 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 and derivative valuations. 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, 2010. Certain items from that discussion are repeated or updated below as necessary to assist in understanding these financial statements.

7

Oil and Natural Gas Accounting Policies

The Partnership utilizes the successful efforts method of accounting for its oil and natural gas properties. Leasehold costs are capitalized when incurred. Costs incurred to drill and complete development wells 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 is found to have 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

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 negative revision or unfavorable 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 weighted average cost of capital. During each of the three and nine months endedSeptember 30, 2011 the Partnership incurred $9.7 million of impairment charges in its Upstream Segment, as the Partnership determined that the development of certain of its proved undeveloped properties in South Texas would not be economic at existing natural gas prices. During each of the three and nine months endedSeptember 30, 2010, the Partnership did not incur any impairment charges related to proved properties. 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. During the three months endedSeptember 30, 2011, the Partnership incurred $0.2 million of impairment charges related to certain drilling locations in its unproved properties which the Partnership no longer intends to develop. In addition, during the nine months endedSeptember 30, 2011, the Partnership also incurred $0.5 million of impairment charges related to certain drilling locations in its unproved properties which the Partnership no longer intends to develop based on the performance of offsetting wells. During the three and nine months ended September 30, 2010, the Partnership recorded impairment charges of $3.4 million in its Upstream Segment as the Partnership determined it would not be economical to develop certain unproved locations.

8

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 changes 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 second quarter of 2011, the Partnership recorded an impairment charge of $4.6 million in its Texas Panhandle Segment to fully write-down its idle Turkey Creek plant. The Partnership determined that the components of its Turkey Creek plant could not be used elsewhere within the business and thus the Partnership decided to remove all above ground equipment and structures. For the nine months ended September 30, 2010, the Partnership recorded impairment charges of $3.1 million related to its Midstream Business due to the notification during the second quarter 2010 that a significant gathering contract in its South Texas Segment would be terminated during the third quarter of 2010. During each of the three months endedSeptember 30, 2011 and 2010, the Partnership did not incur any impairment charges related to long-lived assets.

Other Significant Accounting Policies

Transportation and Exchange Imbalances—In the course of transporting natural gas and NGLs for others, the Partnership 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 are recovered or repaid through the receipt or delivery of natural gas or NGLs in future periods, if not subject to cash out provisions. Imbalance receivables are included in accounts receivable and imbalance payables are included in accounts payable on the consolidated balance sheets and marked-to-market using current market prices in effect for the reporting period of the outstanding imbalances. For the Midstream Business, as of September 30, 2011, the Partnership had imbalance receivables totaling $1.4 million and imbalance payables totaling $0.6 million. For the Midstream Business, as of December 31, 2010, the Partnership had imbalance receivables totaling $0.8 million and imbalance payables totaling $1.2 million. Changes in market value and the settlement of any such imbalance at a price greater than or less than the recorded imbalance results in either an upward or downward adjustment, as appropriate, to the cost of natural gas sold.

Inventory—Inventory is stated at the lower of cost or market, with cost being determined using the average cost method. At September 30, 2011 and December 31, 2010, the Partnership had $0.8 million and $0.5 million, respectively, of crude oil finished goods inventory which is recorded as part of Other Current Assets within the unaudited condensed consolidated balance sheet.

9

Revenue Recognition—Eagle Rock Energy's primary types of sales and service activities reported as operating revenue include:

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

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

• NGL transportation from which the Partnership generates revenues from transportation fees.

Revenues associated with sales of natural gas, NGLs, crude oil, condensate and sulfur 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 in the period when the services are provided.

For gathering and processing services, the Partnership either receives fees or commodities from natural gas producers under various types of contracts including percentage-of-proceeds, fixed recovery and percent-of-index arrangements. The Partnership also recognizes fee-based service revenues for services such as transportation, compression and processing.

The Partnership's Upstream Segment recognizes revenues based on the amount of 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 September 30, 2011 and December 31, 2010, the Partnership's Upstream Segment had an imbalance receivable balance of $1.4 million and $0.5 million, respectively, and it had a long-term payable balance of $1.4 million and zero as of September 30, 2011 and December 31, 2010, respectively.

Derivatives—Authoritative guidance establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires an entity to recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The guidance provides that normal purchase and sale contracts, when appropriately designated, are not subject to the guidance. Normal purchases and sales are contracts which provide for the purchase or sale of something, other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business. The Partnership's forward natural gas and crude oil purchase and sales contracts are designated as normal purchases and sales. The Partnership uses financial instruments such as swaps, collars and other derivatives to mitigate the risks to cash flows resulting from changes in commodity prices and interest rates. The Partnership recognizes these financial instruments on its consolidated balance sheet at the instrument's fair value with changes in fair value reflected in the consolidated statement of operations, as the Partnership has not designated any of these derivative instruments as hedges. The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as a financing activity in the statement of cash flows. See Note 11 for a description of the Partnership's risk management activities.

Fair Value Measurement—Authoritative guidance establishes accounting and reporting standards for assets and liabilities carried at fair value. The guidance provides definitions of fair value and expands the disclosure requirements with respect to fair value and specifies a hierarchy of valuation techniques based on the inputs used to measure fair value. See Note 12 for additional information regarding the Partnership's assets and liabilities carried at fair value.

NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS

In September 2009, the Financial Accounting Standards Board ("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.  This standard was effective for the Partnership on January 1, 2011 and did not have a material impact on the Partnership's financial statements. 

10

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 fair value disclosures guidance on January 1, 2010, except for the gross presentation of the Level 3 rollforward, which was adopted by the Partnership on January 1, 2011 (see Note 12).

In May 2011, the FASB issued additional guidance intended to result in convergence between U.S. GAAP and International Financial Reporting Standards (“IFRS”) requirements for measurement of and disclosures about fair value. The amendments are not expected to have a significant impact on companies applying U.S. GAAP. Key provisions of the amendments include: a prohibition on grouping financial instruments for purposes of determining fair value, except when an entity manages market and credit risks on the basis of the entity’s net exposure to the group; an extension of the prohibition against the use of a blockage factor to all fair value measurements (that prohibition currently applies only to financial instruments with quoted prices in active markets); and a requirement that for recurring Level 3 fair value measurements, entities disclose quantitative information about unobservable inputs, a description of the valuation process used and qualitative details about the sensitivity of the measurements. In addition, for items not carried at fair value but for which fair value is disclosed, entities will be required to disclose the level within the fair value hierarchy that applies to the fair value measurement disclosed. This guidance is effective for interim and annual periods beginning after December 15, 2011. The adoption of this guidance is not expected to have a significant impact on the Partnership’s fair value measurements, financial condition, results of operations or cash flows.

NOTE 4. ACQUISITIONS

Acquisition of CC Energy II L.L.C.

On May 3, 2011, the Partnership completed the acquisition (the "Crow Creek Acquisition") of all of the outstanding membership interests of CC Energy II L.L.C (together with its subsidiaries, "Crow Creek Energy"), a portfolio company of Natural Gas Partners, VIII, L.P. ("NGP VIII"). Crow Creek Energy has oil and natural gas properties located in multiple basins across Oklahoma, north Texas and Arkansas (the "Mid-Continent" properties) and provides the Partnership with an extensive inventory of low-risk development prospects in established plays such as the Golden Trend field and developing plays such as the Cana Shale. The aggregate purchase price of $563.7 million has been calculated as follows (in thousands, except unit and per unit amounts):

Number of Partnership Common Units Issued	28,753,174
Closing common unit price on May 3, 2011	$	11.69
Value of common units issued	$	336,125
Crow Creek Energy outstanding debt assumed	212,638
Cash	14,945
Total purchase price	$	563,708

The number of common units of the Partnership issued was determined based on the value of the equity issued to the sellers of $301.9 million divided by $10.50, the ceiling price of the agreed upon range in the contribution agreement between the Partnership and Crow Creek Energy. The cash portion of the acquisition consideration and the repayment of Crow Creek Energy’s outstanding debt were funded through borrowings under the Partnership’s revolving credit facility. In addition, the Partnership incurred $2.3 million of acquisition related expenses, which are included within general and administrative expenses for the nine months endedSeptember 30, 2011.

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The following presents the preliminary purchase price allocation for the Crow Creek Energy assets, based on preliminary estimates of fair value (in thousands):

Current assets	$	25,329
Oil and gas properties	572,548
Property, plant and equipment	4,463
Intangible assets	3,192
Other assets	450
Derivatives	3,355
Current liabilities	(37,032		)
Asset retirement obligations	(4,394		)
Deferred tax liability	(2,763		)
Other liabilities	(1,440		)
	$	563,708

As of September 30, 2011, the allocation of the purchase price is considered preliminary due to the pending final calculation of the deferred tax liability.

The amounts of Crow Creek Energy's revenue and net income included within the Partnership's unaudited condensed consolidated statement of operations for the nine months endedSeptember 30, 2011, and the pro forma revenue and net income of the combined entity had the acquisition date been January 1, 2010, are as follows:

	Revenue		Net Income		Net Income Per Diluted Common Unit
	($ in thousands)
Actual from May 3, 2011 to September 30, 2011	$	40,490	$	18,172
Supplemental pro forma from January 1, 2011 to September 30, 2011	$	865,946	$	104,178	$	0.94
Supplemental pro forma from January 1, 2010 to September 30, 2010	$	660,285	$	89,651	$	1.18

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NOTE 5. PROPERTY PLANT AND EQUIPMENT

Fixed assets consisted of the following:

	September 30, 2011			December 31, 2010
	($ in thousands)
Land	$	2,607		$	2,629
Plant	278,588			251,436
Gathering and pipeline	675,842			666,163
Equipment and machinery	29,139			26,408
Vehicles and transportation equipment	4,169			4,251
Office equipment, furniture, and fixtures	1,120			1,120
Computer equipment	9,187			8,486
Corporate	126			126
Linefill	4,324			4,269
Proved properties	1,000,229			471,781
Unproved properties	96,636			1,304
Construction in progress	39,370			42,416
	2,141,337			1,480,389
Less: accumulated depreciation, depletion and amortization	(424,462		)	(343,150		)
Net property plant and equipment	$	1,716,875		$	1,137,239

The following table sets forth the total depreciation, depletion and impairment expense by type of asset within the Partnership's unaudited condensed consolidated statement of operations (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	($ in thousands)
Depreciation	$	13,509	$	13,031	$	40,612	$	39,447
Depletion	$	18,612	$	6,787	$	40,918	$	23,751
Impairment expense:
Proved properties	$	9,705	$	—	$	9,705	$	—
Unproved properties	165		3,432		489		3,432
Plant assets	—		—		4,560		576
Pipeline assets	—		—		—		2,006
Total Impairment expense	$	9,870	$	3,432	$	14,754	$	6,014

The Partnership capitalizes interest costs on major projects during extended construction time periods. Such interest costs are allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. During the three and nine months endedSeptember 30, 2011 and 2010, the Partnership capitalized interest costs of $0.1 million, $0.2 million, $0.1 million, and $0.2 million, respectively.

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NOTE 6. ASSET RETIREMENT OBLIGATIONS

The Partnership recognizes asset retirement obligations for its oil and 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 conditional upon a future event that may or may not be within the Partnership's control. Although uncertainty about the timing and/or method of settlement may exist and may be conditional upon a future event, the obligation to perform the asset retirement activity is unconditional. Accordingly, the Partnership is required to recognize a liability for the fair value of a conditional asset retirement obligation upon initial recognition if the fair value of the liability can be reasonably estimated.

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

	Nine Months Ended September 30,
	2011			2010
	($ in thousands)
Asset retirement obligations—January 1	$	24,711		$	19,829
Additional liabilities	143			—
Liabilities settled	(264		)	(287		)
Additional liability related to acquisitions	4,439			—
Accretion expense	1,274			1,429
Asset retirement obligations—September 30	$	30,303		$	20,971

NOTE 7. 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. The Partnership recorded impairment charges of $0.5 million related to rights-of-way in the nine months ended September 30, 2010. The Partnership did not incur any impairment charges during the three and nine months endedSeptember 30, 2011 or the three months ended September 30, 2010 related to intangible assets. Amortization expense was approximately $2.9 million, $8.8 million, $6.1 million and $17.6 million for the three and nine months endedSeptember 30, 2011 and 2010, respectively. Estimated aggregate amortization expense for the remainder of 2011 and each of the four succeeding years is as follows: 2011—$3.0 million; 2012—$11.7 million; 2013—$10.5 million; 2014—$7.0 million; and 2015 —$7.0 million.  Intangible assets consisted of the following: 

	September 30, 2011			December 31, 2010
	($ in thousands)
Rights-of-way and easements—at cost	$	97,865		$	91,490
Less: accumulated amortization	(24,372		)	(20,552		)
Contracts	121,387			122,601
Less: accumulated amortization	(83,616		)	(79,905		)
Net intangible assets	$	111,264		$	113,634

The amortization period for the Partnership's rights-of-way and easements is 20 years. The amortization period for contracts ranges from 5 to 20 years and is approximately 8 years on average as of September 30, 2011.  

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NOTE 8. LONG-TERM DEBT

Long-term debt consisted of the following:

	September 30, 2011			December 31, 2010
	($ in thousands)
Revolving credit facility:	$	443,000		$	530,000
Senior notes:
8 3/8% senior notes due 2019	300,000			—
Unamortized bond discount senior notes due 2019	(2,096		)	—
Total senior notes	297,904			—
Total long-term debt	$	740,904		$	530,000

Revolving Credit Facility

On June 22, 2011, the Partnership entered into an Amended and Restated Credit Agreement (the “Credit Agreement”) with Wells Fargo Bank, National Association, as administrative agent and swingline lender, Bank of America, N.A. and The Royal Bank of Scotland plc, as co-syndication agents, BNP Paribas, as documentation agent, and the other lenders who are parties to the Credit Agreement. The Credit Agreement amended and restated the Partnership’s prior $880 million Credit Agreement (the “Prior Credit Agreement”). Upon the effectiveness of the Credit Agreement, all commitments of the lenders party to the Prior Credit Agreement were terminated and all loans and other indebtedness of the Partnership under the Prior Credit Agreement were renewed and extended, inclusive of new lender commitments, on the terms and conditions of the Credit Agreement. The Credit Agreement matures on June 22, 2016.

The credit facility under the Credit Agreement consists of aggregate initial commitments of $675 million that may, at the Partnership’s request and subject to the terms and conditions of the Credit Agreement, be increased up to an aggregate total amount of $1.2 billion. Availability under the credit facility is subject to a borrowing base comprised of two components: the upstream component and the midstream component. The upstream component of the borrowing base is determined semi-annually as an amount equal to the loan value of the proved oil and gas reserves of the Partnership and its subsidiaries as determined by the lenders party to the Credit Agreement. The midstream component of the borrowing base is determined quarterly as an amount equal to the lesser of (i) 55% of the total borrowing base (subject to increase for certain periods following certain material acquisitions up to 60% of the total borrowing base) and (ii) 3.75 times Consolidated EBITDA (as defined in the Credit Agreement) attributable to the midstream assets of the Partnership and its subsidiaries for the trailing four fiscal quarters. Pro forma adjustments to each component of the borrowing base, and thus total availability under the credit facility, are made upon the occurrence of certain events including material acquisitions and dispositions. Availability under the Credit Agreement is based on the lower of the current borrowing base and the total commitments. As of September 30, 2011, the Partnership had approximately $228.0 million of availability under the credit facility. The Partnership currently pays a 0.45% commitment fee per year on the difference between total commitments and the amount drawn under the credit facility.

The initial borrowings under the Credit Agreement were used to repay in full the borrowings under the Prior Credit Agreement and to pay fees and expenses incurred in connection with the Credit Agreement. Also, in connection with the Credit Agreement, the Partnership incurred debt issuance costs of $6.6 million and recorded a charge of $0.4 million to write off a portion of the unamortized debt issuance costs related to the Prior Credit Agreement. As of September 30, 2011, the Partnership had unamortized debt issuance costs of $7.2 million.

The Credit Agreement includes a sub-limit for the issuance of standby letters of credit for a total of $150 million. As of September 30, 2011, the Partnership had $0.2 million of outstanding letters of credit.

In general, at the Partnership's election, interest will accrue on the credit facility at either LIBOR plus a margin ranging from 1.75% to 2.75% (currently 2.25% per annum based on the Partnership's borrowing base utilization percentage) or the base rate plus a margin ranging from 0.75% to 1.75% (currently 1.25% per annum based on the Partnership's borrowing base utilization percentage). The applicable margin is determined based on the utilization of the then existing borrowing base. The borrowings under the Credit Agreement may be prepaid, without any premium or penalty, at any time. The base rate is generally the highest of the federal funds rate plus 0.5%, the prime rate as announced from time to time by the Administrative Agent, or daily LIBOR for a term of one month plus 1.0%. As of September 30, 2011, the weighted average interest rate (excluding the impact of interest rate swaps) on the Partnership's outstanding debt under its revolving credit facility was 2.48%.

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The obligations under the Credit Agreement are secured by first priority liens on substantially all of the Partnership’s material assets, including a pledge of all of the equity interests of each of the Partnership’s material subsidiaries.

The Credit Agreement requires the Partnership and certain of its subsidiaries to make certain representations and warranties that are customary for credit facilities of this type. The Credit Agreement also contains affirmative and negative covenants that are customary for credit facilities of this type, including compliance with financial covenants. The financial covenants prohibit the Partnership from:

• permitting, as of any fiscal quarter-end, the ratio of the Partnership’s Consolidated EBITDA (as defined in the Credit Agreement) for the four fiscal quarter period ending with such fiscal quarter to Consolidated Interest Expense (as defined in the Credit Agreement) for such four fiscal quarter period to be less than 2.50 to 1.00. The Partnership's interest rate coverage was 5.2 as of September 30, 2011;

• permitting, as of any fiscal quarter-end, the ratio of the Partnership's Total Funded Indebtedness (as defined in the Credit Agreement) to Consolidated EBITDA for the four fiscal quarter period ending with such fiscal quarter to be greater than 4.50 to 1.00. The Partnership's leverage ratio was 3.2 as of September 30, 2011; and

• permitting the ratio of the Partnership’s consolidated current assets (including availability under the Credit Agreement up to the loan limit, as defined within the Credit Agreement but excluding non-cash assets under the accounting guidance for derivatives) to consolidated current liabilities (excluding non-cash obligations under the accounting guidance for derivatives) to be less than 1.00 to 1.00. The Partnership's current ratio was 2.2 as of September 30, 2011

As of September 30, 2011, the Partnership was in compliance with the financial covenants under the Credit Agreement.

Senior Notes

On May 27, 2011, the Partnership, along with its subsidiary, Eagle Rock Energy Finance Corp. ("Finance Corp"), as co-issuer, issued $300 million of senior unsecured notes (the "Senior Notes") through a private placement. The Senior Notes bear a coupon of 8 3/8%. The Senior Notes will mature on June 1, 2019, and interest is payable on each June 1 and December 1, commencing December 1, 2011. After the original discount of $2.2 million and excluding related offering expenses, the Partnership received net proceeds of approximately $297.8 million, which were used to repay borrowings outstanding under the Prior Credit Agreement. As of September 30, 2011, the Partnership had an unamortized debt discount of $2.1 million, which is recorded as an offset to the principal amount of the Senior Notes, and unamortized debt issuance costs of $8.6 million.

The Senior Notes are general unsecured senior obligations and rank equally in right of payment with all of the Partnership's existing and future senior indebtedness and rank senior in right of payment to any of the Partnership's future subordinated indebtedness. The Senior Notes are effectively junior in right of payment to all of the Partnership's existing and future secured indebtedness and other obligations, including borrowings outstanding under the Partnership's Credit Agreement, to the extent of the value of the assets securing such indebtedness and other obligations. The Senior Notes are jointly and severally guaranteed on a senior unsecured basis by the Partnership's existing and future subsidiaries, who are referred to as the "subsidiary guarantors," that guarantee our credit facility or other indebtedness.

The indenture governing the Senior Notes, among other things, restricts the Partnership's ability and the ability of the Partnership's restricted subsidiaries to: (i) incur, assume or guarantee additional indebtedness or issue redeemable stock; (ii) pay dividends on stock, repurchase stock or redeem subordinated debt; (iii) make certain investments; (iv) enter into certain transactions with affiliates; (v) create liens on their assets; (vi) sell or otherwise dispose of certain assets, including capital stock of subsidiaries; (vii) restrict dividends, loans or other asset transfers from the Partnership's restricted subsidiaries; (viii) enter into new lines of business; and (ix) consolidate with or merge with or into, or sell all or substantially all of their properties (taken as a whole) to, another person.

The Partnership has the option to redeem all or a portion of the Senior Notes at any time on or after June 1, 2015 at the redemption prices specified in the indenture plus accrued and unpaid interest. The Partnership may also redeem the Senior Notes, in whole or in part, at a "make-whole" redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to June 1, 2015. In addition, the Partnership may redeem up to 35% of the Senior Notes prior to June 1, 2014 under certain circumstances with the net cash proceeds from certain equity offerings at 108.375% of the principal amount of the notes redeemed.

