Eagle Rock Energy Partners L P (EROC) 10-Q 2012 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 2012

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.

Large accelerated Filer  x	Accelerated Filer  o
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 136,644,946 common units outstanding as of August 1, 2012.

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements	2
	Unaudited Condensed Consolidated Balance Sheets as of June 30, 2012 and December 31, 2011	2
	Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2012 and 2011	3
	Unaudited Condensed Consolidated Statement of Members' Equity for the six months ended June 30, 2012	4
	Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2012 and 2011	5
	Notes to the Unaudited Condensed Consolidated Financial Statements	6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	34
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	54
Item 4.	Controls and Procedures	55
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	56
Item 1A.	Risk Factors	56
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	56
Item 3.	Defaults Upon Senior Securities	57
Item 4.	Mine Safety Disclosures	57
Item 5.	Other Information	57
Item 6.	Exhibits	57

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

($ in thousands)

	June 30, 2012		December 31, 2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	70	$	877
Accounts receivable (a)	83,569		97,832
Risk management assets	54,290		13,080
Prepayments and other current assets	13,025		13,739
Total current assets	150,954		125,528
PROPERTY, PLANT AND EQUIPMENT — Net	1,800,180		1,763,674
INTANGIBLE ASSETS — Net	88,956		109,702
DEFERRED TAX ASSET	1,234		1,432
RISK MANAGEMENT ASSETS	39,786		24,290
OTHER ASSETS	17,421		21,062
TOTAL	$	2,098,531	$	2,045,688
LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	113,845	$	145,985
Accrued liabilities	13,039		12,734
Taxes payable	460		487
Risk management liabilities	3,840		11,649
Total current liabilities	131,184		170,855
LONG-TERM DEBT	885,954		779,453
ASSET RETIREMENT OBLIGATIONS	33,962		33,303
DEFERRED TAX LIABILITY	44,302		45,216
RISK MANAGEMENT LIABILITIES	2,086		6,893
OTHER LONG TERM LIABILITIES	2,427		2,621
COMMITMENTS AND CONTINGENCIES (Note 12)
MEMBERS' EQUITY (b)	998,616		1,007,347
TOTAL	$	2,098,531	$	2,045,688

________________________ 

(a) Net of allowance for bad debt of $992 as of June 30, 2012 and $1,347 as of December 31, 2011.

(b) 133,019,853 and 127,606,229 common units were issued and outstanding as of June 30, 2012 and December 31, 2011, respectively. These amounts do not include unvested restricted common units granted under the Partnership's long-term incentive plan of 3,585,918 and 2,560,110 as of June 30, 2012 and December 31, 2011, respectively.

See accompanying notes to unaudited condensed consolidated financial statements.  

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EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

($ in thousands, except per unit amounts)

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
REVENUE:
Natural gas, natural gas liquids, oil, condensate and sulfur sales	$	172,945		$	265,317		$	395,658		$	468,372
Gathering, compression, processing and treating fees	10,451			12,304			21,962			25,549
Commodity risk management gains (losses)	95,965			34,338			87,357			(26,107		)
Other revenue	3,043			(244		)	3,182			1,265
Total revenue	282,404			311,715			508,159			469,079
COSTS AND EXPENSES:
Cost of natural gas, natural gas liquids, and condensate	97,914			172,674			228,368			319,993
Operations and maintenance	27,562			21,951			54,611			41,426
Taxes other than income	4,620			5,189			9,770			8,505
General and administrative	18,736			15,902			35,577			27,678
Other operating income	—			(2,893		)	—			(2,893		)
Impairment	21,402			4,560			66,924			4,884
Depreciation, depletion and amortization	38,354			31,576			77,648			55,274
Total costs and expenses	208,588			248,959			472,898			454,867
OPERATING INCOME	73,816			62,756			35,261			14,212
OTHER EXPENSE:
Interest expense, net	(10,647		)	(6,308		)	(20,888		)	(9,529		)
Interest rate risk management losses	(1,463		)	(1,643		)	(3,042		)	(4,305		)
Other expense, net	4			(114		)	(45		)	(164		)
Total other expense	(12,106		)	(8,065		)	(23,975		)	(13,998		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	61,710			54,691			11,286			214
INCOME TAX BENEFIT	(79		)	(691		)	(170		)	(733		)
INCOME FROM CONTINUING OPERATIONS	61,789			55,382			11,456			947
DISCONTINUED OPERATIONS, NET OF TAX	—			(311		)	—			407
NET INCOME	$	61,789		$	55,071		$	11,456		$	1,354