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In connection with the issuance and sale of the Senior Notes, the Partnership entered into a registration rights agreement (the "Senior Notes Registration Rights Agreement") with representatives of the initial purchasers. Pursuant to the Senior Notes Registration Rights Agreement, the Partnership agreed to file a registration statement with the Securities and Exchange Commission so that holders can exchange the Senior Notes for registered notes that have substantially identical terms as the Senior Notes and evidence the same indebtedness as the Senior Notes. In addition, the subsidiary guarantors agreed to exchange the guarantee related to the Senior Notes for a registered guarantee having substantially the same terms as the original guarantees. The Partnership is obligated to use commercially reasonable efforts to cause the exchange to be completed by June 30, 2012. If the Partnership fails to satisfy these obligations on a timely basis, it will be required to pay an additional 1% of interest to holders of the Senior Notes, until the exchange offer is completed or the shelf registration statement is declared (or becomes) effective, as applicable.

NOTE 9. MEMBERS’ EQUITY

At September 30, 2011, there were 125,269,779 common units outstanding. In addition, there were 2,006,278 unvested restricted common units outstanding.

During the nine months endedSeptember 30, 2011, 13,039,928 warrants were exercised for a total of 13,039,928 newly issued common units. As of September 30, 2011 and December 31, 2010, 7,625,317 and 20,665,245 warrants, respectively, were outstanding.

On February 7, 2011, the Partnership declared its fourth quarter 2010 cash distribution of $0.15 per unit to its common unitholders of record as of the close of business on February 14, 2011. The distribution was paid on February 14, 2011.

On April 26, 2011, the Partnership declared its first quarter 2011 cash distribution of $0.15 per unit to its common unitholders of record as of the close of business on May 9, 2011, except for the common units issued in connection with the Crow Creek Acquisition on May 3, 2011, which were not eligible to receive the first quarter 2011 distribution. The distribution was paid on May 13, 2011.  

On July 27, 2011, the Partnership declared its second quarter 2011 cash distribution of $0.1875 per unit to its common unitholders of record as of the close of business on August 5, 2011. The distribution was paid on August 12, 2011.

On October 26, 2011, the Partnership declared its third quarter 2011 cash distribution of $0.20 per unit to its common unitholders of record as of the close of business on November 7, 2011, except for the restricted units granted on November 1, 2011 (see Note 21). The distribution will be paid on November 14, 2011.

NOTE 10. RELATED PARTY TRANSACTIONS

During the three and nine months endedSeptember 30, 2011 and 2010, the Partnership purchased natural gas from certain companies affiliated with one or more NGP private equity firms and incurred $1.6 million, $4.8 million, $1.4 million and $5.4 million, respectively, in expenses owed to these related parties, of which there was an outstanding accounts payable balance of $0.5 million and $0.5 million as of September 30, 2011 and December 31, 2010, respectively.

The Partnership received services from Stanolind Field Services ("SFS"), which was an entity controlled by Natural Gas Partners ("NGP"). On August 2, 2010, SFS ceased being a related party of the Partnership because NGP sold all of its interests in SFS. During the three and nine months endedSeptember 30, 2010, the Partnership incurred approximately $0.2 million and $0.6 million, respectively, for services performed by SFS. As of both September 30, 2011 and December 31, 2010, there were no outstanding accounts payable balances to SFS.

As of both September 30, 2011 and December 31, 2010, the Partnership had an outstanding receivable balance of $0.7 million due from an affiliate of NGP.

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On May 3, 2011, the Partnership completed the Crow Creek Acquisition. Due to Crow Creek Energy being a portfolio company of NGP VIII and NGP's ownership interest in the Partnership and board of directors representation, the Board of Directors of the general partner of the Partnership's general partner, authorized its Conflicts Committee to review, evaluate, and, if determined appropriate, approve the Crow Creek Acquisition, due to the potential conflict of interest among the Partnership, the NGP Parties and the Partnership's public unitholders. The Conflicts Committee, consisting of independent directors of the Partnership, determined that the Crow Creek Acquisition was fair and reasonable to the Partnership and its public unitholders and recommended to the Board of Directors that the transaction be approved and authorized. In determining the consideration for the acquisition of Crow Creek Energy, the Conflicts Committee, with the assistance of a third-party, considered the valuation of the properties involved in the transaction, the valuation of the units to be offered as consideration in the transaction and the cash flows of Crow Creek Energy.

In connection with the closing of the Crow Creek Acquisition, the Partnership entered into a registration rights agreement ("Registration Rights Agreement") with NGP VIII. The Registration Rights Agreement grants NGP VIII and certain of its affiliates registration rights with respect to the common units acquired pursuant to the Partnership's acquisition of Crow Creek Energy and their outstanding warrants to purchase common units that were previously acquired by NGP VIII and certain of its affiliates in connection with the Partnership's previously completed recapitalization transaction. Pursuant to the Registration Rights Agreement, NGP VIII and certain of its affiliates have the ability to demand that the Partnership register for resale their common units acquired pursuant to the acquisition of Crow Creek Energy and their existing warrants to purchase common units. This registration may be an underwritten offering at the discretion of NGP VIII and certain of its affiliates. NGP VIII and certain of its affiliates may demand up to four such registrations, subject to an increase to up to seven if the registration rights are amended. Additionally, the Registration Rights Agreement provides that NGP VIII and certain of its affiliates have piggyback registration rights in certain circumstances, which would require inclusion of their common units and warrants on registration statements that the Partnership files, subject to certain customer exceptions. There are no limits on the number of times NGP VIII and certain of its affiliates can exercise these piggyback registration rights.

NOTE 11. RISK MANAGEMENT ACTIVITIES

Interest Rate Swap Derivative Instruments

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

On June 20, 2011, in conjunction with the refinancing of the credit facility under its Prior Credit Agreement (see Note 8), the Partnership consummated the following transactions to restructure certain of its interest rate swaps:

• Terminated a $150 million notional amount 2.56% fixed rate interest rate swap at a cost of $5.0 million; and

• Extended $250 million notional amount of its interest rate swaps from their original maturity date of December 31, 2012 to a new maturity date of June 22, 2015 and blended the existing swap rate for these extended swaps with the then prevailing interest rate swap rate, which lowered the rate from 4.095% to 2.95%. There was no cost associated with this extension.

The following table sets forth certain information regarding the Partnership's various interest rate swaps as of September 30, 2011:

Effective Date	Expiration Date	Notional Amount	Fixed Rate
9/30/2008	12/31/2012	150,000,000	4.295	%
10/3/2008	12/31/2012	50,000,000	4.095	%
6/22/2011	6/22/2015	250,000,000	2.95	%

The Partnership's interest rate derivative counterparties include Wells Fargo Bank National Association and The Royal Bank of Scotland plc.

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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 objectives and comply with the covenants of its revolving credit facility.  In order to manage the risks associated with changes in the future prices of crude oil, natural gas and NGLs on its forecast equity production, the Partnership engages in non-speculative risk management activities that take the form of commodity derivative instruments.  The Partnership has determined that it is necessary to hedge a substantial portion of its expected production in order to meaningfully reduce its future cash flow volatility.  The Partnership generally limits its hedging levels to 80%, on an incurrence basis, of expected future production and has historically hedged substantially less than 80%, on an incurrence basis, of its expected future production for periods beyond 24 months. 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.  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 flow 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.  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 expected future equity share of the commodities.

The Partnership uses fixed-price swaps, costless collars and put options 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 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 may use natural gas hedges to hedge a portion of its expected future ethane production because forward prices for ethane are often heavily discounted from its current prices.  Also, natural gas prices provide support for ethane prices because in many processing plants ethane can be recombined with the residue gas stream and sold as natural gas.  When the Partnership uses cross-commodity hedging, it will convert the expected volumes of the underlying commodity to equivalent volumes of the hedged commodity.  In the case of NGLs hedged with crude oil derivatives, these conversions are based on the linear regression of the prices of the two commodities observed during the previous 36 months and management's judgment regarding future price relationships of the commodities.  In the case where ethane is hedged with natural gas derivatives, the conversion is based on the thermal content of ethane.

The Partnership has not designated, for accounting purposes, any of its commodity derivative instruments as hedges and therefore marks these derivative contracts to fair value (see Note 12).  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.

By using derivative instruments to economically hedge exposure to changes in commodity prices, the Partnership exposes itself to counterparty credit risk. Historically, the Partnership's counterparties have all been participants or affiliates of participants within its revolving credit facility (see Note 8), which is secured by substantially all of the assets of the Partnership. Therefore, the Partnership is not required to post any collateral, nor does it require collateral from its counterparties. In July 2011, the Partnership created a subsidiary to enhance its ability to market natural gas on behalf of itself and third parties. This subsidiary, through its financial derivative activity, will have credit exposure to additional counterparties. The Partnership minimizes the credit risk in derivative instruments by limiting its exposure to any single counterparty and monitoring the creditworthiness of its counterparties on an ongoing basis. In addition, the Partnership's derivative contracts, for certain counterparties, are subject to counterparty netting agreements governing such derivatives.

The Partnership's commodity derivative counterparties include BNP Paribas, Wells Fargo Bank, National Association, Comerica Bank, Bank of Nova Scotia, The Royal Bank of Scotland plc, Bank of America N.A., J Aron and Company (an affiliate of Goldman Sachs), ING Capital Markets LLC and BBVA Compass Bank.

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During the three months ended September 30, 2011, the Partnership entered into the following hedging transactions:

• 840,000 gallon per month OPIS propane swap at $1.39 per gallon for its 2012 calendar year;

• 184,800 gallon per month OPIS isobutane swap at $1.79 per gallon for its 2012 calendar year;

• 369,600 gallon per month OPIS normal butane swap at $1.75 per gallon for its 2012 calendar year;

• 92,400 gallon per month OPIS natural gasoline swap at $2.2125 per gallon for its 2012 calendar year;

• 819,000 gallon per month OPIS propane swap at $1.407 per gallon for its 2012 calendar year;

• 168,000 gallon per month OPIS isobutane swap at $1.8541 per gallon for its 2012 calendar year;

• 84,000 gallon per month OPIS natural gasoline swap at $2.3166 per gallon for its 2012 calendar year; and

• 352,800 gallon per month OPIS normal butane swap at $1.7978 per gallon for its 2012 calendar year.

The following tables set forth certain information regarding the Partnership's commodity derivatives. Within each table, some trades of the same commodities with the same tenors have been aggregated and shown as weighted averages.

Commodity derivatives, as of September 30, 2011, that will mature during the year ended December 31, 2011:

Underlying	Period	Notional Volumes (units)	Type	Weighted Average Floor Strike Price ($/unit)		Weighted Average Cap Strike Price ($/unit)
Natural Gas:
NYMEX Henry Hub	Oct-Dec 2011	300,000 mmbtu	Costless Collar	$	7.500	$	8.850
IF Panhandle East	Oct-Dec 2011	480,000 mmbtu	Costless Collar	5.844		7.631
IF Panhandle East	Oct-Dec 2011	150,000 mmbtu	Put	5.000
IF Centerpoint East	Oct-Dec 2011	240,000 mmbtu	Put	5.375
NYMEX Henry Hub	Oct-Dec 2011	975,000 mmbtu	Swap	6.248
NYMEX Henry Hub	Oct-Dec 2011	(102,000) mmbtu	Swap	4.450
IF Panhandle East	Oct-Dec 2011	1,110,000 mmbtu	Swap	5.887
IF Centerpoint East	Oct-Dec 2011	330,000 mmbtu	Swap	5.375
Crude Oil:
NYMEX WTI	Oct-Dec 2011	184,788 bbls	Costless Collar	78.085		92.746
NYMEX WTI	Oct-Dec 2011	24,000 bbls	Put	55.000
NYMEX WTI	Oct-Dec 2011	247,314 bbls	Swap	75.068
Natural Gas Liquids:
OPIS Nbutane Mt. Belv non TET	Oct-Dec 2011	2,898,000 gallons	Swap	1.500
OPIS IsoButane Mt. Belv non TET	Oct-Dec 2011	1,386,000 gallons	Swap	1.543
OPIS Natural Gasoline Mt. Belv non TET	Oct-Dec 2011	1,134,000 gallons	Swap	1.853
OPIS Propane Mt. Belv non TET	Oct-Dec 2011	5,796,000 gallons	Swap	1.173
OPIS Ethane Mt. Belv non TET	Oct-Dec 2011	10,584,000 gallons	Swap	0.631

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Commodity derivatives, as of September 30, 2011, that will mature during the year ended December 31, 2012:

Underlying	Period	Notional Volumes (units)	Type	Weighted Average Floor Strike Price ($/unit)		Weighted Average Cap Strike Price ($/unit)
Natural Gas:
NYMEX Henry Hub	Jan-Dec 2012	1,080,000 mmbtu	Costless Collar	$	7.350	$	8.650
IF Panhandle East	Jan-May 2012	1,350,000 mmbtu	Costless Collar	5.287		6.912
IF Panhandle East	Jan-Dec 2012	1,680,000 mmbtu	Costless Collar	4.364		5.476
NYMEX Henry Hub	Jan-Dec 2012	6,480,000 mmbtu	Swap	5.854
IF Panhandle East	Jan-May 2012	750,000 mmbtu	Swap	5.715
IF Panhandle East	Jan-Dec 2012	720,000 mmbtu	Swap	5.110
IF Centerpoint East	Jan-May 2012	300,000 mmbtu	Swap	5.795
IF Centerpoint East	Jun-Dec 2012	3,150,000 mmbtu	Swap	5.715
Crude Oil:
NYMEX WTI	Jan-Dec 2012	699,576 bbls	Costless Collar	77.631		95.314
NYMEX WTI	Jan-May 2012	50,000 bbls	Costless Collar	70.000		101.705
NYMEX WTI	Jan-Jun 2012	18,000 bbls	Costless Collar	70.000		92.740
NYMEX WTI	June 2012	54,000 bbls	Costless Collar	73.889		107.669
NYMEX WTI	Jul-Dec 2012	10,000 bbls	Costless Collar	75.000		112.500
NYMEX WTI	Jan-Dec 2012	984,468 bbls	Swap	83.608
NYMEX WTI	Jul-Dec 2012	12,000 bbls	Swap	81.500
Natural Gas Liquids:
OPIS Nbutane Mt. Belv non TET	Jan-Dec 2012	8,668,800 gallons	Swap	1.773
OPIS IsoButane Mt. Belv non TET	Jan-Dec 2012	4,233,600 gallons	Swap	1.821
OPIS Natural Gasoline Mt. Belv non TET	Jan-Dec 2012	2,116,800 gallons	Swap	2.262
OPIS Propane Mt. Belv non TET	Jan-Dec 2012	19,908,000 gallons	Swap	1.398

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Commodity derivatives, as of September 30, 2011, that will mature during the year ended December 31, 2013:

Underlying	Period	Notional Volumes (units)	Type	Weighted Average Floor Strike Price ($/unit)		Weighted Average Cap Strike Price ($/unit)
Natural Gas:
IF Panhandle East	Jan-Dec 2013	1,440,000 mmbtu	Costless Collar	$	4.450	$	5.430
IF Panhandle East	Jan-May 2013	700,000 mmbtu	Costless Collar	5.100		5.610
IF Panhandle East	Jun-Dec 2013	1,400,000 mmbtu	Costless Collar	5.100		5.450
NYMEX Henry Hub	Jan-Dec 2013	6,660,000 mmbtu	Swap	5.350
IF Centerpoint East	Jan-May 2013	500,000 mmbtu	Swap	5.970
IF Panhandle East	Jan-May 2013	500,000 mmbtu	Swap	5.353
IF Panhandle East	Jun-Dec 2013	910,000 mmbtu	Swap	5.260
Crude Oil:
NYMEX WTI	Jan-Dec 2013	36,000 bbls	Costless Collar	80.000		108.000
NYMEX WTI	Jan-Mar 2013	27,000 bbls	Costless Collar	78.085		92.746
NYMEX WTI	Apr-Dec 2013	36,000 bbls	Costless Collar	70.000		96.410
NYMEX WTI	Jan-Dec 2013	1,704,000 bbls	Swap	76.194
NYMEX WTI	Apr-Dec 2013	27,000 bbls	Swap	81.950

Commodity derivatives, as of September 30, 2011, that will mature during the year ended December 31, 2014:

Underlying	Period	Notional Volumes (units)	Type	Weighted Average Floor Strike Price ($/unit)		Weighted Average Cap Strike Price ($/unit)
Natural Gas:
NYMEX Henry Hub	Jan-Dec 2014	4,200,000 mmbtu	Swap	$	5.546
Crude Oil:
NYMEX WTI	Jan-Dec 2014	540,000 bbls	Swap	102.450

Commodity Derivative Instruments - Marketing & Trading

During the three months endedSeptember 30, 2011, the Partnership created a subsidiary to conduct natural gas marketing and trading activities. This subsidiary engages in activities intended to capitalize on favorable price differentials between various receipt and delivery locations. The subsidiary's activities are governed by its risk policy.

The subsidiary enters into both financial derivatives and physical contracts. The subsidiary's financial derivatives, primarily basis swaps, are transacted: (i) to economically hedge subscribed capacity exposed to market rate fluctuations, and (ii) to mitigate the price risk related to other purchase and sales of natural gas. By entering into a basis swap, one pricing index is exchanged for another, effectively locking in the margin between the natural gas purchase and sale by removing index spread risk on the combined physical and financial transaction. Financial derivatives are transacted to mitigate price risk, and are not transacted with the sole purpose of taking a directional view of the market.

Changes in the fair value of the contracts that are hedging transportation and purchases are recorded as adjustments to the cost of natural gas, while changes in the fair value of the contracts that are hedging sales are recorded as adjustments to natural gas sales.

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Physical contracts that qualify for the normal purchase - normal sale scope exemption are not accounted for as derivatives, while those that do not qualify for the exemption are accounted for as derivatives derivatives and are marked-to-market each period. Changes in the fair value of physical contracts accounted for as derivatives to purchase natural gas are recorded as adjustments to the cost of natural gas, while changes in the fair value of physical contracts accounted for as derivatives to sell natural gas are recorded as adjustments to natural gas sales. The income or loss related to the physical contracts that qualify for the normal purchase-normal sale scope exemption are recognized when the contracts settle.

Fair Value of Interest Rate and Commodity Derivatives

Fair values of interest rate and commodity derivative instruments not designated as hedging instruments in the consolidated balance sheet as of September 30, 2011 and December 31, 2010:

	As of September 30, 2011
	Derivative Assets				Derivative Liabilities
	Balance Sheet Classification	Fair Value			Balance Sheet Classification	Fair Value
	($ in thousands)
Interest rate derivatives - liabilities	Current assets	$	(6,452	)	Current liabilities	$	(5,589	)
Interest rate derivatives - liabilities	Long-term assets	(10,314		)	Long-term liabilities	(5,058		)
Commodity derivatives - assets	Current assets	35,106			Current liabilities	2,028
Commodity derivatives - assets	Long-term assets	49,878			Long-term liabilities	464
Commodity derivatives - liabilities	Current assets	(10,077		)	Current liabilities	(512		)
Commodity derivatives - liabilities	Long-term assets	(996		)	Long-term liabilities	—
Total derivatives		$	57,145			$	(8,667	)
	As of December 31, 2010
	Derivative Assets				Derivative Liabilities
	Balance Sheet Classification	Fair Value			Balance Sheet Classification	Fair Value
	($ in thousands)
Interest rate derivatives - liabilities		$	—		Current liabilities	$	(19,822	)
Interest rate derivatives - liabilities		—			Long-term liabilities	(14,757		)
Commodity derivatives - assets		—			Current liabilities	9,150
Commodity derivatives - assets	Long-term assets	2,402			Long-term liabilities	5,347
Commodity derivatives - liabilities		—			Current liabilities	(28,678		)
Commodity derivatives - liabilities	Long-term assets	(1,327		)	Long-term liabilities	(21,595		)
Total derivatives		$	1,075			$	(70,355	)

The following table sets forth the location of gains and losses for derivatives not designated as hedging instruments within the Partnership's unaudited condensed consolidated statement of operations (in thousands):

Amount of Gain (Loss) Recognized in Income on Derivatives		Three Months Ended September 30,						Nine Months Ended September 30,
		2011			2010			2011			2010
Interest rate derivatives	Interest rate risk management losses	$	(6,878	)	$	(8,282	)	$	(11,183	)	$	(27,300	)
Commodity derivatives	Commodity risk management gains (losses)	94,313			(18,579		)	68,206			27,808
Commodity derivatives -trading	Natural gas, natural gas liquids, oil, condensate and sulfur sales	940			—			940			—
Commodity derivatives -trading	Cost of natural gas, natural gas liquids, and condensate	(402		)	—			(402		)	—
	Total	$	87,973		$	(26,861	)	$	57,561		$	508

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NOTE 12. 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 executed in the marketplace.

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

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As of September 30, 2011, the Partnership has recorded its interest rate swaps and commodity derivative instruments (see Note 11), which includes crude oil, natural gas and NGLs, at fair value. The Partnership reviews the classification of the inputs at the end of each period and has classified the inputs to measure the fair value of its interest rate swaps, crude oil derivatives and natural gas derivatives as Level 2.  In prior periods, the Partnership has classified the inputs to measure its NGL derivatives as Level 3 as the NGL market was considered to be less liquid and thinly traded. As of September 30, 2011, the Partnership concluded that the inputs for its NGL derivatives were considered to be more observable due to the NGL market being more liquid through the term of our contracts and has classified these inputs as Level 2. The following table discloses the fair value of the Partnership's derivative instruments as of September 30, 2011 and December 31, 2010: 

	As of September 30, 2011
	Level 1		Level 2			Level 3		Netting (a)			Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	44,840		$	—	$	(7,451	)	$	37,389
Natural gas derivatives	—		39,937			—		(460		)	39,477
NGL derivatives	—		2,650			—		(5,605		)	(2,955		)
Interest rate swaps	—		—			—		(16,766		)	(16,766		)
Total	$	—	$	87,427		$	—	$	(30,282	)	$	57,145
Liabilities:
Crude oil derivatives	$	—	$	(5,350	)	$	—	$	7,451		$	2,101
Natural gas derivatives	—		(581		)	—		460			(121		)
NGL derivatives	—		(5,605		)	—		5,605			—
Interest rate swaps	—		(27,413		)	—		16,766			(10,647		)
Total	$	—	$	(38,949	)	$	—	$	30,282		$	(8,667	)

____________________________

(a) Represents counterparty netting under agreement governing such derivative contracts.

	As of December 31, 2010
	Level 1		Level 2			Level 3			Netting (a)			Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	—		$	—		$	(1,292	)	$	(1,292	)
Natural gas derivatives	—		16,731			—			(14,364		)	2,367
NGL derivatives	—		—			168			(168		)	—
Total	$	—	$	16,731		$	168		$	(15,824	)	$	1,075
Liabilities:
Crude oil derivatives	$	—	$	(45,664	)	$	—		$	1,292		$	(44,372	)
Natural gas derivatives	—		(35		)	—			14,364			14,329
NGL derivatives	—		—			(5,901		)	168			(5,733		)
Interest rate swaps	—		(34,579		)	—			—			(34,579		)
Total	$	—	$	(80,278	)	$	(5,901	)	$	15,824		$	(70,355	)

____________________________

(a) Represents counterparty netting under agreement governing such derivative contracts.

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The following table sets forth a reconciliation of changes in the fair value of the Level 3 NGL derivatives during the three and nine months endedSeptember 30, 2011 and 2010 (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Net liability beginning balance	$	(9,632	)	$	(1,860	)	$	(5,733	)	$	(14,784	)
Settlements	6,156			1,466			15,562			7,860
Total gains or losses (realized and unrealized)	521			(2,823		)	(12,784		)	3,707
Transfers out of Level 3	2,955			—			2,955			—
Net liability ending balance	$	—		$	(3,217	)	$	—		$	(3,217	)

The Partnership values its Level 3 NGL derivatives using forward curves, interest rate curves, and volatility parameters, when applicable. In addition, the impact of counterparty credit risk is factored into the value of derivative assets, and the Partnership's credit risk is factored into the value of derivative liabilities.

The Partnership recognized (losses) gains of $(2.2) million and $0.4 million in the three and nine months endedSeptember 30, 2010, that are attributable to the change in unrealized gains or losses related to those Level 3 assets and liabilities still held at September 30, 2010, which are included in the commodity risk management (losses) gains.  

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 premium amortization related to the Partnership's commodity derivatives are recorded as a component of revenue in the unaudited condensed consolidated statements of operations. 

Fair Value of Assets and Liabilities Measured on a Non-recurring Basis

The following table discloses the fair value of the Partnership's assets measured at fair value on a nonrecurring basis for the three months ended September 30, 2011 (in thousands):

	September 30, 2011		Level 1		Level 2		Level 3		Total Losses
Proved properties	$	2,998	$	—	$	—	$	2,998	$	9,705

In connection with the preparation of these financial statements for the nine months ended September 30, 2011, the Partnership wrote down proved properties with a carrying value of $12.7 million to their fair value of $3.0 million, resulting in an impairment charge of $9.7 million being included in earnings for the three and nine months ended September 30, 2011. The impairment charges related to proved properties in the Upstream Segment which reflected future drilling locations in a specific South Texas field that were no longer economical in the current natural gas price environment. 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. For the other assets impaired by the partnership during the three and nine months endedSeptember 30, 2011, the assets were fully written down and are thus not included in the table above.

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

As of September 30, 2011, the outstanding debt associated with the Credit Agreement bore interest at a floating rate; as such, the Partnership believes that the carrying value of this debt approximates its fair value. The outstanding debt associated with the Senior Notes bears interest at a fixed rate; based on the market price of the Senior Notes as of September 30, 2011, the Partnership estimates that the fair value of the Senior Notes is $292.3 million compared to a carrying value of $297.9 million.

NOTE 13. 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 had no accruals as of September 30, 2011 and December 31, 2010 related to legal matters, and

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current lawsuits are not expected to have a material adverse effect on our financial position, results of operations or cash flows. The Partnership has been indemnified up to a certain dollar amount for two lawsuits. If there ultimately is a finding against the Partnership in these two indemnified cases, the Partnership would expect to make a claim against the indemnification up to limits of the indemnification.

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 its employees on company business; (4) property insurance covering the replacement cost of all owned real and personal property, including coverage for losses due to boiler and machinery breakdown, earthquake, flood and consequent business interruption/extra expense; (5) control of well/operator's extra expense insurance for operated and non-operated wells in the Upstream Segment; and (6) corporate liability insurance including coverage for Directors and Officers and Employment Practices liabilities.  In addition, 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.

Environmental—The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, the Partnership must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership's combined results of operations, financial position or cash flows. At September 30, 2011 and December 31, 2010, the Partnership had accrued approximately $3.9 million and $4.0 million, respectively, for environmental matters.

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

The retained revenue interests affect the Partnership's interest at the Big Escambia Creek, Flomaton and Fanny Church fields in Escambia County, Alabama. With respect to the Partnership's Flomaton and Fanny Church fields, these retained revenue interests are in effect for any calendar year in which the Partnership surpasses certain average net production rates. The Partnership did not surpass such rates in 2010 and does not anticipate doing so in 2011. With respect to the Partnership's Big Escambia Creek field, the retained revenue interest commenced in 2010 and continues through the end of 2019.

Other Commitments—The Partnership utilizes assets under operating leases for its corporate office, certain rights-of-way and facilities locations, vehicles and in several areas of its operations. Rental expense, including leases with no continuing commitment, amounted to approximately $1.8 million, $6.1 million, $1.7 million and $5.1 million for the three and nine months endedSeptember 30, 2011 and 2010, 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 14. SEGMENTS

On May 24, 2010, the Partnership completed the sale of its Minerals Business, and on May 20, 2011, the Partnership completed its sale of the Wildhorse Gathering System, which was previously reported under the South Texas Segment. As authoritative guidance requires, the operations for components of entities disposed of shall be recorded as part of discontinued operations. Operating results for the Minerals Business for the three and nine months ended September 30, 2010 and operating results for the the Wildhorse Gathering System for each of the three and nine months ended September 30, 2011 and 2010, have been excluded from the Partnership’s segment presentation below. See Note 18 for a further discussion of the sale of the Partnership’s Minerals Business and the Wildhorse System.

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 and one functional (Corporate) segment:

(i) Midstream—Texas Panhandle Segment:

gathering, compressing, treating, processing and transporting natural gas; fractionating, transporting and marketing NGLs; crude oil logistics and marketing in the Texas Panhandle and Alabama; and marketing and trading natural gas;

(ii) Midstream—South Texas Segment:

gathering, compressing, processing and treating natural gas and marketing of natural gas, NGLs and condensate in South 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, NGLs and sulfur production from operated and non-operated wells; and

(vi) Corporate and Other Segment:

 risk management, intersegment eliminations 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 tables:

Midstream Business Three Months Ended September 30, 2011	Texas Panhandle Segment		South Texas Segment			East Texas / Louisiana Segment		Gulf of Mexico Segment			Midstream Intersegment Eliminations			Total Midstream Business
($ in thousands)
Sales to external customers	$	164,566	$	9,248		$	47,833	$	9,184		$	—		$	230,831
Intersegment sales	—		2,223			2,107		—			(4,330		)	—
Cost of natural gas and natural gas liquids	115,428		10,910			37,892		7,734			—			171,964
Intersegment cost of natural gas, oil and condensate	14,558		—			—		—			(4,330		)	10,228
Operating costs and other (income) expenses	10,828		400			4,990		498			—			16,716
Depreciation, depletion, amortization and impairment	9,145		735			4,589		1,624			—			16,093
Operating income (loss) from continuing operations	$	14,607	$	(574	)	$	2,469	$	(672	)	$	—		$	15,830
Capital Expenditures	$	22,432	$	1		$	3,618	$	4		$	—		$	26,055
Segment Assets	$	601,729	$	46,760		$	251,582	$	76,681		$	—		$	976,752

Total Segments Three Months Ended September 30, 2011	Total Midstream Business		Upstream Segment		Corporate and Other Segment				Total Segments
($ in thousands)
Sales to external customers	$	230,831	$	50,667	$	94,313		(a)	$	375,811
Intersegment sales	—		8,854		(8,854		)		—
Cost of natural gas and natural gas liquids	171,964		—		—				171,964
Intersegment cost of natural gas, oil and condensate	10,228		—		(10,228		)		—
Operating costs and other (income) expenses	16,716		12,737		16,068				45,521
Depreciation, depletion, amortization and impairment	16,093		28,506		311				44,910
Operating income from continuing operations	$	15,830	$	18,278	$	79,308			$	113,416
Capital Expenditures	$	26,055	$	31,868	$	589			$	58,512
Segment Assets	$	976,752	$	960,963	$	87,416		(b)	$	2,025,131

Midstream Business Three Months Ended September 30, 2010	Texas Panhandle Segment		South Texas Segment		East Texas / Louisiana Segment		Gulf of Mexico Segment			Total Midstream Business
($ in thousands)
Sales to external customers	$	81,726	$	12,992	$	46,206	$	7,834		$	148,758
Cost of natural gas and natural gas liquids	54,783		11,321		33,940		6,638			106,682
Operating costs and other expenses	9,155		390		4,502		354			14,401
Depreciation, depletion, amortization and impairment	11,702		699		4,631		1,651			18,683
Operating income (loss) from continuing operations	$	6,086	$	582	$	3,133	$	(809	)	$	8,992
Capital Expenditures	$	12,636	$	5	$	1,678	$	21		$	14,340
Segment Assets	$	523,933	$	50,946	$	306,839	$	83,561		$	965,279

Total Segments Three Months Ended September 30, 2010	Total Midstream Business		Upstream Segment		Corporate and Other Segment				Total Segments
($ in thousands)
Sales to external customers	$	148,758	$	22,738	$	(18,579	)	(a)	$	152,917
Cost of natural gas and natural gas liquids	106,682		—		—				106,682
Operating costs and other expenses	14,401		6,922		10,674				31,997
Depreciation, depletion, amortization and impairment	18,683		10,242		399				29,324
Operating income from continuing operations	$	8,992	$	5,574	$	(29,652	)		$	(15,086	)
Capital Expenditures	$	14,340	$	5,235	$	366			$	19,941
Segment Assets	$	965,279	$	353,262	$	51,218			$	1,369,759

_________________________________

(a) Represents results of the Partnership's commodity risk management activity.

(b) Includes elimination of intersegment transactions.

29

Midstream Business Nine Months Ended September 30, 2011	Texas Panhandle Segment		South Texas Segment			East Texas / Louisiana Segment		Gulf of Mexico Segment			Midstream Intersegment Eliminations			Total Midstream Business
($ in thousands)
Sales to external customers	$	449,730	$	31,268		$	158,647	$	28,081		$	—		$	667,726
Intersegment sales	—		2,223			2,107		—			(4,330		)	—
Cost of natural gas and natural gas liquids	315,755		31,544			120,946		23,712			—			491,957
Intersegment cost of natural gas,oil and condensate	35,550		—			—		—			(4,330		)	31,220
Operating costs and other expenses	31,436		1,055			14,193		1,397			—			48,081
Depreciation, depletion, amortization and impairment	31,942		2,208			13,706		4,954			—			52,810
Operating income (loss) from continuing operations	$	35,047	$	(1,316	)	$	11,909	$	(1,982	)	$	—		$	43,658
Capital Expenditures	$	37,999	$	90		$	5,992	$	37		$	—		$	44,118
Segment Assets	$	601,729	$	46,760		$	251,582	$	76,681		$	—		$	976,752

Total Segments Nine Months Ended September 30, 2011	Total Midstream Business		Upstream Segment			Corporate and Other Segment				Total Segments
($ in thousands)
Sales to external customers	$	667,726	$	108,958	(c)	$	68,206		(a)	$	844,890
Intersegment sales	—		31,378			(31,378		)		—
Cost of natural gas and natural gas liquids	491,957		—			—				491,957
Intersegment cost of natural gas, oil and condensate	31,220		—			(31,220		)		—
Operating costs and other (income) expenses	48,081		31,303			40,853				120,237
Intersegment operations and maintenance	—		66			(66		)		—
Depreciation, depletion, amortization and impairment	52,810		51,240			1,018				105,068
Operating income (loss) from continuing operations	$	43,658	$	57,727		$	26,243			$	127,628
Capital Expenditures	$	44,118	$	56,688		$	1,121			$	101,927
Segment Assets	$	976,752	$	960,963		$	87,416		(b)	$	2,025,131

Midstream Business Nine Months Ended September 30, 2010	Texas Panhandle Segment		South Texas Segment			East Texas / Louisiana Segment		Gulf of Mexico Segment			Total Midstream Business
($ in thousands)
Sales to external customers	$	259,404	$	46,410		$	157,348	$	24,121		$	487,283
Cost of natural gas and natural gas liquids	176,485		41,624			114,622		20,496			353,227
Operating costs and other expenses	25,666		1,530			12,921		1,390			41,507
Depreciation, depletion, amortization and impairment	34,931		5,345			13,171		4,821			58,268
Operating income (loss) from continuing operations	$	22,322	$	(2,089	)	$	16,634	$	(2,586	)	$	34,281
Capital Expenditures	$	23,405	$	36		$	7,658	$	39		$	31,138
Segment Assets	$	523,933	$	50,946		$	306,839	$	83,561		$	965,279

Total Segments Nine Months Ended September 30, 2010	Total Midstream Business		Upstream Segment			Corporate and Other Segment				Total Segments
($ in thousands)
Sales to external customers	$	487,283	$	69,684		$	27,808		(a)	$	584,775
Cost of natural gas and natural gas liquids	353,227		—			—				353,227
Operating costs and other expenses	41,507		24,953		(d)	36,491				102,951
Depreciation, depletion, amortization and impairment	58,268		27,865			1,234				87,367
Operating income from continuing operations	$	34,281	$	16,866		$	(9,917	)		$	41,230
Capital Expenditures	$	31,138	$	17,628		$	1,259			$	50,025
Segment Assets	$	965,279	$	353,262		$	51,218			$	1,369,759

_________________________________

(a) Represents results of the Partnership's commodity risk management activity.

(b) Includes elimination of intersegment transactions.

(c) Sales to external customers for the nine months endedSeptember 30, 2011 includes $2.0 million of business interruption insurance recovery related to the shutdown of the Eustace plant in 2010 in the Upstream Segment, which is recognized as part of Other revenue in the unaudited condensed consolidated statement of operations.

(d) Includes costs to dispose of sulfur in the Upstream Segment of $0.7 million for the nine months endedSeptember 30, 2010.

30

NOTE 15. 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 subsidiary 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 (collectively, the "C Corporations").

As a result of the taxable income from the underlying partnerships owned by the C Corporations described above, statutory depletion carryforwards of less than $0.1 million, $0.2 million, $0.6 million and $2.4 million were used during the three and nine months endedSeptember 30, 2011 and 2010, respectively.

Effective Rate - The effective rate for the nine months endedSeptember 30, 2011 was (1.9)% compared to 1.0% for the nine months endedSeptember 30, 2010. Due to the fact that the effective rate is a ratio of total tax expense compared to pre-tax book net income, the change is due primarily to book and tax temporary differences for the the nine months ending September 30, 2011 as compared to the nine months ended September 30, 2010.

Deferred Taxes - As of September 30, 2011, the net deferred tax liability was $36.7 million compared to $36.7 million as of December 31, 2010, 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.

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. In addition, the Partnership has accrued interest and penalties associated with these liabilities and has recorded these amounts within its State deferred income tax expense. The amount stated below relates to the tax returns filed for 2008 and 2009, which are still open under current statute. A reconciliation of the beginning and ending amount of the unrecognized tax benefits (liabilities) is as follows (in thousands): 

Balance as of December 31, 2010	$	(569	)
Increases related to prior year tax positions	—
Increases related to current year tax positions	(166		)
Balance as of September 30, 2011	$	(735	)

NOTE 16. EQUITY-BASED COMPENSATION

Eagle Rock Energy G&P, LLC, the general partner of the general partner of 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 provides for the issuance of an aggregate of up to 7,000,000 common units, to be granted either as options, restricted units or phantom units. Distributions declared and paid on outstanding restricted units are paid directly to the holders of the restricted units. No options or phantom units have been issued to date.

The restricted units granted are valued at the market price as of the date issued. The weighted average fair value of the units granted during the nine months endedSeptember 30, 2011 and 2010 was $10.73 and $6.01, respectively. The awards generally vest over three years on the basis of one third of the award each year. During the restriction period, distributions associated with the granted awards will be distributed to the awardees.

31

A summary of the restricted common units’ activity for the nine months endedSeptember 30, 2011 is provided below:

	Number of Restricted Units		Weighted Average Fair Value
Outstanding at December 31, 2010	1,744,454		$	6.27
Granted	432,775		$	10.73
Vested	(62,071	)	$	5.07
Forfeited	(108,880	)	$	6.54
Outstanding at September 30, 2011	2,006,278		$	7.25

For the three and nine months endedSeptember 30, 2011 and 2010, non-cash compensation expense of approximately $1.5 million, $3.4 million, $1.3 million and $4.7 million, respectively, was recorded related to the granted restricted units. During the three months ended September 30, 2011, the Partnership adjusted its forfeiture rate, resulting in increased expense of $0.3 million, which is included in total non-cash compensation expense as discussed above.

As of September 30, 2011, unrecognized compensation costs related to the outstanding restricted units under the LTIP totaled approximately $10.2 million. The remaining expense is to be recognized over a weighted average of 2.18 years.

In connection with the vesting of certain restricted units during the nine months endedSeptember 30, 2011, 10,772 of the newly-vested common units were cancelled by the Partnership in satisfaction of $0.1 million of employee tax liability paid by the Partnership. Pursuant to the terms of the LTIP, these cancelled units are available for future grants under the LTIP.

NOTE 17. EARNINGS PER UNIT

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

As of September 30, 2011 and 2010, the Partnership had unvested restricted common units outstanding, which are considered dilutive securities. 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.

Any warrants outstanding during the period are considered to be dilutive securities. These outstanding warrants will be considered in the diluted weighted average common unit outstanding number in periods of net income, except if the exercise price of the outstanding warrants is greater than the average market price of the common units for such periods. In periods of net losses, the outstanding warrants are excluded from the diluted weighted average common unit outstanding number.

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”) participated 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 nine months endedSeptember 30, 2010, 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, and they were eliminated.

In addition, all of the subordinated units and general partner units were contributed to the Partnership and cancelled on May 24, 2010 and July, 30, 2010, respectively.

The following table presents the Partnership's calculation of basic and diluted units outstanding for the periods indicated:

32

	Three Months Ended September 30,		Nine Months Ended September 30,
	2011	2010	2011	2010
	(Unit amounts in thousands)
Weighted average units outstanding during period:
Common units - Basic	122,575	80,224	105,042	63,770
Effect of Dilutive Securities:
Warrants	4,395	—	5,635	—
Restricted Units	1,107	—	980	180
Common units - Diluted	128,077	80,224	111,657	63,950
Subordinated units - Basic and Diluted				10,914
General partner units - Basic and Diluted		275		653

Warrants totaling 21,272,442 were excluded in the computation of diluted earnings per share for the three and nine months ended September 30, 2010, as the effect would have been anti-dilutive.

The restricted common units granted under the LTIP, as discussed in Note 16, 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 pursuant to the two-class method. For the three and nine months ended September 30, 2011 and the nine months endedSeptember 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 and weighted average warrants outstanding.