NET INCOME PER COMMON UNIT—BASIC AND DILUTED:
Income from Continuing Operations
Common units - Basic	$	0.46	$	0.50	$	0.08	$	—
Common units - Diluted	$	0.46	$	0.47	$	0.08	$	—
Discontinued Operations
Common units - Basic	$	—	$	—	$	—	$	—
Common units - Diluted	$	—	$	—	$	—	$	—
Net Income
Common units - Basic	$	0.46	$	0.50	$	0.08	$	0.01
Common units - Diluted	$	0.46	$	0.47	$	0.08	$	0.01
Weighted Average Units Outstanding (in thousands)
Common units - Basic	131,905		108,117		130,034		96,130
Common units - Diluted	133,439		115,897		132,101		103,950

 See accompanying notes to unaudited condensed consolidated financial statements.

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EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF MEMBERS’ EQUITY

FOR THE SIX MONTHS ENDED JUNE 30, 2012

($ in thousands, except unit amounts)

	Number of Common Units		Common Units			Total
BALANCE — December 31, 2011	127,606,229		$	1,007,347		$	1,007,347
Net income	—		11,456			11,456
Distributions	—		(56,711		)	(56,711		)
Vesting of restricted units	145,562		—			—
Exercised warrants	5,300,588		31,804			31,804
Repurchase of common units	(32,526	)	(292		)	(292		)
Equity based compensation	—		5,012			5,012
BALANCE — June 30, 2012	133,019,853		$	998,616		$	998,616

 See accompanying notes to unaudited condensed consolidated financial statements.  

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EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

($ in thousands)

	Six Months Ended June 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	11,456		$	1,354
Adjustments to reconcile net income to net cash provided by operating activities:
Discontinued operations	—			(407		)
Depreciation, depletion and amortization	77,648			55,274
Impairment	66,924			4,884
Amortization of debt issuance costs	1,406			1,046
Reclassing financing derivative settlements	(8,420		)	(2,443		)
Equity-based compensation	5,012			1,934
Other operating income	—			(2,893		)
Other	291			(169		)
Changes in assets and liabilities—net of acquisitions:
Accounts receivable	14,263			(2,215		)
Prepayments and other current assets	714			(3,268		)
Risk management activities	(69,322		)	(19,769		)
Accounts payable	(39,172		)	(8,701		)
Accrued liabilities	305			1,681
Other assets	2,281			(17		)
Other current liabilities	(1,615		)	(598		)
Net cash provided by operating activities	61,771			25,693
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(150,023		)	(31,195		)
Acquisitions, net of cash acquired	—			(220,326		)
Proceeds from sale of assets	—			6,093
Purchase of intangible assets	(2,176		)	(1,315		)
Net cash used in investing activities	(152,199		)	(246,743		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	373,850			709,329
Repayment of long-term debt	(267,450		)	(791,329		)
Proceeds from senior notes	—			297,837
Payment of debt issuance costs	—			(13,802		)
Proceeds from derivative contracts	8,420			2,443
Exercise of warrants	31,804			45,897
Repurchase of common units	(292		)	(119		)
Distributions to members and affiliates	(56,711		)	(26,250		)
Net cash provided by financing activities	89,621			224,006
CASH FLOWS FROM DISCONTINUED OPERATIONS:
Operating activities	—			(180		)
Net cash used in discontinued operations	—			(180		)
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	(807		)	2,776
CASH AND CASH EQUIVALENTS—Beginning of period	877			4,049
CASH AND CASH EQUIVALENTS—End of period	$	70		$	6,825
NONCASH INVESTING AND FINANCING ACTIVITIES:
Units issued for acquisitions	$	—		$	336,125
Transaction fees, not paid	$	—		$	1,234
Investments in property, plant and equipment, not paid	$	38,406		$	20,653
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid—net of amounts capitalized	$	19,523		$	11,225
Cash paid for taxes	$	567		$	984

See accompanying notes to unaudited condensed consolidated financial statements.

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. ORGANIZATION AND DESCRIPTION OF BUSINESS

Description of Business—Eagle Rock Energy Partners, L.P. ("Eagle Rock Energy" or the "Partnership") is a domestically-focused growth-oriented limited partnership engaged in the business of (i) gathering, compressing, treating, processing and transporting natural gas; fractionating and transporting natural gas liquids ("NGLs"); crude oil logistics and marketing; and natural gas marketing and trading (collectively the "Midstream Business"); and (ii) developing and producing interests in oil and natural gas properties (the "Upstream Business"). The Partnership's midstream assets are located in four significant natural gas producing regions; the Texas Panhandle, East Texas/Louisiana, South Texas and the Gulf of Mexico. These four regions are productive, mature, natural gas producing basins that have historically experienced significant drilling activity. 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 reports its Midstream Business results through three segments: the Texas Panhandle Segment, the East Texas and Other Midstream Segment and the Marketing and Trading Segment.  The Partnership's upstream assets are located in four significant oil and gas producing regions: (i) Southern Alabama (which includes the associated gathering, processing and treating assets); (ii) Mid-Continent (which includes areas in Oklahoma, Arkansas, Texas Panhandle and North Texas); (iii) Permian (which includes areas in West Texas); and (iv) East Texas/South Texas/Mississippi. The Partnership reports its Upstream Business through one segment.

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 the Partnership.

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Principles of Consolidation—The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). 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, 2011. That report contains a more comprehensive summary of the Partnership's major accounting policies. In the opinion of management, the accompanying unaudited condensed consolidated financial statements contain all appropriate adjustments, all of which are normally recurring adjustments unless otherwise noted, considered necessary to present fairly the financial position of the Partnership and its consolidated subsidiaries and the results of operations and cash flows for the respective periods. Operating results for the three and six months endedJune 30, 2012 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2012.

Eagle Rock Energy is the owner of non-operating undivided interests in certain gas processing plants and gas gathering systems. 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 unaudited condensed consolidated financial statements.

The Partnership has provided a discussion of significant accounting policies in its Annual Report on Form 10-K for the year ended December 31, 2011. Certain items from that discussion are repeated or updated below as necessary to assist in the understanding of these financial statements.

Use of Estimates—The preparation of financial statements in conformity with 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. 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.

Inventory—Inventory is stated at the lower of cost or market, with cost being determined using the average cost method. At June 30, 2012 and December 31, 2011, the Partnership had $1.1 million and $1.4 million, respectively, of crude oil finished goods inventory, which is recorded as part of Other Current Assets within the unaudited condensed consolidated

6

balance sheet.

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.

For its oil and natural gas long-lived assets, 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 and/or forward prices 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. Unproved properties (both individually significant and insignificant) are assessed periodically within specific geographic areas and, if necessary, impairments are charged to expense.

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.  

See Notes 4 and 6 for further discussion on impairment charges.

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 natural gas 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 June 30, 2012 and December 31, 2011, the Partnership's Upstream Segment had an imbalance receivable balance of $0.2 million and $0.3 million, respectively, and it had a long-term payable balance of $1.4 million and $1.6 million as of June 30, 2012 and December 31, 2011, respectively.

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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 unaudited condensed consolidated balance sheets and marked-to-market using current market prices in effect for the reporting period of the outstanding imbalances. For the Midstream Business, as of June 30, 2012, the Partnership had no imbalance receivables and imbalance payables totaling $1.1 million. For the Midstream Business, as of December 31, 2011, the Partnership had imbalance receivables totaling $0.6 million and imbalance payables totaling $0.5 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.

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 normal sales, with the exception of certain contracts with our natural gas trading and marketing business. 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 unaudited condensed consolidated balance sheet at the instrument's fair value with changes in fair value reflected in the unaudited condensed 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 unaudited condensed consolidated statement of cash flows. See Note 10 for a description of the Partnership's risk management activities.

Other Reclassifications—Certain prior period financial statement balances have been reclassified to conform to the current year presentation. These reclassifications had no effect on the recorded net income.

NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS

In May 2011, the Financial Accounting Standards Board ("FASB") issued additional guidance intended to result in convergence between 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 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 was effective for the Partnership on January 1, 2012 and did not have a significant impact on the Partnership’s fair value measurements, financial condition, results of operations or cash flows.