The following table presents the Partnership's basic income per unit for the three months endedSeptember 30, 2011:

	Total			Common Units			Restricted Common Units
	($ in thousands, except for per unit amounts)
Income from continuing operations	$	97,562
Distributions declared	24,863			$	24,515		$	348
Assumed income from continuing operations after distribution to be allocated	72,699			71,574			1,125
Assumed allocation of income from continuing operations	97,562			96,089			1,473
Discontinued operations	(197		)	(197		)	—
Assumed net income to be allocated	$	97,365		$	95,892		$	1,473
Basic income from continuing operations per unit				$	0.78
Basic discontinued operations per unit				$	—
Basic income per unit				$	0.78

33

The following table presents the Partnership's diluted income per unit for the three months endedSeptember 30, 2011:

	Total			Common Units			Restricted Common Units
	($ in thousands, except for per unit amounts)
Income from continuing operations	$	97,562
Distributions declared	25,742			$	25,394		$	348
Assumed income from continuing operations after distribution to be allocated	71,820			70,733			1,087
Assumed allocation of income from continuing operations	97,562			96,127			1,435
Discontinued operations	(197		)	(197		)	—
Assumed net income to be allocated	$	97,365		$	95,930		$	1,435
Diluted income from continuing operations per unit				$	0.76
Diluted discontinued operations per unit				$	—
Diluted income per unit				$	0.76

The following table presents the Partnership's basic income per unit for the nine months endedSeptember 30, 2011:

	Total		Common Units		Restricted Common Units
	($ in thousands, except for per unit amounts)
Income from continuing operations	$	98,509
Distributions declared	52,489		$	51,668	$	821
Assumed income from continuing operations after distribution to be allocated	46,020		45,231		789
Assumed allocation of income from continuing operations	98,509		96,899		1,610
Discontinued operations	210		206		4
Assumed net income to be allocated	$	98,719	$	97,105	$	1,614
Basic income from continuing operations per unit			$	0.92
Basic discontinued operations per unit			$	—
Basic income per unit			$	0.92

34

The following table presents the Partnership's diluted income per unit for the nine months endedSeptember 30, 2011:

	Total		Common Units		Restricted Common Units
	($ in thousands, except for per unit amounts)
Income from continuing operations	$	98,509
Distributions declared	53,616		$	52,795	$	821
Assumed income from continuing operations after distribution to be allocated	44,893		44,162		731
Assumed allocation of income from continuing operations	98,509		96,957		1,552
Discontinued operations	210		207		3
Assumed net income to be allocated	$	98,719	$	97,164	$	1,555
Diluted income from continuing operations per unit			$	0.88
Diluted discontinued operations per unit			$	—
Diluted income per unit			$	0.88

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

	Total			Common Units			Restricted Common Units			General Partner Units
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(25,403	)
Distributions declared	2,028			$	2,006		$	22		$	—
Assumed loss from continuing operations after distribution to be allocated	(27,431		)	(26,986		)	(352		)	(93		)
Assumed allocation of loss from continuing operations	(25,403		)	(24,980		)	(330		)	(93		)
Discontinued operations, net of tax	166			163			2			1
Assumed net loss to be allocated	$	(25,237	)	$	(24,817	)	$	(328	)	$	(92	)
Basic and diluted loss from continuing operations per unit				$	(0.31	)				$	(0.34	)
Basic and diluted discontinued operations per unit				$	—					$	—
Basic and diluted loss per unit				$	(0.31	)				$	(0.33	)

35

The following table presents the Partnership's basic and diluted income per unit for the nine months endedSeptember 30, 2010:

	Total			Common Units			Restricted Common Units			Subordinated Units			General Partner Units
	($ in thousands, except for per unit amounts)
Income from continuing operations	$	3,076
Distributions declared	4,486			$	4,364		$	80		$	—		$	42
Assumed loss from continuing operations after distribution to be allocated	(1,410		)	(1,174		)	(23		)	(201		)	(12		)
Assumed allocation of income (loss) from continuing operations	3,076			3,190			57			(201		)	30
Discontinued operations, net of tax	43,811			36,485			708			6,244			374
Assumed net income to be allocated	$	46,887		$	39,675		$	765		$	6,043		$	404
Basic and diluted income (loss) from continuing operations per unit				$	0.05					$	(0.02	)	$	0.05
Basic and diluted discontinued operations per unit				$	0.57					$	0.57		$	0.57
Basic and diluted income per unit				$	0.62					$	0.55		$	0.62

NOTE 18.   DISCONTINUED OPERATIONS

On April 1, 2009, the Partnership sold its producer services business (which was accounted for in its South Texas Segment). As part of the sale, the Partnership received a monthly payment equivalent to $0.01 per MMbtu on the volume of gas that flowed pursuant to the assigned contracts through March 31, 2011. During the nine months endedSeptember 30, 2011, this business generated revenues of less than $0.1 million and no cost of natural gas and NGLs. During the three and nine months endedSeptember 30, 2010, this business generated revenues of less than $0.1 million and no cost of natural gas and NGLs for both periods.

On May 24, 2010, the Partnership completed the sale of its Minerals Business. During the nine months endedSeptember 30, 2011, the Partnership received payments of $0.4 million related to pre-effective date operations and recorded this amount as part of discontinued operations for the period. During the three months ended September 30, 2010, the Partnership received payments of $0.3 million related to pre-effective date operations and have recorded this amount as past of discontinued operations for the period. For the nine months ended September 30, 2010, the Partnership generated revenues of $8.9 million and income from operations of $5.6 million. During the three and nine months endedSeptember 30, 2010, the Minerals Business incurred state tax expense on discontinued operations of $0.1 million and $0.4 million, respectively. During the nine months endedSeptember 30, 2010, the Partnership recorded income from discontinued operations of $5.8 million excluding the gain recognized by the Partnership on the sale of the Minerals Business.

On May 20, 2011, the Partnership sold its Wildhorse Gathering System (which was accounted for in its South Texas Segment), for net proceeds of approximately $5.7 million in cash. The Partnership recorded a loss of $0.8 million on the sale, which is recorded as part of discontinued operations for the nine months endedSeptember 30, 2011. For the nine months endedSeptember 30, 2011, the Partnership generated revenues of $6.9 million and income from operations of $0.6 million. For the three and nine months endedSeptember 30, 2010, the Partnership generated revenues of $6.1 million and $20.1 million, respectively, and income from operations of less than $0.1 million and a loss from operations of $0.3 million, respectively. During the three and nine months endedSeptember 30, 2011, the Partnership recorded a loss from discontinued operations of $0.2 million and $0.6 million, respectively. During the three and nine months endedSeptember 30, 2010, the Partnership recorded a loss from discontinued operations of less than $0.1 million and income from operations of $0.4 million, respectively. During each of the three and nine months endedSeptember 30, 2011 and 2010, this system incurred state tax expense of less than $0.1 million.

Assets and liabilities held for sale represent the assets and liabilities of the Wildhorse Gathering System. As of December 31, 2010, liabilities held for sale consisted of accounts payable, and assets held for sale consisted of the following: (i) $2.1 million of accounts receivable, (ii) $6.2 million of pipelines and equipment and (iii) $0.3 million of intangible assets.

36

NOTE 19. OTHER OPERATING INCOME

In July 2008, SemGroup, L.P. and certain of its subsidiaries (“SemGroup”) filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. The Partnership historically sold portions of its condensate production from its Texas Panhandle and East Texas midstream systems to SemGroup. In August 2009, the Partnership sold $3.9 million of its outstanding receivables from SemGroup, which represented its 20-day administrative claims under 503(b)(9) of the United States Bankruptcy Code, for which it received a payment of $3.0 million. Due to certain repurchase obligations under the assignment agreement, the Partnership recorded the payment as a current liability within accounts payable as of December 31, 2010 and maintained the balance as a liability until it was clear that the repurchase obligations can no longer be triggered. Due to the expiration of the repurchase obligations during the nine months ended September 30, 2011, the Partnership released its reserve for these receivables and recorded other operating income of $2.9 million related to these reserves.

NOTE 20. SUBSIDIARY GUARANTORS

In the future, the Partnership expects to issue registered debt securities guaranteed by its subsidiaries.  The Partnership expects that all guarantors would be wholly-owned or available to be pledged and that such guarantees would be joint and several and full and unconditional.  In accordance with Rule 3-10 of Regulation S-X, the Partnership has prepared Condensed Consolidating Financial Statements as supplemental information.  The following unaudited condensed consolidating balance sheets at September 30, 2011 and December 31, 2010, unaudited condensed consolidating statements of operations for the three and nine months endedSeptember 30, 2011 and 2010, and unaudited condensed consolidating statements of cash flows for the nine months endedSeptember 30, 2011 and 2010, present financial information for Eagle Rock Energy as the Parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the co-issuer and the subsidiary guarantors, which are all 100% owned by the Parent, 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 Consolidating Balance Sheet

September 30, 2011

	Parent Issuer		Co-Issuer		Subsidiary Guarantors		Non-guarantor investments		Consolidating Entries			Total
	($ in thousands)
ASSETS:
Accounts receivable – related parties	$	—	$	—	$	10,497	$	—	$	(10,497	)	$	—
Other current assets	27,361		1		108,254		—		—			135,616
Total property, plant and equipment, net	1,346		—		1,715,529		—		—			1,716,875
Investment in subsidiaries	1,757,328		—		—		1,049		(1,758,377		)	—
Total other long-term assets	39,852		—		132,788		—		—			172,640
Total assets	$	1,825,887	$	1	$	1,967,068	$	1,049	$	(1,768,874	)	$	2,025,131
LIABILITIES AND EQUITY:
Accounts payable – related parties	$	10,497	$	—	$	—	$	—	$	(10,497	)	$	—
Other current liabilities	16,358		—		145,617		—		—			161,975
Other long-term liabilities	11,690		—		64,124		—		—			75,814
Long-term debt	740,904		—		—		—		—			740,904
Equity	1,046,438		1		1,757,327		1,049		(1,758,377		)	1,046,438
Total liabilities and equity	$	1,825,887	$	1	$	1,967,068	$	1,049	$	(1,768,874	)	$	2,025,131

37

Unaudited Condensed Consolidating Balance Sheet

December 31, 2010

	Parent Issuer		Co-Issuer		Subsidiary Guarantors		Non-guarantor investments		Consolidating Entries			Total
	($ in thousands)
ASSETS:
Accounts receivable – related parties	$	42,667	$	—	$	—	$	—	$	(42,667	)	$	—
Assets held for sale	—		—		8,615		—		—			8,615
Other current assets	5,694		1		76,547		—		—			82,242
Total property, plant and equipment, net	1,200		—		1,136,039		—		—			1,137,239
Investment in subsidiaries	1,113,603		—		—		1,116		(1,114,719		)	—
Total other long-term assets	3,622		—		117,679		—		—			121,301
Total assets	$	1,166,786	$	1	$	1,338,880	$	1,116	$	(1,157,386	)	$	1,349,397
LIABILITIES AND EQUITY:
Accounts payable – related parties	$	—	$	—	$	42,667	$	—	$	(42,667	)	$	—
Liabilities held for sale	—		—		1,705		—		—			1,705
Other current liabilities	31,208		—		112,126		—		—			143,334
Other long-term liabilities	26,465		—		68,780		—		—			95,245
Long-term debt	530,000		—		—		—		—			530,000
Equity	579,113		1		1,113,602		1,116		(1,114,719		)	579,113
Total liabilities and equity	$	1,166,786	$	1	$	1,338,880	$	1,116	$	(1,157,386	)	$	1,349,397

Unaudited Condensed Consolidating Statement of Operations

For the Three Months Ended September 30, 2011

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	81,278		$	—	$	294,533		$	—		$	—		$	375,811
Cost of natural gas and natural gas liquids	—			—		171,964			—			—			171,964
Operations and maintenance	—			—		24,897			—			—			24,897
Taxes other than income	—			—		4,556			—			—			4,556
General and administrative	1,562			—		14,506			—			—			16,068
Other operating income	—			—		—			—			—			—
Depreciation, depletion, amortization and impairment	42			—		44,868			—			—			44,910
Income from operations	79,674			—		33,742			—			—			113,416
Interest expense	(10,057		)	—		—			—			—			(10,057		)
Other non-operating income	2,240			—		630			—			(2,863		)	7
Other non-operating expense	(21,297		)	—		11,554			(1		)	2,863			(6,881		)
Income (loss) before income taxes	50,560			—		45,926			(1		)	—			96,485
Income tax benefit	(58		)	—		(1,019		)	—			—			(1,077		)
Equity in earnings of subsidiaries	46,747			—		—			—			(46,747		)	—
Income (loss) from continuing operations	97,365			—		46,945			(1		)	(46,747		)	97,562
Discontinued operations, net of tax	—			—		(197		)	—			—			(197		)
Net income (loss)	$	97,365		$	—	$	46,748		$	(1	)	$	(46,747	)	$	97,365

38

Unaudited Condensed Consolidating Statement of Operations

For the Three Months Ended September 30, 2010

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments		Consolidating Entries			Total
	($ in thousands)
Total revenues	$	(9,443	)	$	—	$	162,360		$	—	$	—		$	152,917
Cost of natural gas and natural gas liquids	—			—		106,682			—		—			106,682
Operations and maintenance	—			—		18,714			—		—			18,714
Taxes other than income	—			—		2,609			—		—			2,609
General and administrative	2,050			—		8,624			—		—			10,674
Depreciation, depletion, amortization and impairment	44			—		29,280			—		—			29,324
Loss from operations	(11,537		)	—		(3,549		)	—		—			(15,086		)
Interest expense	(3,258		)	—		—			—		—			(3,258		)
Other non-operating income	2,110			—		740			21		(2,841		)	30
Other non-operating expense	(3,293		)	—		(7,881		)	—		2,841			(8,333		)
(Loss) income before income taxes	(15,978		)	—		(10,690		)	21		—			(26,647		)
Income tax provision (benefit)	(310		)	—		(934		)	—		—			(1,244		)
Equity in earnings of subsidiaries	(9,569		)	—		—			—		9,569			—
(Loss) income from continuing operations	(25,237		)	—		(9,756		)	21		9,569			(25,403		)
Discontinued operations, net of tax	—			—		166			—		—			166
Net (loss) income	$	(25,237	)	$	—	$	(9,590	)	$	21	$	9,569		$	(25,237	)

Unaudited Condensed Consolidating Statement of Operations

For the Nine Months Ended September 30, 2011

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	61,796		$	—	$	783,094		$	—		$	—		$	844,890
Cost of natural gas and natural gas liquids	—			—		491,957			—			—			491,957
Operations and maintenance	—			—		66,323			—			—			66,323
Taxes other than income	—			—		13,061			—			—			13,061
General and administrative	3,279			—		40,467			—			—			43,746
Other operating income	—			—		(2,893		)	—			—			(2,893		)
Depreciation, depletion, amortization and impairment	122			—		104,946			—			—			105,068
Income from operations	58,395			—		69,233			—			—			127,628
Interest expense	(19,584		)	—		(8		)	—			—			(19,592		)
Other non-operating income	6,526			—		2,848			—			(9,361		)	13
Other non-operating expense	(26,497		)	—		5,798			(12		)	9,361			(11,350		)
Income (loss) before income taxes	18,840			—		77,871			(12		)	—			96,699
Income tax provision (benefit)	138			—		(1,948		)	—			—			(1,810		)
Equity in earnings of subsidiaries	80,017			—		—			—			(80,017		)	—
Income (loss) from continuing operations	98,719			—		79,819			(12		)	(80,017		)	98,509
Discontinued operations, net of tax	—			—		210			—			—			210
Net income (loss)	$	98,719		$	—	$	80,029		$	(12	)	$	(80,017	)	$	98,719

39

Unaudited Condensed Consolidating Statement of Operations

For the Nine Months Ended September 30, 2010

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments		Consolidating Entries			Total
	($ in thousands)
Total revenues	$	20,594		$	—	$	564,181		$	—	$	—		$	584,775
Cost of natural gas and natural gas liquids	—			—		353,227			—		—			353,227
Operations and maintenance	—			—		57,511			—		—			57,511
Taxes other than income	2			—		8,947			—		—			8,949
General and administrative	7,035			—		29,456			—		—			36,491
Depreciation, depletion, amortization and impairment	126			—		87,241			—		—			87,367
Income from operations	13,431			—		27,799			—		—			41,230
Interest expense	(10,994		)	—		—			—		—			(10,994		)
Other non-operating income	6,163			—		1,961			6		(7,847		)	283
Other non-operating expense	(11,748		)	—		(24,512		)	—		7,847			(28,413		)
(Loss) income before income taxes	(3,148		)	—		5,248			6		—			2,106
Income tax provision (benefit)	517			—		(1,487		)	—		—			(970		)
Equity in earnings of subsidiaries	50,552			—		—			—		(50,552		)	—
Income from continuing operations	46,887			—		6,735			6		(50,552		)	3,076
Discontinued operations, net of tax	—			—		43,811			—		—			43,811
Net income	$	46,887		$	—	$	50,546		$	6	$	(50,552	)	$	46,887

40

Unaudited Condensed Consolidating Statement of Cash Flows

For the Nine Months Ended September 30, 2011

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments		Consolidating Entries			Total
	($ in thousands)
Net cash flows provided by operating activities	$	3,263		$	—	$	81,633		$	55	$	—		$	84,951
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions, net of cash acquired	—			—		(220,326		)	—		—			(220,326		)
Additions to property, plant and equipment	(269		)	—		(79,542		)	—		—			(79,811		)
Purchase of intangible assets	—			—		(3,122		)	—		—			(3,122		)
Proceeds from sale of asset	—			—		5,712			—		—			5,712
Contribution to subsidiaries	(227,583		)	—		—			—		227,583			—
Net cash flows used in investing activities	(227,852		)	—		(297,278		)	—		227,583			(297,547		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	826,379			—		—			—		—			826,379
Repayment of long-term debt	(913,379		)	—		—			—		—			(913,379		)
Proceed from senior notes	297,837			—		—			—		—			297,837
Payment of debt issuance cost	(16,800		)	—		—			—		—			(16,800		)
Proceeds from derivative contracts	3,706			—		—			—		—			3,706
Repurchase of common units	(119		)	—		—			—		—			(119		)
Exercise of Warrants	78,239			—		—			—		—			78,239
Distributions to members and affiliates	(49,080		)	—		—			—		—			(49,080		)
Contribution from parent	—			—		227,583			—		(227,583		)	—
Net cash flows provided by financing activities	226,783			—		227,583			—		(227,583		)	226,783
Net cash flows used in discontinued operations	—			—		(574		)	—		—			(574		)
Net increase in cash and cash equivalents	2,194			—		11,364			55		—			13,613
Cash and cash equivalents at beginning of year	4,890			1		(885		)	43		—			4,049
Cash and cash equivalents at end of year	$	7,084		$	1	$	10,479		$	98	$	—		$	17,662

41

Unaudited Condensed Consolidating Statement of Cash Flows

For the Nine Months Ended September 30, 2010

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor Investments			Consolidating Entries		Total
	($ in thousands)
Net cash flows provided by operating activities	$	36,746		$	—	$	40,007		$	54		$	—	$	76,807
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions, net of cash acquired	—			—		(4,139		)	—			—		(4,139		)
Additions to property, plant and equipment	(837		)	—		(41,962		)	—			—		(42,799		)
Purchase of intangible assets	—			—		(1,930		)	—			—		(1,930		)
Proceeds from sale of asset	171,686			—		—			—			—		171,686
Net cash flows provided by (used in) investing activities	170,849			—		(48,031		)	—			—		122,818
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	37,000			—		—			—			—		37,000
Repayment of long-term debt	(276,000		)	—		—			—			—		(276,000		)
Repurchase of common units	(724		)	—		—			—			—		(724		)
Deferred transaction fees	(3,015		)	—		—			—			—		(3,015		)
Proceeds from rights offering	53,893			—		—			—			—		53,893
Exercise of warrants	1,708			—		—			—			—		1,708
Proceeds from derivative contracts	—			—		1,001			—			—		1,001
Distributions to members and affiliates	(5,102		)	—		—			—			—		(5,102		)
Net cash flows (used in) provided by financing activities	(192,240		)	—		1,001			—			—		(191,239		)
Net cash flows provided by discontinued operations	—			—		8,930			—			—		8,930
Net increase in cash and cash equivalents	15,355			—		1,907			54			—		17,316
Cash and cash equivalents at beginning of year	4,922			1		(2,180		)	(11		)	—		2,732
Cash and cash equivalents at end of year	$	20,277		$	1	$	(273	)	$	43		$	—	$	20,048

NOTE 21.  SUBSEQUENT EVENTS

Borrowing Base Redetermination

On October 4, 2011, the Partnership announced that the Upstream Segment component of the borrowing base under its revolving credit facility was set at $375 million by its commercial lenders as part of its regularly scheduled semi-annual borrowing base redetermination. This represented an increase of $22 million from the previous level of $353 million. The redetermined borrowing base was effective October 1, 2011, with no additional fees or increase in interest rate spread incurred.

Risk Management Activities

On October 17, 2011, the Partnership entered into the following hedging transactions:

• 961,800 gallons per month Mont Belvieu propane - OPIS swap with a strike price of $1.3425 per gallon for its 2012 calendar year;

• 310,800 gallons per month Mont Belvieu isobutane - OPIS swap with a strike price of $1.77 per gallon for its 2012 calendar year;

• 453,600 gallons per month Mont Belvieu normal butane - OPIS swap with a strike price of $1.67 per gallon for its 2012 calendar year; and

• 252,000 gallons per month Mont Belvieu natural gasoline - OPIS swap with a strike price of $2.19 per gallon for its 2012 calendar year.

In addition, on October 17, 2011, the Partnership partially unwound 7,800 barrels a month of a 20,000 barrels a month

42

"in-the-money" WTI crude oil swap. As consideration for this unwind, the strike price of the remaining 12,200 barrels a month was increased from $97.42 per barrel to $103.31 per barrel.

On October 20, 2011, the Partnership entered into the following hedging transactions:

• 3,150,000 gallons per month Mont Belvieu purity ethane - OPIS ethane swap with a strike price of $0.73 per gallon for the first six months of 2012; and

• (260,000) MMBtu per month (the Partnership pays the fixed price and receives the floating price) Henry Hub natural gas swap with a strike price of $3.965 per MMBtu for the first six months of 2012 to offset an existing 260,000 MMBtu Henry Hub natural gas swap with a strike price of $6.77 per MMBtu for the same period.