In December 2011, the FASB issued new guidance related to disclosure requirements about the nature of an entity's rights of set-off and related arrangements associated with its financial instruments and derivative instruments. The new disclosures are designed to make financial statements that are prepared under U.S. GAAP more comparable to those prepared under IFRS. To better facilitate comparison between financial statements prepared under U.S. GAAP and IFRS, the new disclosures will give financial statement users information about both gross and net exposures. The disclosure requirements are effective for annual reporting periods beginning on or after January 1, 2013, and interim periods therein, with retrospective application required. The Partnership is currently evaluating the impact, if any, of the adoption of this guidance on its consolidated financial statements and related disclosures.

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NOTE 4. PROPERTY PLANT AND EQUIPMENT

Fixed assets consisted of the following:

	June 30, 2012			December 31, 2011
	($ in thousands)
Land	$	2,607		$	2,607
Plant	353,681			290,460
Gathering and pipeline	656,222			681,227
Equipment and machinery	36,105			31,720
Vehicles and transportation equipment	4,115			4,169
Office equipment, furniture, and fixtures	1,186			1,318
Computer equipment	10,674			9,539
Linefill	4,307			4,324
Proved properties	1,140,451			1,050,872
Unproved properties	73,209			91,363
Construction in progress	47,908			56,588
	2,330,465			2,224,187
Less: accumulated depreciation, depletion and amortization	(530,285		)	(460,513		)
Net property plant and equipment	$	1,800,180		$	1,763,674

The following table sets forth the total depreciation, depletion, capitalized interest costs and impairment expense by type of asset within the Partnership's unaudited condensed consolidated statements of operations:

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	($ in thousands)
Depreciation	$	14,122	$	13,488	$	28,377	$	27,103
Depletion	$	21,301	$	15,154	$	43,351	$	22,306
Capitalized interest costs	$	373	$	52	$	732	$	72
Impairment expense:
Unproved properties (a)	$	785	$	—	$	785	$	324
Plant assets (b)(c)	$	3,181	$	4,560	$	7,345	$	4,560
Pipeline assets (c)	$	4,627	$	—	$	41,775	$	—

__________________________________

(a) During the three and six months endedJune 30, 2012 and six months endedJune 30, 2011, the Partnership incurred impairment charges in its Upstream Business related to certain drilling locations in its unproved properties which the Partnership no longer intends to develop based on the performance of offsetting wells (see Note 11).

(b) During the three and six months endedJune 30, 2011, the Partnership recorded an impairment charge in its Texas Panhandle Segment to fully write-down its idle Turkey Creek plant.

(c) During the six months endedJune 30, 2012, the Partnership incurred impairment charges in its Midstream Business related to certain plants and pipelines in its East Texas and Other Midstream Segment due to (i) reduced throughput volumes as its producer customers curtailed their drilling activities due to the continued decline in natural gas prices during the first three months of 2012 and (ii) the termination of two significant gathering contracts on our Panola system during the three months ended June 30, 2012 (see Note 11).

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NOTE 5. ASSET RETIREMENT OBLIGATIONS

The Partnership recognizes asset retirement obligations 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 makes estimates of property abandonment costs that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to significant revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors that may be difficult to predict. 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. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of (i) remediation costs, (ii) remaining lives, (iii) future inflation factors and (iv) a credit-adjusted risk free interest rate.

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

	2012			2011
	($ in thousands)
Asset retirement obligations—December 31	$	33,303		$	24,711
Additional liabilities	1,119			54
Liabilities settled	(1,588		)	(148		)
Additional liability related to acquisitions	—			7,528
Accretion expense	1,128			828
Asset retirement obligations—June 30	$	33,962		$	32,973

NOTE 6. 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 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.  Intangible assets consist of the following: 

	June 30, 2012			December 31, 2011
	($ in thousands)
Rights-of-way and easements—at cost	$	97,604		$	99,143
Less: accumulated amortization	(28,274		)	(25,570		)
Contracts	108,083			121,387
Less: accumulated amortization	(88,457		)	(85,258		)
Net intangible assets	$	88,956		$	109,702

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The following table sets forth amortization and impairment expense by type of intangible asset within the Partnership's unaudited condensed consolidated statements of operations:

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	($ In thousands)
Amortization	$	2,931	$	2,934	$	5,920	$	5,865
Impairment expense:
Rights-of-way (a)	$	561	$	—	$	3,715	$	—
Contracts (a)	$	12,248	$	—	$	13,304	$	—

_____________________________________

(a) During the three and six months endedJune 30, 2012, the Partnership incurred impairment charges in its Midstream Business related to certain rights-of-way and contracts in its East Texas and Other Midstream Segment due to (i) reduced throughput volumes as its producer customers curtailed their drilling activities due to the continued decline in natural gas prices during the first three months of 2012 and (ii) the termination of two significant gathering contracts on our Panola system during the three months ended June 30, 2012 (see Note 11).

Estimated future amortization expense related to the intangible assets at June 30, 2012, is as follows (in thousands):

Year ending December 31,
2012	$	5,357
2013	$	8,922
2014	$	6,195
2015	$	6,195
2016	$	6,195
Thereafter	$	56,092

NOTE 7. LONG-TERM DEBT

Long-term debt consisted of the following:

	June 30, 2012			December 31, 2011
	($ in thousands)
Revolving credit facility:	$	587,900		$	481,500
Senior notes:
8 3/8% senior notes due 2019	300,000			300,000
Unamortized bond discount senior notes due 2019	(1,946		)	(2,047		)
Total senior notes	298,054			297,953
Total long-term debt	$	885,954		$	779,453

The Partnership currently pays an annual fee on the unused commitment, which was 0.50%. As of June 30, 2012, the Partnership had approximately $77.6 million of availability under its revolving credit facility.

As of June 30, 2012, the Partnership was in compliance with the financial covenants under the revolving credit facility.

NOTE 8. MEMBERS’ EQUITY

At June 30, 2012 and December 31, 2011, there were 133,019,853 and 127,606,229 common units outstanding, respectively. In addition, there were 3,585,918 and 2,560,110 unvested restricted common units outstanding at June 30, 2012 and December 31, 2011, respectively.

During the six months endedJune 30, 2012 and 2011, 5,300,588 and 7,649,544 warrants were exercised, respectively, for an equivalent number of newly issued common units. The final exercise date for the warrants was May 15,

11

2012, and on that date the remaining unexercised warrants expired. As of December 31, 2011, 5,707,705 warrants were outstanding.

During the three months ended June 30, 2012, the Partnership announced a program through which it may issue common units, from time to time, with an aggregate market value of up to $100 million. The Partnership is under no obligation to issue equity under the program. As of June 30, 2012, no units had been issued under this program.

The Partnership has declared a cash distribution for each quarter since its initial public offering. The table below summarizes the distributions paid and declared for the six months endedJune 30, 2012. 

Quarter Ended	Distribution per Unit		Record Date	Payment Date
December 31, 2011	$	0.2100	February 7, 2012	February 14, 2012
March 31, 2012+	$	0.2200	May 8, 2012	May 15, 2012
June 30, 2012	$	0.2200	August 7, 2012	August 14, 2012

_____________________________

+ The distribution excludes certain restricted unit grants.

NOTE 9. RELATED PARTY TRANSACTIONS

The following table summarizes transactions between the Partnership and affiliated entities:

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Affiliates of NGP:	($ in thousands)
Natural gas purchases from affiliates	$	734	$	1,642	$	1,675	$	3,192

	June 30, 2012	December 31, 2011
Affiliates of NGP:	($ in thousands)
Payable	219	371

NOTE 10. RISK MANAGEMENT ACTIVITIES

Interest Rate Swap Derivative Instruments

To mitigate its interest rate risk, the Partnership has entered into various interest rate swaps. These swaps convert the variable-rate term loan into a fixed-rate obligation. The purpose of entering into 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.

The following table sets forth certain information regarding the Partnership's various interest rate swaps as of June 30, 2012:

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	2.950	%

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

During July 2012, in conjunction with the Partnership's issuance of $250.0 million of senior unsecured notes (see Note 20), which increased its fixed interest rate exposure, the Partnership terminated the full $200.0 million notional amount of its

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existing 4.295% and 4.095% fixed rate interest rate swaps at a cost of $3.9 million.