These hedging transactions are not included in the commodity derivatives schedules in Note 11 above as of September 30, 2011.

Turnaround of Upstream Business Processing Facilities

On October 1, 2011, the Partnership's Big Escambia Creek facility in Alabama was brought down to make additional repairs to its sulfur recovery unit following the facility's planned turnaround conducted during September 2011. The facility and all Big Escambia Creek field wells were shut-in for seven days during this repair period. The Partnership estimates the revenue impact associated with the loss in production was approximately $1.9 million and the additional repair expense was approximately $0.2 million.

During October 2011, the Partnership completed a scheduled turnaround of its Flomaton facility in Escambia County, Alabama to make certain equipment repairs and routine inspections of equipment. During the turnaround both the Flomaton facility and all wells in the Flomaton and Fanny Church fields were shut-in. The duration of the plant turnaround and the field shut-in was approximately twelve days. The Partnership estimates the revenue impact due to the loss of production was approximately $0.5 million and the turnaround expense was approximately $0.6 million.

Wheeler Plant

On October 31, 2011, the Partnership announced its intention to install a 125 MMcf/d high efficiency cryogenic processing plant in Wheeler County, Texas, in the heart of the prolific Granite Wash play. The Partnership expects the installation of the new processing plant (to be named the “Wheeler Plant”) and construction of the associated infrastructure to be completed early in the fourth quarter of 2012. The construction of the Wheeler Plant and associated infrastructure, gathering and compression is expected to cost approximately $100 million.

LTIP Grant

On November 1, 2011, the Partnership granted 1,257,565 restricted units under its LTIP. Although the units will be outstanding as of the record date of the Partnership's third quarter 2011 distribution, these units are not eligible for the third quarter distribution but will be eligible for future distributions, beginning with the Partnership's fourth quarter 2011 distribution to be paid in February 2012.

43

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

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report may include “forward-looking statements” as defined by the SEC. All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These statements are based on certain assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control, which may cause our actual results to differ materially from those implied or expressed by the forward-looking statements. We do not assume any obligation to update such forward-looking statements following the date of this report. For a complete description of these risks, please read our risk factors set forth in our annual report on Form 10-K for the year ended December 31, 2010 and in “Part II. Item 1A. Risk Factors.” These factors include but are not limited to:

• Drilling and geological / exploration risks;

• Assumptions regarding oil and natural gas reserve levels and costs to exploit and timing of development;

• Volatility or declines in commodity prices;

• Our significant existing indebtedness, including indebtedness we assumed in connection with the Crow Creek Acquisition;

• Hedging activities;

• Ability to obtain credit and access capital markets;

• Ability to remain in compliance with the covenants set forth in our credit facility;

• Conditions in the securities and/or capital markets;

• Future processing volumes and throughput;

• Loss of significant customers;

• Availability and cost of processing and transportation of NGLs;

• Competition in the oil and natural gas industry;

• Relevant legislative or regulatory changes, including retroactive royalty or production tax regimes, changes in environmental, health and safety regulation, hydraulic fracturing regulation, environmental risks and liability under federal, state and foreign environmental laws and regulations;

• Ability to make favorable acquisitions and integrate operations from such acquisitions, including our Crow Creek Acquisition;

• Shortages of personnel and equipment;

• Potential losses associated with trading in derivative contracts;

• Increases in interest rates;

• Creditworthiness of our counterparties;

• Weather, including the occurrence of any adverse weather conditions and/or natural disasters affecting our business;

• Any other factors that impact or could impact the exploration of oil or natural gas resources, including but not limited to the geology of a resource, the total amount and costs to develop recoverable reserves, legal title, regulatory, natural gas administration, marketing and operations factors relating to the extraction of oil and natural gas; and

• Tax risk associated with pass-through investment, including potential reduction in tax shield or creation of phantom income in the event distributions are not enough to support the tax burden.

44

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, 2010 and quarterly reports on Form 10-Q for the quarterly periods ended March 31, 2011 and June 30, 2011, filed with the Securities and Exchange Commission. For a description of oil and natural gas terms, see our annual report on Form 10-K for the year ended December 31, 2010.

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, transporting, marketing and trading natural gas; fractionating, transporting and marketing natural gas liquids ("NGLs"); and crude oil logistics and marketing; and

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

We present our business in six segments for reporting purposes.

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, crude oil logistics and marketing in Texas and Alabama, and natural gas marketing and trading. Our East Texas/Louisiana Segment consists of gathering and processing assets in East Texas/Northern Louisiana. Our South Texas Segment consists of gathering systems and related compression and processing facilities in South Texas.  Our Gulf of Mexico Segment consists of gathering and processing assets in Southern Louisiana, the Gulf of Mexico and Galveston Bay.  During the three and nine months endedSeptember 30, 2011, our Midstream Business generated operating income from continuing operations of $15.8 million and $43.7 million, respectively, compared to operating income from continuing operations of $9.0 million and $34.3 million generated during the three and nine months endedSeptember 30, 2010, respectively.  

We conduct, evaluate and report on our Upstream Business as one segment. Our Upstream Segment includes operated and non-operated wells located in Alabama, Texas, Oklahoma, Arkansas, Mississippi and Louisiana, two treating facilities, and one natural gas processing plant and related gathering systems in Escambia County, Alabama.  During the three and nine months endedSeptember 30, 2011, our Upstream Business generated operating income of $18.3 million and $57.7 million, respectively, compared to operating income of $5.6 million and $16.9 million generated during the three and nine months endedSeptember 30, 2010, respectively.  Of important note, our Upstream Business generated net revenue of $5.1 million and $12.8 million from the sale of sulfur during the three and nine months endedSeptember 30, 2011, respectively, compared to net revenue of $1.5 million and $3.9 million during the three and nine months endedSeptember 30, 2010, respectively.  

The final segment that we report on is our Corporate and Other Segment, which is where we account for our risk management activity, intersegment eliminations and our general and administrative expenses.   During the three and nine months endedSeptember 30, 2011, our Corporate Segment generated operating income, excluding intersegment eliminations, of $77.9 million and $26.3 million, respectively, compared to operating losses of $29.7 million and $9.9 million generated during the three and nine months endedSeptember 30, 2010, respectively.  Results reflected net gains, realized and unrealized, on our commodity derivatives of $94.3 million and $68.2 million during the three and nine months endedSeptember 30, 2011, respectively, compared to a net loss, realized and unrealized, on our commodity derivatives of $18.6 million and a net gain of $27.8 million during the three and nine months endedSeptember 30, 2010, respectively.  See "Summary of Consolidated Operating Results - Corporate and Other Segment" for a further discussion of the impact of our commodity derivatives.

45

Acquisition

On May 3, 2011, we completed the acquisition (the "Crow Creek Acquisition") of all of the outstanding membership interests of CC Energy II L.L.C (together with its subsidiaries, "Crow Creek Energy"), a portfolio company of Natural Gas Partners, VIII, L.P. ("NGP VIII"), for total consideration of $563.7 million including 28.8 million common units valued at $336.1 million, debt assumed of $212.6 million and cash of approximately $15.0 million. The cash portion of the acquisition consideration and the repayment of Crow Creek Energy’s outstanding debt was funded through borrowings under our revolving credit facility. In addition, we incurred $2.3 million of acquisition-related expenses, which are included within general and administrative expenses for the nine months ended September 30, 2011. The oil and natural gas properties acquired from Crow Creek Energy are located in multiple basins across Oklahoma, north Texas and Arkansas (the "Mid-Continent Properties") and provides us with an extensive inventory of low-risk development prospects.

Subsequent Events

Borrowing Base Redetermination

On October 4, 2011, we announced that the Upstream Segment component of the borrowing base under our revolving credit facility was set at $375 million by our commercial lenders as part of our regularly scheduled semi-annual borrowing base redetermination. This represented an increase of $22 million from the previous level of $353 million. The redetermined borrowing base was effective October 1, 2011, with no additional fees or increase in interest rate spread incurred.

Risk Management Activities

On October 17, 2011, we entered into the following hedging transactions:

• 961,800 gallons per month Mont Belvieu propane - OPIS swap with a strike price of $1.3425 per gallon for its 2012 calendar year;

• 310,800 gallons per month Mont Belvieu isobutane - OPIS swap with a strike price of $1.77 per gallon for its 2012 calendar year;

• 453,600 gallons per month Mont Belvieu normal butane - OPIS swap with a strike price of $1.67 per gallon for its 2012 calendar year; and

• 252,000 gallons per month Mont Belvieu natural gasoline - OPIS swap with a strike price of $2.19 per gallon for its 2012 calendar year.

In addition, on October 17, 2011, we partially unwound 7,800 barrels a month of a 20,000 barrels a month "in-the-money" WTI crude oil swap. As consideration for this unwind, the strike price of the remaining 12,200 barrels a month was increased from $97.42 per barrel to $103.31 per barrel.

On October 20, 2011, we entered into the following hedging transactions:

• 3,150,000 gallons per month Mont Belvieu purity ethane - OPIS ethane swap with a strike price of $0.73 per gallon for the first six months of 2012; and

• (260,000) mmBtu per month (we pay the fixed price and receive the floating price) Henry Hub natural gas swap with a strike price of $3.965 per mmBtu to offset an existing 260,000 mmBtu Henry Hub natural gas swap with a strike price of $6.77 per mmBtu for the same period.

Turnarounds of Upstream Business Processing Facilities

On October 1, 2011, our Big Escambia Creek facility in Alabama was brought down to make additional repairs to its sulfur recovery unit following the facility's planned turnaround conducted during September 2011. The facility and all Big Escambia Creek field wells were shut-in for seven days during this repair period. We estimate the revenue impact associated with the loss in production was approximately $1.9 million, and the additional repair expense was approximately $0.2 million.

During October 2011, we completed a scheduled turnaround of our Flomaton facility in Escambia County, Alabama to make certain equipment repairs and routine inspections of equipment. During the turnaround, both the Flomaton facility and all wells in the Flomaton and Fanny Church fields were shut-in. The duration of the plant turnaround and the field shut-in was approximately twelve days. We estimate the revenue impact due to the loss of production was approximately $0.5 million and the turnaround expense was approximately $0.6 million.

46

Wheeler Plant

On October 31, 2011, we announced our intention to install a 125 MMcf/d high efficiency cryogenic processing plant in Wheeler County, Texas, in the heart of the prolific Granite Wash play. We expect the installation of the new processing plant (to be named the “Wheeler Plant”) and construction of the associated infrastructure to be completed early in the fourth quarter of 2012. The construction of the Wheeler Plant and associated infrastructure, gathering and compression is expected to cost approximately $100 million.

LTIP Grant

On November 1, 2011, we granted 1,257,565 restricted units under our long-term incentive plan ("LTIP"). Although the units will be outstanding as of the record date for our third quarter 2011 distribution, these units are not eligible for the third quarter distribution but will be eligible for future distributions, beginning with our fourth quarter 2011 distribution to be paid in February 2012.

Impairment

We incurred impairment charges during the three and nine months endedSeptember 30, 2011 of $9.9 million and $14.8 million, respectively. During the three months ended September 30, 2011, we recorded $9.7 million in impairment charges in the Upstream Segment related to certain proved properties of the Jourdanton Field in South Texas, which included five future drilling locations that are not able to produce in commercially paying quantities in the current natural gas price environment and $0.2 million in impairment charges related to certain drilling locations in our unproved properties which we no longer intend to develop. During the nine months endedSeptember 30, 2011, we recorded an impairment charge of $4.6 million in our Texas Panhandle Segment to fully write-down our idle Turkey Creek plant. We determined that the assets that made up our Turkey Creek plant could not be used elsewhere within our business, and thus we decided to remove all above ground equipment and structures. During the nine months endedSeptember 30, 2011, we incurred impairment charges of $0.3 million in our Upstream Business related to certain legacy drilling locations in our unproved properties which we no longer intend to develop based on the performance of offsetting wells.  During the three and nine months endedSeptember 30, 2010, we recorded $3.4 million in impairment charges related to certain wells in our unproved properties as we determined it would not be economical to develop these unproved locations and during the nine months endedSeptember 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.

Pursuant to generally accepted accounting principles in the United States ("U.S. GAAP"), 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.

Other Matters

Potential Impact of New Environmental Standards - We have certain obligations under our air emissions permit to lower the SO₂ emissions of our Alabama plant operations.  Additionally, in mid-2010, the Environmental Protection Agency (“EPA”) enacted new National Ambient Air Quality Standards (“2010 NAAQS”) which substantially lowered the emissions limits for SO₂ and mandated timelines for compliance.  In order to fulfill its permit obligations, comply with the new 2010 NAAQS requirements, and replace and upgrade certain assets in our Alabama facilities, we expect to spend approximately $50 million over the next several years at the locations of its Alabama operations.  The expected facility upgrades to our Alabama operations should not only increase the marketable sulfur recovered from the inlet gas stream, but also are anticipated to reduce plant fuel consumption, improve the plant's operating reliability and extend the plant's operating life. Management does not anticipate, however, that the required spending will generate returns consistent with our internal rate of return thresholds for discretionary capital investment. At this time, management has identified no other operational areas impacted by the 2010 NAAQS.     

Management expects that a substantial percentage of the total capital invested to achieve the SO₂ emissions standard at our Alabama operations will be classified as maintenance capital, and therefore will reduce the amount of distributable cash flow we recognize in the periods in which the capital is spent. Management, based on its current expectations, does not believe the additional maintenance capital will impact its objective of recommending an annualized distribution rate of $1.00 per common unit by the end of 2012; it will, however, reduce the our distribution coverage ratio in the periods in which the capital is spent.

47

RESULTS OF OPERATIONS

Summary of Consolidated Operating Results

Below is a table of a summary of our consolidated operating results for the three and nine months endedSeptember 30, 2011 and 2010.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	($ in thousands)
Revenues:
Natural gas, natural gas liquids, oil, condensate and sulfur sales	$	269,790		$	159,303		$	738,162		$	516,276
Gathering, compression, processing and treating fees	11,567			12,093			37,116			40,806
Realized commodity derivative losses	(2,698		)	(1,535		)	(17,958		)	(10,031		)
Unrealized commodity derivative gains (losses)	97,011			(17,044		)	86,164			37,839
Other revenue	141			100			1,406			(115		)
Total revenues	375,811			152,917			844,890			584,775
Cost of natural gas, natural gas liquids, and condensate	171,964			106,682			491,957			353,227
Costs and expenses:
Operating and maintenance	24,897			18,714			66,323			57,511
Taxes other than income	4,556			2,609			13,061			8,949
General and administrative	16,068			10,674			43,746			36,491
Other operating income	—			—			(2,893		)	—
Impairment expense	9,870			3,432			14,754			6,562
Depreciation, depletion and amortization	35,040			25,892			90,314			80,805
Total costs and expenses	90,431			61,321			225,305			190,318
Total operating income (loss)	113,416			(15,086		)	127,628			41,230
Other income (expense):
Interest income	7			9			13			184
Interest expense	(10,057		)	(3,258		)	(19,592		)	(12,056		)
Unrealized interest rate derivatives (losses) gains	(3,165		)	(3,112		)	2,191			(12,288		)
Realized interest rate derivative losses	(3,713		)	(5,170		)	(13,374		)	(15,012		)
Other (expense) income	(3		)	(30		)	(167		)	48
Total other income (expense)	(16,931		)	(11,561		)	(30,929		)	(39,124		)
Income (loss) from continuing operations before income taxes	96,485			(26,647		)	96,699			2,106
Income tax benefit	(1,077		)	(1,244		)	(1,810		)	(970		)
Income from continuing operations	97,562			(25,403		)	98,509			3,076
Discontinued operations, net of tax	(197		)	166			210			43,811
Net income	$	97,365		$	(25,237	)	$	98,719		$	46,887
Adjusted EBITDA(a)	$	62,177		$	32,678		$	146,419		$	94,945

________________________

(a) See "- Non-GAAP Financial Measures" for a definition and reconciliation to GAAP.

48

Midstream Business (Four Segments)

Texas Panhandle Segment

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Natural gas, natural gas liquids, oil and condensate sales	$	159,674		$	78,905		$	436,825		$	250,593
Gathering, compression, processing and treating fees	4,892			2,821			12,905			8,811
Total revenue	164,566			81,726			449,730			259,404
Cost of natural gas, natural gas liquids, and condensate (a)	129,986			54,783			351,305			176,485
Operating costs and expenses:
Operations and maintenance	10,828			9,155			31,436			25,666
Depreciation and amortization	9,145			11,702			27,382			34,931
Impairment	—			—			4,560			—
Total operating costs and expenses	19,973			20,857			63,378			60,597
Operating income	$	14,607		$	6,086		$	35,047		$	22,322
Capital expenditures	$	22,432		$	12,636		$	37,999		$	23,405
Realized prices:
Oil and condensate (per Bbl)	$	79.43		$	60.82		$	82.31		$	64.81
Natural gas (per Mcf)	$	3.86		$	3.45		$	3.95		$	3.98
NGLs (per Bbl)	$	53.39		$	40.38		$	55.28		$	44.99
Production volumes:
Gathering volumes (Mcf/d)(b)	163,665			123,541			154,011			128,201
NGLs (net equity Bbls)	231,965			198,639			609,097			660,839
Condensate (net equity Bbls)	260,228			303,197			728,860			780,148
Natural gas short position (MMbtu/d)(b)	(7,418		)	(4,776		)	(5,517		)	(5,405		)

_______________________

(a) Includes purchase of oil, condensate and natural gas of $14,558 and $35,550 from the East Texas/Louisiana Segment, South Texas Segment and the Upstream Segment for the three and nine months endedSeptember 30, 2011, respectively.

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

Revenue and Cost of Natural Gas and NGLs. For the three and nine months endedSeptember 30, 2011, revenues minus cost of natural gas, NGLs and condensate for our Texas Panhandle Segment operations totaled $34.6 million and $98.4 million, respectively, compared to $26.9 million and $82.9 million, respectively, for the three and nine months endedSeptember 30, 2010. The increase was primarily driven by higher product prices, increased volumes from new drilling activity in Wheeler and Hemphill counties, and volumes associated with the acquisition of gathering assets from CenterPoint Energy Field Services (our "East Hemphill" system) in October of 2010. These benefits were substantially offset by operating downtime at three facilities and a reduction in existing volumes of natural gas, NGLs and condensate due to severe winter weather in our Texas Panhandle Segment in January and February 2011. This event also caused damage to our Cargray processing facility, resulting in reduced recoveries of NGLs. The Cargray processing facility was repaired in late June 2011. The operating downtime and the affected recoveries at the Cargray facility impacted revenues minus cost of natural gas by $4.1 million across the Texas Panhandle Segment during the nine months ended September 30, 2011. Eagle Rock Marketing, LLC, which began operations during the fourth quarter of 2010, contributed $0.4 million and $1.6 million, respectively, of revenues minus cost of NGLs and condensate during the three and nine months endedSeptember 30, 2011. Also, Eagle Rock Gas Services, LLC, which began operations during the third quarter of 2011, contributed $(0.1) million of revenues minus cost of natural gas, NGLs and condensate during each of the three and nine months endedSeptember 30, 2011.

49

Our Texas Panhandle Segment lies within ten counties in Texas and consists of our East Panhandle System and our West Panhandle System. The limited 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. However, we have seen continued drilling activity in the East Panhandle by our producer customers beginning in the third quarter of 2010 as higher NGL prices and continued improvements in horizontal drilling technology and fracturing practices resulted in favorable drilling economics. We began to experience increase in drilling activity on our processed volumes during the fourth quarter of 2010 and expect it would have continued in the first half of 2011 had it not been for the severe winter weather experienced in January and February. We have seen and continue to expect drilling activity and the resulting volumes to continue to improve during the remainder of 2011. Accordingly, on August 18, 2011, we entered into an amendment to our Natural Gas Liquids Exchange Agreement with ONEOK Hydrocarbon, L.P. ("ONEOK") to increase the maximum allowable volumes of natural gas that we may deliver from our East Panhandle System to ONEOK for transportation and fractionation services and correspondingly decrease the maximum allowable volumes from our West Panhandle System. The amendment also provided for additional volumes expected after completion of our projects in the Granite Walsh play, which are discussed below.

Operating Expenses. Operating expenses, including taxes other than income, for the three and nine months endedSeptember 30, 2011, increased $1.7 million and $5.8 million, respectively, as compared to the three and nine months endedSeptember 30, 2010. The increase was primarily driven by costs related to the East Hemphill gathering system acquired in October 2010, routine plant turnarounds and higher costs associated with our high-efficiency cryogenic Arrington Ranch - Phoenix Plant. Additionally, the costs incurred related to February's extreme weather during the first six months of the year was $1.3 million.

Depreciation and Amortization. Depreciation and amortization expenses for the three and nine months endedSeptember 30, 2011 decreased $2.6 million and $7.5 million, respectively, from the three and nine months endedSeptember 30, 2010. The major item impacting the decrease was a reduction in amortization expense due to certain intangible assets becoming fully amortized during the fourth quarter of 2010. This decrease was offset by increased depreciation expense associated with the capital expenditures placed into service during the period.

Impairment. During the nine months endedSeptember 30, 2011, we recorded an impairment charge of $4.6 million in our Texas Panhandle Segment to fully write down our idle Turkey Creek plant. We determined that the components of our Turkey Creek plant could not be used elsewhere within our business, and thus we decided to remove all above ground equipment and structures. We did not incur any impairment changes during the three months endedSeptember 30, 2011 nor the three and nine months endedSeptember 30, 2010.

Capital Expenditures. Capital expenditures for the three and nine months endedSeptember 30, 2011 increased $9.8 million and $14.6 million, respectively, compared to the three and nine months endedSeptember 30, 2010. The increase was primarily driven by spending related to: (i) the construction of our Arrington Ranch - Phoenix Plant, including an interconnect between it and our System 97 gathering system, (ii) spending related to improvements to our Cargray Stabilizer and Goad Treater, and (iii) interconnects between our East Hemphill system and our Arrington Ranch - Phoenix Plant.

On April 27, 2011, we announced our intention to expand the Arrington Ranch - Phoenix Plant by an incremental 30 MMcf/d. Once the expansion is completed, the plant capacity will total 80 MMcf/d. The expansion of the Arrington Ranch - Phoenix Plant, coupled with additional expansions of related gathering systems (the "Phoenix Expansion"), will increase our total processing and gathering capacity and accommodate volume growth from the Granite Wash play. The Phoenix Expansion is a direct complement to our acquisition of the East Hemphill system in October 2010, which extended our reach into Hemphill and Wheeler Counties in the Texas Panhandle.

The Phoenix Expansion is expected to be completed in the fourth quarter of 2011 at a cost of approximately $20 million. We do not anticipate downtime or reduced throughput volumes across our East or West Panhandle Systems during the completion of the project. As announced in April 2011, due to the increased demand for additional processing capacity in the area, we do not intend to shut down and re-direct gas volumes from our Canadian Plant in Hemphill County, Texas into the Arrington Ranch - Phoenix Plant. Our Canadian Plant will remain operating, with total processing capacity of 25 MMcf/d.

On July 27, 2011, we announced plans to install a state-of-the-art 60 MMcf/d cryogenic processing facility in the Granite Wash play in the Texas Panhandle (the "Woodall Plant"). The construction of the Woodall Plant and associated gathering and compression is expected to cost approximately $67 million, of which $11 million was spent during the three months ended September 30, 2011 and is expected to be accretive to our distributable cash flow upon being placed into service. We do not anticipate downtime or reduced throughput volumes across our East or West Panhandle Systems during the completion of the project. This project has an anticipated startup date of April 2012. The addition of our Woodall Plant to our

50

existing processing infrastructure in the Texas Panhandle, together with the Phoenix Expansion is in response to incremental processing needs driven by increased drilling activity by producers in the Granite Wash play.

  East Texas/Louisiana Segment

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Natural gas, natural gas liquids, oil and condensate sales (a)	$	43,817	$	37,352	$	138,237	$	127,816
Gathering, compression, processing and treating fees	6,123		8,854		22,517		29,532
Total revenue	49,940		46,206		160,754		157,348
Cost of natural gas, natural gas liquids, and condensate	37,892		33,940		120,946		114,622
Operating costs and expenses:
Operations and maintenance	4,990		4,502		14,193		12,921
Depreciation and amortization	4,589		4,631		13,706		13,171
Total operating costs and expenses	9,579		9,133		27,899		26,092
Operating income	$	2,469	$	3,133	$	11,909	$	16,634
Capital expenditures	$	3,618	$	1,678	$	5,992	$	7,658
Realized prices:
Oil and condensate (per Bbl)	$	94.20	$	79.15	$	95.42	$	75.91
Natural gas (per Mcf)	$	4.43	$	4.56	$	4.55	$	5.15
NGLs (per Bbl)	$	50.94	$	31.32	$	48.94	$	34.48
Production volumes:
Gathering volumes (Mcf/d)(b)	173,567		205,194		188,431		209,724
NGLs (net equity Bbls)(c)	89,050		115,625		267,348		328,147
Condensate (net equity Bbls)(c)	10,364		9,457		34,382		29,070
Natural gas short position (MMbtu/d)(b)	523		317		1,129		949

________________________

(a) Includes sales of natural gas of $2,107 to the Panhandle Segment for each of the three and nine months endedSeptember 30, 2011.

(b) 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.

(c) For the three and nine months endedSeptember 30, 2011, volumes from our Indian Springs plant, in which we own 25%, are included in equity NGL and condensate volumes, as we believe including these volumes is more illustrative of current operating trends. In addition, NGL and condensate volumes associated with a certain contract at our Brookeland plant have been excluded from the three and nine months endedSeptember 30, 2011 due to a change in reporting methodology. This change is evident only in the reporting of 2011 production volumes above and does not impact any of the components of 2011 operating results.

Revenue and Cost of Natural Gas and NGLs. For the three and nine months endedSeptember 30, 2011, revenues minus cost of natural gas and NGLs for our East Texas/Louisiana Segment totaled $12.0 million and $39.8 million, respectively, compared to $12.3 million and $42.7 million, respectively, for the three and nine months endedSeptember 30, 2010. During the three and nine months endedSeptember 30, 2011 and 2010, we recorded revenues associated with deficiency payments of $0.1 million, $1.5 million, $2.2 million and $10.4 million, respectively. We receive deficiency payments under certain of our gathering contracts when delivered volumes fail to meet certain thresholds. These amounts are included within gathering and treating services revenue. Excluding these deficiency payments, revenues minus cost of natural gas, NGLs and condensate for the three and nine months endedSeptember 30, 2011 and 2010 would have been $12.0 million, $38.3 million, $10.0 million and $32.4 million, respectively. The increase for the three and nine months endedSeptember 30, 2011 compared to the three and nine months endedSeptember 30, 2010, is primarily due to higher condensate and NGL prices and increased condensate and NGL equity volumes, and is partially offset by a decrease in gathering volumes and lower natural gas prices.

The gathering volumes for the three and nine months endedSeptember 30, 2011 decreased as compared to the three and nine months endedSeptember 30, 2010, due to natural declines in the production of the existing wells, reduced drilling

51

activity in dry-gas formations related to a decline in natural gas prices and to certain mechanical and completion difficulties experienced by our producer customers.

Operating Expenses. Operating expenses for the three and nine months endedSeptember 30, 2011 increased $0.5 million and $1.3 million, respectively, compared to the three and nine months endedSeptember 30, 2010 as a result of higher costs at the Indian Springs Plant (which is operated by a third party), compressor repairs and labor and benefits, offset by lower compressor rental costs and chemicals.

Depreciation and Amortization. Depreciation and amortization expenses for the nine months endedSeptember 30, 2011 increased $0.5 million compared to the nine months endedSeptember 30, 2010. The increase was due to depreciation expense associated with the capital assets placed into service during the period. Depreciation and amortization expenses for the three months endedSeptember 30, 2011 remained consistent with the three months endedSeptember 30, 2010.

Capital Expenditures. Capital expenditures for the three and nine months endedSeptember 30, 2011 increased $1.9 million and decreased $1.7 million, respectively, compared to the three and nine months endedSeptember 30, 2010. Costs incurred to connect new wells decreased during the nine month period due to the reduced drilling activities in the dry-gas formations. In addition, capital expenditures for the nine months endedSeptember 30, 2011 were offset by the sale of $2.9 million of excess pipe inventory related to the East Texas Mainline ("ETML") expansion project which was cancelled in 2010.

South Texas Segment

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Natural gas, natural gas liquids, oil and condensate sales (a)	$	11,042		$	12,785		$	32,186		$	44,766
Gathering, compression, processing and treating fees	429			207			1,305			1,644
Total revenue	11,471			12,992			33,491			46,410
Cost of natural gas, natural gas liquids, and condensate	10,910			11,321			31,544			41,624
Operating costs and expenses:
Operations and maintenance	400			390			1,055			1,530
Impairment	—			—			—			3,130
Depreciation and amortization	735			699			2,208			2,215
Total operating costs and expenses	1,135			1,089			3,263			6,875
Operating (loss) income from continuing operations	(574		)	582			(1,316		)	(2,089		)
Discontinued operations (a)	(197		)	(15		)	(194		)	363
Operating (loss) income	$	(771	)	$	567		$	(1,510	)	$	(1,726	)
Capital expenditures	$	1		$	5		$	90		$	36
Realized prices:
Oil and condensate (per Bbl)	$	80.06		$	67.24		$	82.34		$	74.56
Natural gas (per Mcf)	$	4.21		$	4.45		$	4.15		$	4.60
NGLs (per Bbl)	$	58.64		$	40.81		$	53.41		$	45.09
Production volumes:
Gathering volumes (Mcf/d)(b)	25,170			39,792			29,423			54,347
NGLs (net equity Bbls)	1,248			1,483			3,393			5,994
Condensate (net equity Bbls)	155			(588		)	1,045			10,999
Natural gas short position (MMbtu/d)(b)	1,235			773			834			995

________________________

52

(a) Includes sales of natural gas of $66 to the Upstream Segment for the nine months endedSeptember 30, 2011 and sales of natural gas of $2,223 to the Panhandle Segment for each of the three and nine months endedSeptember 30, 2011.

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

Revenue and Cost of Natural Gas and NGLs. During the three and nine months endedSeptember 30, 2011, the South Texas Segment contributed revenues minus cost of natural gas and NGLs of $0.6 million and $1.9 million, respectively, as compared to $1.7 million and $4.8 million, respectively, for the three and nine months endedSeptember 30, 2010.   Our South Texas Segment was negatively impacted by declining gathering volumes due to the loss of a significant producer during the third quarter of 2010.

Operating Expenses. Operating expenses for the nine months endedSeptember 30, 2011 decreased $0.5 million compared to the nine months endedSeptember 30, 2010 due to reduced gathering volumes in 2011. Additionally, a major pigging project and pipeline integrity work contributed to the higher expenses in 2010. Operating expenses for the three months endedSeptember 30, 2011 remained consistent with the operating expenses incurred during the three months endedSeptember 30, 2010.

Impairment. We recorded impairment expense of $3.1 million in the nine months endedSeptember 30, 2010 due to the loss of a significant gathering contract. No impairment charges were incurred in the three and nine months endedSeptember 30, 2011 nor the three months endedSeptember 30, 2010.

Depreciation and Amortization. Depreciation and amortization expenses for the three and nine months endedSeptember 30, 2011 remained consistent with the three and nine months endedSeptember 30, 2010.  

Capital Expenditures. Capital expenditures for the three and nine months endedSeptember 30, 2011 remained consistent as compared to the three and nine months endedSeptember 30, 2010.  

Discontinued Operations.  On April 1, 2009, we sold our producer services line of business and classified the revenues minus the cost of natural gas and NGLs as discontinued operations.  During the nine months endedSeptember 30, 2011 and the three and nine months endedSeptember 30, 2010, this business generated revenues of less than $0.1 million and no cost of natural gas and NGLs. As of March 31, 2011, we ceased generating any revenue related to this business, due to us no longer receiving payments related to the volume of gas flows pursuant to the assigned contracts of this business.

On May 20, 2011, we sold the Wildhorse Gathering System. After transaction costs of approximately $0.2 million, we received net proceeds of approximately $5.7 million. We recorded a loss of $0.8 million on the sale, which is recorded as part of discontinued operations for the nine months ended September 30, 2011. For the nine months endedSeptember 30, 2011, we generated revenues of $6.9 million and income from operations of and $0.6 million attributable to the Wildhorse Gathering System. For the three and nine months endedSeptember 30, 2010, we generated revenues of $6.1 million and $20.1 million, respectively, and income from operations of less than $0.1 million and a loss from operations of $0.3 million, respectively. During the three and nine months endedSeptember 30, 2011, we recorded a loss from discontinued operations of $0.2 million and $0.6 million, respectively, attributable to the Wildhorse Gathering System. During the three and nine months endedSeptember 30, 2010, we recorded a loss from discontinued operations of less than $0.1 million and income from discontinued operations of $0.4 million, respectively. During each of the three and nine months endedSeptember 30, 2011 and 2010, this system incurred state tax expense of less than $0.1 million.

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Gulf of Mexico Segment

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Natural gas, natural gas liquids, oil and condensate sales	$	9,061		$	7,623		$	27,692		$	23,302
Gathering, compression, processing and treating fees	123			211			389			819
Total revenue	9,184			7,834			28,081			24,121
Cost of natural gas and NGLs	7,734			6,638			23,712			20,496
Operating costs and expenses:
Operations and maintenance	498			354			1,397			1,390
Depreciation and amortization	1,624			1,651			4,954			4,821
Total operating costs and expenses	2,122			2,005			6,351			6,211
Operating loss	$	(672	)	$	(809	)	$	(1,982	)	$	(2,586	)
Capital Expenditures	$	4		$	21		$	37		$	39
Realized average prices:
NGLs (per Bbl)	$	55.58		$	43.52		$	56.70		$	45.31
Production volumes:
Gathering volumes (Mcf/d)(a)	113,365			101,473			113,150			100,560
NGLs and condensate (net equity barrels)	23,981			27,995			74,514			77,961

________________________

(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 NGLs. During the three and nine months endedSeptember 30, 2011, the Gulf of Mexico Segment contributed $1.5 million and $4.4 million, respectively, in revenues minus cost of natural gas and NGLs compared to $1.2 million and $3.6 million, respectively, in the three and nine months endedSeptember 30, 2010.  The increase for the three and nine months endedSeptember 30, 2011 compared to the three and nine months endedSeptember 30, 2010 is primarily due to increased gathering volumes and higher NGL prices. Our ownership percentage in the North Terrebonne Plant and the Yscloskey Plant 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. Our ownership in the Yscloskey Plant decreased from 11.45% to 10.54% effective September 2011. Our ownership in the North Terrebonne Plant increased to 2.63% in January 2011 from 1.67% for 2010.

Operating Expenses.  Operating expenses for the three and nine months endedSeptember 30, 2011 remained consistent with the three and nine months endedSeptember 30, 2010.

Depreciation and Amortization. Depreciation and amortization expenses for the three and nine months endedSeptember 30, 2011 remained consistent with the three and nine months endedSeptember 30, 2010.

Capital Expenditures. Capital expenditures for the three and nine months endedSeptember 30, 2011 remained consistent with the three and nine months endedSeptember 30, 2010.

54

Upstream Segment

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011(a)		2010		2011(a)		2010
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Oil and condensate	$	24,720	$	14,292	$	63,774	$	37,654
Natural gas (c)	17,417		2,617		32,697		11,982
NGLs (d)	12,186		4,231		29,678		15,485
Sulfur (e)	5,057		1,498		12,781		4,678
Other	141		100		1,406		(115		)
Total revenue (b)	59,521		22,738		140,336		69,684
Operating Costs and expenses:
Operations and maintenance (f)	12,737		6,922		31,369		24,224
Sulfur disposal costs	—		—		—		729
Depletion, depreciation and amortization	18,636		6,810		41,046		24,433
Impairment	9,870		3,432		10,194		3,432
Total operating costs and expenses	41,243		17,164		82,609		52,818
Operating income	$	18,278	$	5,574	$	57,727	$	16,866
Capital expenditures	$	31,868	$	5,235	$	56,688	$	17,628
Realized average prices (g):
Oil and condensate (per Bbl)	$	81.65	$	60.21	$	82.57	$	60.98
Natural gas (per Mcf)	$	4.08	$	4.30	$	3.95	$	4.54
NGLs (per Bbl)	$	52.35	$	41.92	$	55.37	$	45.70
Sulfur (per Long ton) (h)	$	187.03	$	80.54	$	179.48	$	75.38
Production volumes:
Oil and condensate (Bbl)	302,766		212,083		772,350		613,315
Natural gas (Mcf)	4,274,811		778,793		8,272,176		2,743,883
NGLs (Bbl)	227,614		102,967		533,223		355,470
Total (Mcfe)	7,457,091		2,669,093		16,105,615		8,556,593
Sulfur (Long ton) (h)	27,706		17,622		71,509		69,929

________________________

(a) Includes operations related to the Crow Creek Acquisition starting on May 3, 2011

(b) Includes sales of oil and condensate and natural gas to the Texas Panhandle Segment of $8,854 and $31,378 for the three and nine months endedSeptember 30, 2011 respectively.

(c) Revenues include a change in the value of product imbalances by $(38), $22, $(48) and $519 for the three and nine months endedSeptember 30, 2011 and 2010, respectively.

(d) Revenues include a change in the value of product imbalances by $270, $155, $(81) and $(81) for the three and nine months endedSeptember 30, 2011 and 2010, respectively.

(e) Revenues include a change in the value of product imbalances by $(125), $(54), $27 and $27 for the three and nine months endedSeptember 30, 2011 and 2010, respectively.

(f) Includes purchase of natural gas of $66 from the South Texas Segment for the nine months endedSeptember 30, 2011.

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

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

Revenue. For the three and nine months endedSeptember 30, 2011, Upstream Segment revenues increased by $36.8 million and $70.7 million, respectively, as compared to the three and nine months endedSeptember 30, 2010.  The addition of production volumes from the Crow Creek Acquisition positively impacted the Upstream Segment's revenues by $25.6 million and $40.5 million during the three and nine months endedSeptember 30, 2011, respectively. From closing on May 3, 2011 to September 30, 2011, the Mid-Continent Properties contributed 3.2 Bcf natural gas, 90 Mbbl oil and 109 Mbbl of NGLs to the

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Upstream Segment's total production. The increase in revenue was also due to higher realized prices for oil, NGLs and sulfur during the three and nine months endedSeptember 30, 2011 compared to the three and nine months endedSeptember 30, 2010.

The increase in revenue for the nine months ended September 30,2011 was partially offset by the shut-in of our East Texas production beginning August 11, 2010 through March 11, 2011. In August 2010, we announced that our East Texas oil and natural gas production was temporarily shut-in due to an unscheduled shut-down of the Eustace processing facility owned and operated by a third-party. The shut-down involved replacing all of the tubes in the reaction furnace's waste heat recovery unit, replacing the catalyst in the sulfur recovery unit and other equipment repairs. The operator originally estimated that the shut-down would take 30 to 45 days to complete, but the facility was not brought back into service until March 11, 2011. The shut-in negatively impacted our net revenues from January 1, 2011 to March 11, 2011 by approximately $3.9 million (excluding recoveries) and from August 11, 2010 through September 30, 2010 by $2.1 million (excluding recoveries). As of September 30, 2011, we had recognized $5.0 million related to our business interruption insurance claim in other revenue, of which $2.0 million was recognized in the three months ended March 31, 2011 and $3.0 million was recognized in the fourth quarter of 2010. The maximum recovery under our business interruption insurance policy is $5.0 million per occurrence.

During late April and early May 2010, we completed a scheduled turnaround of our Big Escambia Creek facility. 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 revenue impact of the loss in production was approximately $1.8 million during the nine months ended September 30, 2010. In addition, during the nine months ended September 30, 2010, we completed a reallocation of historical production results based on more accurate tests for our Big Escambia Creek wells for the period from August 2007 through March 2010. As a result of this reallocation of historical production, our revenues for the nine months ended September 30, 2010 were negatively impacted by $1.3 million.

During September 2011, we completed another scheduled turnaround (a complete shutdown of the facility to perform certain standard plant repairs and routine inspections of equipment) of our Big Escambia Creek facility in Southern Alabama. The duration of the plant turnaround was approximately nine days. The negative impact to our production during this period was a loss of approximately 49 MMcf of residue gas, 15 MBbls of oil, 6 MBbls of plant products and NGLs and 1,800 long tons of sulfur. The revenue impact of the loss in production was approximately $2.3 million during the three and nine months ended September 30, 2011.

During the three and nine months endedSeptember 30, 2011, sulfur revenue was $5.1 million and $12.8 million, respectively, as compared to net revenue of $1.5 million and $3.9 million, respectively, during the three and nine months endedSeptember 30, 2010. Historically, sulfur was viewed as a low value by-product in the production of oil and natural gas. During the three and nine months endedSeptember 30, 2011, we saw a recovery in sulfur prices, with prices ranging from $185 per long ton on February 10, 2011 to $220 per long ton on October 17, 2011 at the Tampa, Florida market. Our net realized price is lower than the price set at the Tampa, Florida hub due to transportation and marketing deductions and charges. These charges vary depending on how far from the Tampa, Florida market our product is produced. 

Operating Expenses. Operating expenses, including severance and ad valorem taxes, increased by $5.8 million and $7.1 million, respectively, for the three and nine months endedSeptember 30, 2011, as compared to the three and nine months endedSeptember 30, 2010.  The increase for the three and nine months endedSeptember 30, 2011 is primarily due to expenses of $4.7 million and $6.7 million incurred from May 3, 2011 through September 30, 2011 related to the Mid-Continent Properties and increased severance taxes as a result of the increase in revenue. During the three and nine months ended September 30, 2011, we incurred an additional expense of $0.7 million related to the Big Escambia Creek turnaround compared to prior periods. Also, included within these expenses are approximately $1.7 million of post-production expenses, which includes transportation, compression, and processing expenses. Post-production expenses increased by $1.6 million and $2.1 million for the three and nine months endedSeptember 30, 2011,respectively, as compared to the same periods in the prior year, primarily as a result of the Crow Creek Acquisition.