Commodity Derivative Instruments

The prices of crude oil, natural gas and NGLs are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors which are beyond the Partnership's control.  These risks can cause significant changes in the Partnership's cash flows and affect its ability to achieve its distribution 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 forecasted equity production, the Partnership engages in 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 not 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 the covenants under 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 "proxy" 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 proxy hedging, it converts 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.

For accounting purposes, the Partnership has not designated any of its commodity derivative instruments as hedges; instead it marks these derivative contracts to fair value (see Note 11).  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, 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. Through this financial derivative activity, the Partnership 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, BBVA Compass Bank, Royal Bank of Canada and CITIBANK, N.A.

13

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 June 30, 2012, that will mature during the years ended December 31, 2012, 2013, 2014 and 2015:

Underlying	Type	Notional Volumes (units) (a)	Floor Strike Price ($/unit)(b)		Cap Strike Price ($/unit)(b)
Portion of Contracts Maturing in 2012
Natural Gas	Costless Collar	1,380,000	$	5.53	$	6.72
Natural Gas	Swap (Pay Floating/Receive Fixed)	6,300,000	5.76
Crude Oil	Costless Collar	403,788	77.13		96.92
Crude Oil	Swap (Pay Floating/Receive Fixed)	457,434	83.08
Propane	Swap (Pay Floating/Receive Fixed)	15,724,800	1.38
IsoButane	Swap (Pay Floating/Receive Fixed)	3,981,600	1.80
Normal Butane	Swap (Pay Floating/Receive Fixed)	7,056,000	1.73
Natural Gasoline	Swap (Pay Floating/Receive Fixed)	2,570,400	2.22
Portion of Contracts Maturing in 2013
Natural Gas	Costless Collar	3,540,000	4.84		5.47
Natural Gas	Swap (Pay Floating/Receive Fixed)	8,570,000	5.38
Crude Oil	Costless Collar	99,000	74.85		104.57
Crude Oil	Swap (Pay Floating/Receive Fixed)	1,930,200	96.82
Propane	Swap (Pay Floating/Receive Fixed)	25,200,000	1.23
IsoButane	Swap (Pay Floating/Receive Fixed)	3,578,400	1.91
Normal Butane	Swap (Pay Floating/Receive Fixed)	4,384,800	1.82
Portion of Contracts Maturing in 2014
Natural Gas	Swap (Pay Floating/Receive Fixed)	6,600,000	4.94
Crude Oil	Costless Collar	240,000	90.00		106.00
Crude Oil	Swap (Pay Floating/Receive Fixed)	1,680,000	97.69
Portion of Contracts Maturing in 2015
Natural Gas	Swap (Pay Floating/Receive Fixed)	3,600,000	3.92
Crude Oil	Costless Collar	480,000	90.00		97.55

_______________________

(a) Volumes of natural gas are measured in MMbtu, volumes of crude oil are measured in barrels, and volumes of natural gas liquids are measured in gallons.

(b) Amounts represent the weighted average price. The weighted average prices are in $/MMbtu for natural gas, $/barrel for crude oil and $/gallon for natural gas liquids.

During July 2012, the Partnership enhanced its commodity derivative portfolio by paying $2.8 million to adjust the strike price from $68.30 to $92.00 (the forward market price at the date of the transaction) per barrel on an existing WTI crude oil swap of 20,000 barrels per month for the six months ended December 31, 2012.

Commodity Derivative Instruments - Marketing & Trading

The Partnership conducts natural gas marketing and trading activities. The Partnership engages in activities intended to capitalize on favorable price differentials between various receipt and delivery locations. The Partnership's activities are governed by its risk policy.

As part of its natural gas marketing and trading activities, the Partnership enters into both financial derivatives and physical contracts. These 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.

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A commodity-related derivative contract may be designated as a "normal" purchase or sale if the commodity is to be physically received or delivered for use or sale in the normal course of business. If designated as "normal," the derivative contract is accounted for under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of the contract until settlement. Commodity-related contracts that do not qualify for the normal designation are accounted for as derivatives and are marked-to-market each period.