Depletion, Depreciation and Amortization. Depletion, depreciation and amortization expense increased by $11.8 million and $16.6 million, respectively, for the three and nine months endedSeptember 30, 2011, as compared to the same period in the prior year.  The increase was primarily due to $9.6 million and $15.4 million of depletion expense incurred for operations from the Mid-Continent Properties during the three and nine months endedSeptember 30, 2011, respectively. This increase was partially offset due to decreases in production as a result of our East Texas wells being shut-in, as discussed above.

Impairment.  Impairment charges of $9.9 million and $10.2 million were incurred during the three and nine months endedSeptember 30, 2011, respectively. For the nine month period, $9.7 million related to the proved properties of the Jourdanton Field in South Texas, which included five future drilling locations that are not able to produce in commercially paying quantities in the current natural gas price environment $0.2 million related to certain drilling locations in its unproved

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properties which we no longer intend to develop and the remaining $0.3 million related to certain drilling locations in our unproved properties which we no longer intend to develop based on the performance of offsetting wells. During the three and nine months endedSeptember 30, 2010, we incurred impairment charges of $3.4 million related to certain wells in our unproved properties as we determined it would not be economical to develop these unproved locations.

Capital Expenditures.  Capital expenditures increased by $26.6 million and $39.1 million, respectively, for the three and nine months endedSeptember 30, 2011, as compared to the three and nine months endedSeptember 30, 2010.   During the three months ended September 30, 2011, we drilled and completed five operated wells and participated in seven non-operated wells on leases in the Mid-Continent, and drilled and completed an operated well on in East Texas. Additionally, during the three months ended September 30, 2011, we conducted four recompletions and five workovers across our operations. During the three months ended September 30, 2011, we spent approximately $32.0 million on capital projects, primarily on well operations in the Mid-Continent. Of this total expended capital, approximately $24.0 million was spent on projects operated by the Partnership and $8.0 million on projects operated by others. As of September 30, 2011, we were operating two drilling rigs in the Mid-Continent and participating with a non-operated working interest in seven additional drilling locations.

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Corporate and Other Segment

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	($ in thousands)
Revenues:
Realized commodity derivative losses	$	(2,698	)	$	(1,535	)	$	(17,958	)	$	(10,031	)
Unrealized commodity derivative gains (losses)	97,011			(17,044		)	86,164			37,839
Intersegment elimination - Sales of natural gas, oil and condensate	(13,184		)	—			(35,708		)	—
Total revenue	81,129			(18,579		)	32,498			27,808
Intersegment elimination - Cost of natural gas, oil and condensate	(14,558		)	—			(35,550		)	—
General and administrative	16,068			10,674			43,746			36,491
Intersegment elimination - Operations and maintenance	—			—			(66		)	—
Other operating income	—			—			(2,893		)	—
Depreciation and amortization	311			399			1,018			1,234
Operating income (loss)	79,308			(29,652		)	26,243			(9,917		)
Other income (expense):
Interest income	7			9			13			184
Interest expense	(10,057		)	(3,258		)	(19,592		)	(12,056		)
Unrealized interest rate derivative (losses) gains	(3,165		)	(3,112		)	2,191			(12,288		)
Realized interest rate derivative losses	(3,713		)	(5,170		)	(13,374		)	(15,012		)
Other (expense) income	(3		)	(30		)	(167		)	48
Total other income (expense)	(16,931		)	(11,561		)	(30,929		)	(39,124		)
Income (loss) from continuing operations before taxes	62,377			(41,213		)	(4,686		)	(49,041		)
Income tax benefit	(1,076		)	(1,244		)	(1,809		)	(970		)
Income (loss) from continuing operations	63,453			(39,969		)	(2,877		)	(48,071		)
Discontinued operations, net of tax	—			181			404			43,448
Segment income (loss)	$	63,453		$	(39,788	)	$	(2,473	)	$	(4,623	)

Revenue. Our Corporate and Other Segment's revenue consists of our intersegment eliminations and our commodity derivatives activity. Our commodity derivatives activities impact our Corporate and Other Segment revenues through (i) the unrealized, non-cash, mark-to-market of our commodity derivatives scheduled to settle in future periods; and (ii) the realized gains or losses on our commodity derivatives settled in the indicated period. Our unrealized commodity gains and losses reflect (i) the change in the mark-to-market value of our derivative position from the beginning of a period to the end and (ii) the amortization of put premiums and other derivative costs.  In general, the change in the mark-to-market value of our derivative position may be due to several factors including the settlement of derivative instruments during the period, the addition of new derivative positions during the period, changes in the forward curves of the underlying commodities from the beginning to the end of the period, changes in interest rates used in the mark-to-market calculations from the beginning to the end of the period and the passage of time during the period.  

During the three and nine months endedSeptember 30, 2011, we experienced significant unrealized gains in our commodity derivative portfolio due to the hedging contracts we assumed in the Crow Creek Acquisition and to decreases in the crude oil, NGL and natural gas forward curves.  This compares to the unrealized loss in our commodity derivative portfolio for the three months endedSeptember 30, 2010 and an unrealized gain in our commodity derivative portfolio for the nine months endedSeptember 30, 2010. Included with our unrealized commodity derivative gains (losses) for the three and nine months endedSeptember 30, 2010, are the amortization of put premiums and other derivative costs, including the costs of hedge resets, of $0.4 million and $3.5 million, respectively.

We recognized realized commodity derivative losses during each of the three and nine months endedSeptember 30, 2011 and 2010. The increase in the realized losses for the three and nine months endedSeptember 30, 2011, as compared to the same period in the prior year, was due to higher crude oil and NGL market prices during the three and nine months endedSeptember 30, 2011, in relation to the strike prices of our settled contracts, as compared to the same period in the prior year.

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The increase in the realized losses for three and nine months endedSeptember 30, 2011 was partially offset by the net realized gains recorded for the derivative contracts assumed in the Crow Creek Acquisition that settled during the period.

Given the uncertainty surrounding future commodity prices, and the general inability to predict future commodity prices as they relate to the strike prices at which we have hedged our exposure, it is difficult to predict the magnitude and impact that marking our hedges to market will have on our income from operations in future periods.

Intersegment Eliminations. During the three and nine months endedSeptember 30, 2011, our South Texas Segment within our Midstream Business sold natural gas to our Upstream Segment to be used as fuel, and our Upstream Segment sold oil, condensate and natural gas to the marketing group within our Midstream Business for resale.

General and Administrative Expenses. General and administrative expenses increased by $5.4 million and $7.3 million, respectively, for the three and nine months endedSeptember 30, 2011 as compared to the same periods in 2010. This increase was partially due to an increase in salaries and benefits of $2.5 million and $4.9 million due to increased headcount over the last 12 months. The increase in salaries and benefits was offset by a decrease in equity-based compensation expense of approximately $1.2 million during the nine months endedSeptember 30, 2011, as compared to the nine months endedSeptember 30, 2010, primarily as a result of natural run-off (through vesting) of restricted common units granted in prior periods at higher prices. In addition, included within our general and administrative expenses for the nine months endedSeptember 30, 2011 are legal and other professional advisory fees of $2.3 million related to the Crow Creek Acquisition and for the three and nine months endedSeptember 30, 2011, $0.9 million and $1.1 million, respectively, of transition services expenses related to the Crow Creek Acquisition, while the three and nine months endedSeptember 30, 2010 include $0.6 million and $2.1 million, respectively, of legal and other professional advisory fees related to the recapitalization and related transactions and the associated lawsuit. During the three and nine months endedSeptember 30, 2011, the Partnership recognized $0.7 million and $0.6 million of bad debt expense versus a credit of $0.5 million and $0.2 million during the three and nine months endedSeptember 30, 2010, respectively.

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

Other Operating Income. In July 2008, SemGroup, L.P. and certain of its subsidiaries (“SemGroup”) filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. We historically sold portions of our condensate production from the Texas Panhandle and East Texas midstream systems to SemGroup. As a result of the bankruptcy, we took a $10.7 million bad debt charge during the year ended December 31, 2008, which was included in “Other Operating Expense” in the consolidated statement of operations. In August 2009, we sold $3.9 million of our outstanding receivables from SemGroup, which represented its 20-day administrative claims under 503(b)(9) of the United States Bankruptcy Code, for which we received a payment of $3.0 million. Due to certain repurchase obligations under the assignment agreement, we recorded the payment as a current liability within accounts payable as of December 31, 2010 and maintained the balance as a liability until it was clear that the repurchase obligations can no longer be triggered. Due to the expiration of the repurchase obligations during the nine months ended September 30, 2011, we released our reserve for these receivables and recorded other operating income of $2.9 million related to these reserves.

Total Other Expense.  Total other expense primarily consists of both realized and unrealized gains and losses from our interest rate swaps and interest expense related to our senior secured credit facility and our senior unsecured notes. On June 22, 2011, we terminated a $150 million notional amount 2.56% fixed rate interest rate swap at a total cost of $5.0 million, and extended the maturity of $250 million notional amount of our 4.095% fixed rate interest rate swaps from December 31, 2012 to June 22, 2015 with a fixed rate of 2.95%. During 2011, our realized settlements decreased by about $1.5 million and $1.6 million, respectively, as compared to 2010, as a result of increased LIBOR rates in 2011 and due to the two transactions described above. For the three and nine months endedSeptember 30, 2011, we recognized an unrealized loss of $3.2 million and an unrealized gain of $2.2 million, respectively, as compared to unrealized losses of $3.1 million and $12.3 million, respectively, during the same period in 2010, as a result of an increase in the forward interest rate curves. These unrealized mark-to-market losses did not have any impact on cash activities for the period, and are excluded by definition from our calculation of Adjusted EBITDA.

Interest expense increased by $6.8 million and $7.5 million, during the three and nine months endedSeptember 30, 2011, respectively, as compared to the same period in the prior year.  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.  On May 27, 2011, we issued $300 million of senior unsecured notes with a coupon of 8 3/8% through a private placement, and on June 22, 2011, we entered into an Amended and Restated Credit Agreement (see Note 8 to our unaudited condensed consolidated financial statements), which bears interest currently at LIBOR plus 2.25%.  The increase in interest

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expense is due to the transactions discussed above and to higher LIBOR rates during 2011, as compared to the same period in 2010.

Income Tax (Benefit) Provision. Income tax provision for 2011 and 2010 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 in 2008) and Eagle Rock Energy Acquisition Co. II, Inc. (acquiring entity of certain entities acquired in the Stanolind Acquisition) and their wholly-owned subsidiary 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 three and nine months endedSeptember 30, 2011, our tax benefit decreased by $0.2 million and increased by $0.8 million, respectively, as compared to the same periods in the prior year, primarily due to the reduction of the deferred tax liabilities created by the book/tax differences as a result of the federal income taxes associated with the Redman and Stanolind Acquisitions, receipt of state tax refunds and true-ups related to our prior year provision.   

Discontinued Operations. On May 24, 2010, we completed the sale of our fee mineral and royalty interests as well as our equity investment in Ivory Working Interests, L.P. (collectively, the "Minerals Business"). During the nine months endedSeptember 30, 2011, we received payments of $0.4 million related to pre-effective date operations and recorded this amount as part of discontinued operations. For the nine months endedSeptember 30, 2010, we generated revenues of $8.9 million and income from operations of $5.6 million. During the nine months endedSeptember 30, 2010, we recorded income to discontinued operations of $5.9 million.

Adjusted EBITDA

Adjusted EBITDA, as defined under "- Non-GAAP Financial Measures," increased by $29.5 million and $51.5 million from $32.7 million and $94.9 million, respectively, for the three and nine months endedSeptember 30, 2010 to $62.2 million and $146.4 million, respectively, for the three and nine months endedSeptember 30, 2011.

As described above, revenues minus cost of natural gas and NGLs for the Midstream Business (including the Texas Panhandle, East Texas/Louisiana, South Texas and Gulf of Mexico Segments, less unrealized gains from Eagle Rock Gas Services) increased by $6.0 million and $10.0 million, respectively, during the three and nine months endedSeptember 30, 2011, as compared to the comparable period in 2010. The Upstream Segment revenues increased $36.6 million and $71.0 million, respectively, during the three and nine months endedSeptember 30, 2011, as compared to the comparable periods in 2010. Intercompany eliminations revenues minus cost of natural gas and NGLs resulted in a $1.4 million increase and $0.2 million decrease, respectively. Our Corporate and Other Segment's realized commodity derivatives loss decreased by $1.2 million and $7.9 million, respectively, during the three and nine months endedSeptember 30, 2011 as compared to the comparable period in 2010. This resulted in total incremental revenues minus cost of natural gas and NGLs increasing by $42.8 million and $72.9 million, respectively, during the three and nine months endedSeptember 30, 2011 as compared to the comparable periods in 2010.  The incremental revenue amounts are adjusted to exclude the impact of unrealized commodity derivatives, which includes the amortization of put premiums and other derivative costs, and the non-cash mark-to-market Upstream Segment imbalances, none of which are included in the calculation of Adjusted EBITDA.

Operating expenses (including taxes other than income) for our Midstream Business increased by $2.3 million and $6.6 million, respectively, for the three and nine months endedSeptember 30, 2011, as compared to the same period in 2010, and operating expenses (including taxes other than income) for the Upstream Segment increased $5.8 million and $6.4 million, respectively, for the three and nine months endedSeptember 30, 2011, as compared to the comparable period in 2010.

General and administrative expense, excluding the impact of non-cash compensation charges related to our long-term incentive program and other non-recurring items and captured within our Corporate and Other Segment, increased during the three and nine months endedSeptember 30, 2011 by $5.2 million and $8.4 million, respectively, as compared to the respective period in 2010.

As a result, revenues (excluding the impact of unrealized commodity derivative activity) minus cost of natural gas and NGLs for the three and nine months endedSeptember 30, 2011, as compared to the same period in 2010 increased by $42.8 million and $72.9 million, respectively, operating expenses increased by $8.1 million and $12.9 million, respectively, and general and administrative expenses increased by $5.2 million and $8.4 million, respectively.  The increases in revenues minus the cost of natural gas and NGLs, while partially offset by the increases in operating costs and the increases in general and administrative expenses resulted in a increase to Adjusted EBITDA during each of the three and nine months endedSeptember 30, 2011, as compared to the three and nine months endedSeptember 30, 2010. Adjusted EBITDA excludes amortization of commodity hedge costs (including costs of hedge reset transactions) for the three and nine months ended

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September 30, 2010 of $0.4 million and $3.5 million, respectively.   Including these amortization costs, our Adjusted EBITDA for the three and nine months endedSeptember 30, 2010 would have been $32.2 million and $91.4 million, respectively.

LIQUIDITY AND CAPITAL RESOURCES

Historically, our sources of liquidity have included cash generated from operations, issuances of equity and debt securities and borrowings under our revolving credit facility. Our primary cash requirements have included general administrative and operating expenses, maintenance and growth capital expenditures, short-term working capital needs, interest payments on our outstanding debt, distributions to our unitholders and acquisitions of new assets or businesses. In 2010, we raised additional liquidity through a series of transactions that included the sale of our Minerals Business for approximately $171.6 million and a rights offering through which we received net proceeds of approximately $53.9 million. As part of the rights offering, we issued approximately 21.6 million warrants entitling holders to purchase a common unit of Eagle Rock for a price of $6.00 on certain designated exercise dates through May 2012. During the three and nine months endedSeptember 30, 2011, 5,390,384 and 13,039,928 warrants, respectively, were exercised for which we received proceeds of $32.3 million and $78.2 million, respectively. A total of approximately 7,625,317 warrants remained outstanding as of September 30, 2011.

On May 27, 2011, we completed the sale of $300 million of our senior unsecured notes (the "Senior Notes") through a private placement. The Senior Notes carry a coupon of 8 3/8%. The Senior Notes will mature on June 1, 2019, and interest is payable on June 1 and December 1 each year, commencing December 1, 2011. We used the net proceeds of approximately $290.3 million to repay borrowings outstanding under our revolving credit facility. See Note 8 to our unaudited condensed consolidated financial statements for a further description of our Senior Notes.

We believe that our historical sources of liquidity, including additional proceeds from warrant exercises, will be sufficient to fund our 2011 capital budget and to satisfy our short-term liquidity needs. With the acquisition of the Crow Creek properties, however, we expect the level of organic growth spending in our Upstream Business will increase substantially. We expect our organic growth spending to increase in our Midstream Business as well with the planned installation of the Woodall and Wheeler cryogenic processing plants in our Texas Panhandle segment. We also intend to continue to pursue attractive development and acquisition opportunities in the midstream and upstream sectors. Accordingly, we may utilize various additional, available financing sources, including the issuance of equity or debt securities to fund a portion of our organic growth expenditures and potential acquisitions. Our ability to complete future offerings of equity or debt securities and the timing of these offerings will depend upon various factors including prevailing market conditions and our financial condition.

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 (and, as necessary, allocate the attributable portion of our capital expenditures between) either:

• growth capital expenditures, which are made to acquire, construct, expand or upgrade our gathering, processing and treating assets; or to grow our natural gas, NGL, crude or sulfur production; or

• maintenance capital expenditures, which are made to replace partially or fully depreciated assets, meet regulatory requirements, or maintain the existing operating capacity of our gathering, processing and treating assets; or to maintain our natural gas, NGL, crude or sulfur production.

Our current 2011 capital budget, which excludes cost to acquire the Mid-Continent Properties, anticipates that we will spend approximately $196 million in total in 2011 on capital expenditures. Our capital expenditures, excluding acquisitions, were approximately $58.5 million and $101.9 million, respectively, for the three and nine months endedSeptember 30, 2011. On May 3, 2011, we completed the Crow Creek Acquisition for a total purchase price of $563.7 million (including our equity units, valued at their trading price at the closing of transaction) used as acquisition consideration. Our current 2012 capital budget anticipates that we will spend in excess of $335 million on capital expenditures.

We expect our capital expenditures to increase in response to environmental compliance associated with sulfur dioxide (SO₂) emissions.  We have certain permit obligations to lower our SO₂ emissions at our Alabama plant operations.  Additionally, in mid-2010, the Environmental Protection Agency (“EPA”) enacted new National Ambient Air Quality Standards (“2010 NAAQS”) which substantially lowered the emissions limits for SO₂ and mandated timelines for compliance.  In order to fulfill its permit obligations, comply with the new 2010 NAAQS requirements, and replace and upgrade certain aging assets in the Partnership's Alabama facilities, we expect to spend approximately $50 million over the next several years to enhance the SO₂ recovery capabilities at our Alabama operations.  The expected facility upgrades to our Alabama operations should not

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only increase the marketable sulfur recovered from the inlet gas stream, but also are anticipated to reduce plant fuel consumption, improve the plant's operating reliability and extend the plant's operating life. Management does not anticipate, however, that the required spending will generate returns consistent with our internal rate of return thresholds for discretionary capital investment. At this time, management has identified no other operational areas impacted by the 2010 NAAQS.

Management expects a substantial percentage of the total capital invested to achieve the SO₂ emissions standard at our Alabama operations will be classified as maintenance capital, and therefore will reduce the amount of distributable cash flow we recognize in the periods in which the capital is spent. Management, based on its current expectations, does not believe the additional maintenance capital will impact its objective of recommending an annualized distribution rate of $1.00 per common unit by the end of 2012; it will, however, reduce our distribution coverage ratio in the periods in which the capital is spent.

Distribution Policy

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

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

Revolving Credit Facility

On June 22, 2011, we entered into an Amended and Restated Credit Agreement (the “Credit Agreement”) with Wells Fargo Bank, National Association, as administrative agent and swingline lender, Bank of America, N.A. and The Royal Bank of Scotland plc, as co-syndication agents, BNP Paribas, as documentation agent, and the other lenders who are parties to the Credit Agreement. The Credit Agreement amended and restated our prior $880 million Credit Agreement (the “Prior Credit Agreement”). Upon the effectiveness of the Credit Agreement, all commitments of the lenders party to the Prior Credit Agreement were terminated and all loans and other indebtedness of the Partnership under the Prior Credit Agreement were renewed and extended, inclusive of new lender commitments, on the terms and conditions of the Credit Agreement. The Credit Agreement matures on June 22, 2016.

The credit facility under the Credit Agreement consists of aggregate initial commitments of $675 million that may, at our request and subject to the terms and conditions of the Credit Agreement, be increased up to a total aggregate amount of $1.2 billion. Availability under the credit facility is subject to a borrowing base comprised of two components: the upstream component and the midstream component. The initial borrowing base is $675 million. As of September 30, 2011, we had approximately $228.0 million of availability under the credit facility.

Debt Covenants

At September 30, 2011, 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 5.2 as compared to a minimum interest coverage covenant of 2.5; our leverage ratio, as defined in the Credit Agreement (i.e., Total Funded Indebtedness divided by Consolidated EBITDA), was 3.2 as compared to a maximum leverage ratio of 4.5; and our current ratio, as defined in the Credit Agreement, was 2.2 as compared to a minimum current ratio covenant of 1.0.  We believe that we will remain in compliance with our financial covenants through 2011.

Our goal is to maintain our ratio of outstanding debt to Adjusted EBITDA, or “leverage ratio,” in the range of approximately 3.0 to 3.5 on a sustained basis. We believe this leverage ratio range to be appropriate for our business.  We expect our efforts to maintain or reduce our leverage ratio during 2011 will be primarily through investing in attractive growth opportunities that will increase our Adjusted EBITDA. We also expect our leverage ratio to benefit from any exercise of our

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approximately 7,625,317 warrants outstanding as of September 30, 2011, which carry an exercise price of $6.00 per common unit and expire on May 15, 2012. Proceeds to us from the remaining warrants, if exercised in full, would total approximately $46 million. It is our intention to use future proceeds from warrants being exercised, if any, to pay for general partnership purposes, including to pay down borrowings outstanding under our revolving credit facility, absent any organic growth or acquisition opportunities.

For a detailed description of our Credit Agreement, see Note 8 to our unaudited condensed consolidated financial statements.

Cash Flows

Cash Distributions

On January 27, 2011, we declared our fourth quarter 2010 cash distribution of $0.15 per unit to our common unitholders of record as of the close of business on February 7, 2011. The distribution was paid on February 14, 2011.

On April 26, 2011, we declared our first quarter 2011 cash distribution of $0.15 per unit to our common unitholders of record as of the close of business on May 9, 2011, except for the common units issued in connection with the acquisition of Crow Creek Energy on May 3, 2011 (see further discussion within "- Overview - Acquisitions"), which were not eligible to receive the first quarter 2011 distribution. This distribution was paid on May 13, 2011.

On July 27, 2011, we declared our second quarter 2011 cash distribution of $0.1875 per unit to our common unitholders of record as of the close of business on August 5, 2011. The distribution was paid on August 12, 2011.

On October 26, 2011, we declared our third quarter 2011 cash distribution of $0.20 per unit to our common unitholders of record as of the close of business on November 7, 2011, except for the restricted units granted on November 1, 2011 (see further discussion within "Overview - Subsequent Events"). The distribution will be paid on November 14, 2011.

Working Capital.

Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. As of September 30, 2011, working capital was a negative $26.4 million as compared to a negative $54.2 million as of December 31, 2010.

The net increase in working capital of $27.8 million from December 31, 2010 to September 30, 2011 resulted primarily from the following factors:

• cash balances and marketable securities increased overall by $13.6 million;

• trade accounts receivable increased by $17.7 million primarily from the impact of the Crow Creek Acquisition and higher revenues due to higher commodity prices;

• risk management net working capital balance increased by a net $53.9 million as a result of derivative contracts acquired as part of the Crow Creek Acquisition and changes in current portion of mark-to-market unrealized positions as a result of decreases to the forward crude oil, natural gas and NGL price curves;

• accounts payable increased by $43.4 million primarily as a result of the Crow Creek Acquisition, activities and timing of payments, including capital expenditures activities; and

• accrued liabilities increased by $10.9 million primarily reflecting payment of employee benefit accruals, higher interest payments and the timing of payment of unbilled expenditures related primarily to capital expenditures.

Cash Flows for the Nine Months Ended September 30,2011 Compared to the Nine Months Ended September 30,2010

Cash Flow from Operating Activities. Cash flows from operating activities increased $8.1 million during the nine months endedSeptember 30, 2011 as compared to the nine months endedSeptember 30, 2010. This increase was primarily due to an increase in our results of operations from our Crow Creek Acquisition and higher commodity prices, which resulted in higher cash flows from the sale of our equity crude oil and NGLs volumes and higher cash flows from the sale of sulfur.  Higher commodity prices also resulted in us realizing net settlement losses on our commodity derivatives during the

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nine months endedSeptember 30, 2011. The increase in operations was offset by our payment of $5.0 million to unwind an interest rate derivative contract, a payment of $4.8 million to unwind certain commodity derivative contracts and a payment of $14.6 million to adjust the strike price on certain existing commodity derivative contracts to the forward market price as of the date of the adjustment. For the nine months endedSeptember 30, 2011, we paid $5.9 million to adjust the strike price on an existing commodity derivative contract to the forward market price as of the date the adjustment was executed.

Cash Flows from Investing Activities. Cash flows used in investing activities for the nine months endedSeptember 30, 2011 were $297.5 million as compared to cash flows provided by investing activities of $122.8 million for the nine months endedSeptember 30, 2010. The key difference between periods is our cash outlay of $220.3 million for the Crow Creek Acquisition during nine months endedSeptember 30, 2011, as compared to the net proceeds of $171.6 million received from the sale of our Minerals Business during nine months endedSeptember 30, 2010. In addition, we incurred increased cash outlays of $37.0 million for capital expenditures, in particular spending related to our Arrington Ranch - Phoenix Plant, partially offset by proceeds from the sale of our Wildhorse Gathering System of $5.7 million during the nine months endedSeptember 30, 2011.  

Cash Flows from Financing Activities. Cash flows provided by financing activities during the nine months endedSeptember 30, 2011 were $226.8 million as compared to cash flows used in financing activities of $191.2 million for the nine months endedSeptember 30, 2010. Key differences between periods include net repayments to our revolving credit facility of $87.0 million during the nine months endedSeptember 30, 2011 as compared to net repayments of $239.0 million to our revolving credit facility during the nine months endedSeptember 30, 2010.  We also received $297.8 million from the sale of our Senior Notes during the nine months ended ended September 30, 2011. Cash outflows related to our distributions increased to $49.1 million during the nine months endedSeptember 30, 2011 as compared to $5.1 million during the nine months endedSeptember 30, 2010 as a result of increasing our quarterly distribution from $0.025 for the payments made in the first three quarters of 2010 (for the fourth quarter of 2009 and the first and second quarters of 2010) to $0.15 paid in the first two quarters of 2011 (for the fourth quarter of 2010 and the first quarter of 2011) and $0.1875 paid in the third quarter of 2011 (for the second quarter of 2011). We also received $78.2 million due to the exercise of warrants during the nine months endedSeptember 30, 2011, as compared to $1.7 million from the exercise of warrants during the same period in 2010.

Hedging Strategy

We use a variety of hedging instruments such as fixed-price swaps, costless collars and put options to manage our risks related to our commodity price and interest rate exposure. At times our hedging strategy may involve adjusting strike prices of existing hedges to better reflect current market conditions or to meet other corporate 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.  Hedge transactions such as these impact our liquidity in that we are required to pay the present value of the difference between the hedged price and the current futures price.  These transactions also increase our exposure to the counterparties through which we execute the hedges. Under this strategy, and in conjunction with the refinancing of our revolving credit facility, we novated a portfolio of calendar year 2011, 2012 and 2013 hedges from a counterparty that was not continuing as a lender under our revolving credit facility and, at a cost of $14.6 million, adjusted the strike price to reflect current market prices of several hedges. For further description of our hedging activity, see Notes 11 and 21 to our unaudited condensed consolidated financial statements.

Off-Balance Sheet Obligations.

We have no off-balance sheet transactions or obligations. 

Total Contractual Obligations.

Since December 31, 2010, the material change in our total contractual obligations consisted of an increase in our total long-term debt from $530.0 million to $740.9 million as of September 30, 2011.  The increase is attributable in part to our issuance of $300 million of Senior Notes in May 2011.  Additionally, on June 22, 2011 we entered into a Credit Agreement pursuant to which all commitments of the lenders party to the Prior Credit Agreement were terminated and all loans and other indebtedness of the Partnership were renewed and extended through the new Credit Agreement.  For further description of the Senior Notes and Credit Agreement, see “Revolving Credit Facility" and "Debt Covenants" above.

Recent Accounting Pronouncements

In September 2009, the Financial Accounting Standards Board ("FASB") issued a consensus which revises the standards for recognizing revenue on arrangements with multiple deliverables.  Before evaluating how to recognize revenue for

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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.  This standard was effective for us on January 1, 2011 and did not have a material impact on our 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 disclosures guidance on January 1, 2010, except for the gross presentation of the Level 3 rollforward, which was adopted by us on January 1, 2011.

In May 2011, the FASB issued additional guidance which is intended to result in convergence between U.S. GAAP and International Financial Reporting Standards (“IFRS”) requirements for measurement of and disclosures about fair value. The amendments are not expected to have a significant impact on companies applying U.S. GAAP. Key provisions of the amendments include: a prohibition on grouping financial instruments for purposes of determining fair value, except when an entity manages market and credit risks on the basis of the entity’s net exposure to the group; an extension of the prohibition against the use of a blockage factor to all fair value measurements (that prohibition currently applies only to financial instruments with quoted prices in active markets); and a requirement that for recurring Level 3 fair value measurements, entities disclose quantitative information about unobservable inputs, a description of the valuation process used and qualitative details about the sensitivity of the measurements. In addition, for items not carried at fair value but for which fair value is disclosed, entities will be required to disclose the level within the fair value hierarchy that applies to the fair value measurement disclosed. This guidance is effective for interim and annual periods beginning after December 15, 2011. The adoption of this guidance is not expected to have a significant impact on our fair value measurements, financial condition, results of operations or cash flows.

Non-GAAP Financial Measures

We include in this report 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 U.S. 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 used as a supplemental financial measure by external users of our financial statements such as investors, commercial banks and research analysts.  For example, the compliance covenant used by our lenders under our revolving credit facility which is designed to measure the viability of us and our ability to perform under the terms of our revolving credit facility uses our Adjusted EBITDA.  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. Our Adjusted EBITDA definition may not be comparable to Adjusted EBITDA or similarly titled measures of other entities, as other entities may not calculate Adjusted EBITDA in the same manner as us. For example, we include in Adjusted EBITDA the actual settlement revenue created from our commodity hedges by virtue of transactions undertaken by us to reset commodity hedges to higher prices or purchase puts or other similar floors despite the fact that we exclude from

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Adjusted EBITDA any charge for amortization of the cost of such commodity hedge reset transactions or puts. 

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

Adjusted EBITDA does not include interest expense, income taxes or depreciation and amortization expense. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate net income. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net income determined under U.S. GAAP, as well as Adjusted EBITDA, to evaluate our performance and liquidity.

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The following table sets forth a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with U.S. GAAP:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Reconciliation of Adjusted EBITDA to net cash flows provided by (used in) operating activities and net income:
Net cash flows provided by operating activities	$	59,258		$	34,145		$	84,951		$	76,807
Add (deduct):
Discontinued operations	(197		)	166			210			43,811
Depreciation, depletion, amortization and impairment	(44,910		)	(29,324		)	(105,068		)	(87,367		)
Amortization and write-offs of debt issuance costs and discounts	(642		)	(242		)	(1,688		)	(1,062		)
Risk management portfolio value changes	94,634			(14,225		)	114,403			31,482
Reclassing financing derivative settlements	1,263			373			3,706			1,001
Other	(1,106		)	(1,498		)	22			(5,705		)
Accounts receivable and other current assets	(4,283		)	(13,398		)	1,200			(22,109		)
Accounts payable, due to affiliates and accrued liabilities	(6,929		)	(1,008		)	91			9,474
Other assets and liabilities	277			(226		)	892			555
Net income	97,365			(25,237		)	98,719			46,887
Add (deduct):
Interest (income) expense net	13,766			8,470			33,120			26,935
Depreciation, depletion, amortization and impairment	44,910			29,324			105,068			87,367
Income tax benefit	(1,077		)	(1,244		)	(1,810		)	(970		)
EBITDA	154,964			11,313			235,097			160,219
Add:
Risk management portfolio value changes	(93,846		)	20,156			(88,355		)	(25,551		)
Physical contract fair value changes	(538		)	—			(538		)	—
Restricted unit compensation expense	1,507			1,294			3,441			4,652
Non-cash mark-to-market Upstream imbalances	(107		)	102			(123		)	(465		)
Discontinued operations	197			(166		)	(210		)	(43,811		)
Other income	—			(21		)	—			(99		)
Other operating income	—			—			(2,893		)	—
ADJUSTED EBITDA(a)	$	62,177		$	32,678		$	146,419		$	94,945

________________________

(a) Adjusted EBITDA excludes amortization of commodity hedge costs (including costs of hedge reset transactions) for the three and nine months endedSeptember 30, 2010 of $0.4 million and $3.5 million, respectively.  Including these amortization costs, our Adjusted EBITDA for the three and nine months endedSeptember 30, 2010 would have been $32.2 million and $91.4 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 authority levels, and for the establishment of a Risk Management Committee ("RMC"). The RMC 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 RMC is responsible for the overall management of commodity price risk, interest rate risk and credit risk, including monitoring exposure limits.

Commodity Price Risk

We are exposed to the impact of market fluctuations in the prices of crude oil, natural gas, NGLs and other commodities as a result of our gathering, processing, producing and marketing activities, which produce a naturally long position in these commodities. Our profitability and cash flow are affected by changes in prices of 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 have generally correlated with changes in the price of crude oil.

We manage this commodity price exposure through an integrated strategy that includes management of our contract portfolio, matching sales prices of commodities with purchases, optimization of our portfolio by monitoring basis and other price differentials in our areas of operations, and the use of derivative contracts. Crude oil, natural gas and NGL prices can also indirectly affect our profitability by influencing the level of drilling activity and related opportunities for our service.

We frequently use financial derivatives (“hedges”) to reduce our exposure to commodity price risk. We have implemented a Risk Management Policy which allows management to execute crude oil, natural gas liquids and natural gas hedging instruments, which may include swaps, collars, options and other derivatives, in order to reduce exposure to substantial adverse changes in the prices of these commodities. These hedges are only intended to mitigate the risk associated with our natural physical position. We monitor and ensure compliance with this Risk Management Policy through senior level executives in our operations, finance and legal departments.

We have not designated our contracts as accounting hedges based on authoritative guidance. As a result, we mark our derivatives to market with the resulting change in fair value being included in our statement of operations. For each of the three and nine months endedSeptember 30, 2011, we recorded a gain on risk management instruments of $94.3 million and $68.2 million, respectively, representing a fair value (unrealized) gain of $97.0 million and $86.2 million and net (realized) settlement losses of $2.7 million and $18.0 million, respectively. For the three and nine months endedSeptember 30, 2010, we recorded a loss on risk management instruments of $18.6 million and a gain of $27.8 million, respectively, representing a fair value (unrealized) loss of $17.0 million and a gain of $37.8 million, respectively, amortization of put premiums and other derivative costs of $0.4 million and $3.5 million, respectively, and net (realized) settlement losses of $1.5 million and $10.0 million, respectively. As of September 30, 2011, the fair value net asset of these commodity contracts totaled approximately $75.9 million.

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

In addition, we have recently begun operations through our natural gas marketing subsidiary. Though we intend for these activities to complement our existing operations, they may expose us to additional and different risks, as our activities are expected to be more comprehensive than our commodities derivative activities described above. To minimize our exposure to trading losses, we have established procedures to monitor and limit risk, including the use of value-at-risk metrics. 

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Interest Rate Risk

We are exposed to variable interest rate risk as a result of borrowings under our revolving credit facility. 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. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense. As of September 30, 2011, the notional amount of our interest rate swaps was in excess of the outstanding borrowings under our Credit Agreement by approximately $7.0 million.

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 and nine months endedSeptember 30, 2011, we recorded a fair value (unrealized) loss of $3.2 million and a gain of $2.2 million, respectively, and realized losses of $3.7 million and $13.4 million, respectively. For the three and nine months endedSeptember 30, 2010, we recorded fair value (unrealized) losses of $3.1 million and $12.3 million, respectively, and realized losses of $5.2 million and $15.0 million, respectively. As of September 30, 2011, the fair value liability of these interest rate contracts totaled approximately $27.4 million.

Credit Risk

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

This concentration of credit risk may affect our overall credit risk in that these customers may be similarly affected by changes in the natural gas, natural gas liquids, petrochemical and other segments of the energy industry, the economy in general, the regulatory environment and other factors.

Our derivative counterparties include BNP Paribas, Wells Fargo Bank, National Association, Comerica Bank, Bank of Nova Scotia, The Royal Bank of Scotland plc, Bank of America N.A., J Aron & Company (an affiliate of Goldman Sachs), ING Capital Markets LLC and BBVA Compass Bank.

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Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Based on the evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (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

As reported during the prior quarter, we completed the acquisition of CC Energy, LLC during the second quarter of 2011. Because of the timing of the acquisition, management anticipates that it will not include the internal control process for this entity in its 2011 internal control assessment included in our Annual Report for the year ended December 31, 2011. The acquisition is excluded from the certification required under Section 302 of the Sarbanes-Oxley Act of 2002. We will include all aspects of internal control over financial reporting for the new business and the acquisition, including changes to our internal controls over financial reporting based on this acquisition, in our 2012 evaluation and assessment.

There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d - 15(f) under the Exchange Act) that occurred during our 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 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.

Item 1A. Risk Factors.

In addition to the other information set forth in this quarterly report on Form 10-Q, you should carefully consider the risks discussed in our annual report on Form 10-K for the year ended December 31, 2010, under the headings “Item 1. Business,” “Item 1A. Risk Factors,” “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” which risks could materially affect our business, financial condition or future results. Except for the risk factors set forth below, there have been no material changes in our risk factors from those described in our annual report on Form 10-K for the year ended December 31, 2010 and our quarterly report on Form 10-Q for the quarterly period ended June 30, 2011.

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

On August 15, 2011, certain entities affiliated with Eagle Rock Holdings, L.P. and Natural Gas Partners (collectively, the “NGP Parties”) exercised 3,975,362 warrants to purchase common units, and Eagle Rock Energy Partners, L.P. (the “Partnership”) issued an equivalent number of common units, for an aggregate exercise price of approximately $23.9 million. The Warrants were initially issued in a transaction exempt from the registration requirements of the Securities Act of 1933 (the “Securities Act”) pursuant to Section 4(2) thereunder in connection with the Partnership’s June 2010 rights offering. Similarly, the issuance of the common units upon exercise of the Warrants occurred in a transaction exempt from the registration requirements of the Securities Act pursuant to Section 4(2) thereunder.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. [Removed and Reserved]

Item 5. Other Information.

None.

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Item 6. Exhibit

Exhibit Number	Description
3.1	Certificate of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Partnership's Registration Statement on Form S-1 (File No. 333-134750)).
3.2	Second Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Partnership's Current Report on Form 8-K filed on May 25, 2010).
3.3	Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 4.1 to the Partnership's Current Report on Form 8-K filed on July 30, 2010).
3.4	Certificate of Limited Partnership of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.3 to the Partnership's Registration Statement on Form S-1 (File No. 333-134750)).
3.5	Limited Partnership Agreement of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.4 to the Partnership's Registration Statement on Form S-1 (File No. 333-134750)).
3.6	Certificate of Formation of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 3.5 to the Partnership's Registration Statement on Form S-1 (File No. 333-134750)).
3.7	Third Amended and Restated Limited Liability Company Agreement of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 4.2 to the Partnership's Current Report on Form 8-K filed with the Commission on July 30, 2010).
10.1	Amendment to Natural Gas Liquids Exchange Agreement By and Between Oneok Hydrocarbon, L.P, and Eagle Rock Field Services, L.P. (incorporate by reference to Exhibit 10.1 of the registrants current report on Form 8-K filed with the Commission on August 23, 2011)
31.1*	Certification of Periodic Financial Reports by Joseph A. Mills in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Periodic Financial Reports by Jeffrey P. Wood in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of Periodic Financial Reports by Joseph A. Mills in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of Periodic Financial Reports by Jeffrey P. Wood in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS**	XBRL Instance Document
101.SCH**	XBRL Taxonomy Extension Schema Document
101.CAL**	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF**	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB**	XBRL Taxonomy Extension Label Linkbase Document

_______________________________

* Filed herewith.

** Furnished herewith 

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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: November 4, 2011	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
	Name:	Jeffrey P. Wood
	Title:	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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Index to Exhibits

Exhibit Number	Description
3.1	Certificate of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Partnership's Registration Statement on Form S-1 (File No. 333-134750)).
3.2	Second Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Partnership's Current Report on Form 8-K filed on May 25, 2010).
3.3	Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 4.1 to the Partnership's Current Report on Form 8-K filed on July 30, 2010).
3.4	Certificate of Limited Partnership of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.3 to the Partnership's Registration Statement on Form S-1 (File No. 333-134750)).
3.5	Limited Partnership Agreement of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.4 to the Partnership's Registration Statement on Form S-1 (File No. 333-134750)).
3.6	Certificate of Formation of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 3.5 to the Partnership's Registration Statement on Form S-1 (File No. 333-134750)).
3.7	Third Amended and Restated Limited Liability Company Agreement of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 4.2 to the Partnership's Current Report on Form 8-K filed with the Commission on July 30, 2010).
10.1	Amendment to Natural Gas Liquids Exchange Agreement By and Between Oneok Hydrocarbon, L.P, and Eagle Rock Field Services, L.P. (incorporate by reference to Exhibit 10.1 of the registrants current report on Form 8-K filed with the Commission on August 23, 2011)
31.1*	Certification of Periodic Financial Reports by Joseph A. Mills in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Periodic Financial Reports by Jeffrey P. Wood in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of Periodic Financial Reports by Joseph A. Mills in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of Periodic Financial Reports by Jeffrey P. Wood in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS**	XBRL Instance Document
101.SCH**	XBRL Taxonomy Extension Schema Document
101.CAL**	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF**	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB**	XBRL Taxonomy Extension Label Linkbase Document

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* Filed herewith.

** Furnished herewith