Marketing and Trading commodity derivative instruments, as of June 30, 2012, that will mature during the years ended December 31, 2012 and 2013:

Type	Notional Volumes (MMbtu)
Portion of Contracts Maturing in 2012
Basis Swaps - Purchases	6,320,000
Basis Swaps - Sales	6,010,000
Index Swap - Purchases	620,000
Index Swap - Sales	4,537,500
Swap (Pay Fixed/Receive Floating) - Purchases	775,000
Swap (Pay Floating/Received Fixed) - Sales	1,240,000
Forward purchase contract - index	8,056,750
Forward sales contract - index	15,726,373
Forward purchase contract - fixed price	761,608
Forward sales contract - fixed price	775,000
Portion of Contracts Maturing in 2013
Forward purchase contract - index	1,800,000

Changes in the fair value of these financial and physical contracts are recorded as adjustments to natural gas sales.

15

Fair Value of Interest Rate and Commodity Derivatives

Fair values of interest rate and commodity derivative instruments not designated as hedging instruments in the unaudited condensed consolidated balance sheet as of June 30, 2012 and December 31, 2011:

	As of June 30, 2012
	Derivative Assets				Derivative Liabilities
	Balance Sheet Classification	Fair Value			Balance Sheet Classification	Fair Value
	($ in thousands)
Interest rate derivatives - liabilities	Current assets	$	(5,334	)	Current liabilities	$	(3,954	)
Interest rate derivatives - liabilities	Long-term assets	(8,832		)	Long-term liabilities	(2,086		)
Commodity derivatives - assets	Current assets	62,864			Current liabilities	114
Commodity derivatives - assets	Long-term assets	49,641			Long-term liabilities	—
Commodity derivatives - liabilities	Current assets	(3,239		)	Current liabilities	—
Commodity derivatives - liabilities	Long-term assets	(1,024		)	Long-term liabilities	—
Total derivatives		$	94,076			$	(5,926	)
	As of December 31, 2011
	Derivative Assets				Derivative Liabilities
	Balance Sheet Classification	Fair Value			Balance Sheet Classification	Fair Value
	($ in thousands)
Interest rate derivatives - liabilities	Current assets	$	—		Current liabilities	$	(12,678	)
Interest rate derivatives - liabilities	Long-term assets	—			Long-term liabilities	(11,331		)
Commodity derivatives - assets	Current assets	24,240			Current liabilities	15,357
Commodity derivatives - assets	Long-term assets	26,611			Long-term liabilities	5,217
Commodity derivatives - liabilities	Current assets	(11,160		)	Current liabilities	(14,328		)
Commodity derivatives - liabilities	Long-term assets	(2,321		)	Long-term liabilities	(779		)
Total derivatives		$	37,370			$	(18,542	)

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:

Amount of Gain (Loss) Recognized in Income on Derivatives		Three Months Ended June 30,						Six Months Ended June 30,
		2012			2011			2012			2011
		($ in thousands)
Interest rate derivatives	Interest rate risk management losses	$	(1,463	)	$	(1,643	)	$	(3,042	)	$	(4,305	)
Commodity derivatives	Commodity risk management gains (losses)	95,965			34,338			87,357			(26,107		)
Commodity derivatives - trading	Natural gas, natural gas liquids, oil, condensate and sulfur sales	(707		)	—			(70		)	—
	Total	$	93,795		$	32,695		$	84,245		$	(30,412	)

NOTE 11. FAIR VALUE OF FINANCIAL INSTRUMENTS

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).

16

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.

As of June 30, 2012, the Partnership has recorded its interest rate swaps and commodity derivative instruments (see Note 10), 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 the Partnership's contracts and has classified these inputs as Level 2.

The following tables disclose the fair value of the Partnership's derivative instruments as of June 30, 2012 and December 31, 2011: 

	As of June 30, 2012
	Level 1		Level 2			Level 3		Netting (a)			Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	34,188		$	—	$	(3,312	)	$	30,876
Natural gas derivatives	—		50,504			—		(1,065		)	49,439
NGL derivatives	—		27,927			—		—			27,927
Interest rate swaps	—		—			—		(14,166		)	(14,166		)
Total	$	—	$	112,619		$	—	$	(18,543	)	$	94,076
Liabilities:
Crude oil derivatives	$	—	$	(3,198	)	$	—	$	3,312		$	114
Natural gas derivatives	—		(1,065		)	—		1,065			—
NGL derivatives	—		—			—		—			—
Interest rate swaps	—		(20,206		)	—		14,166			(6,040		)
Total	$	—	$	(24,469	)	$	—	$	18,543		$	(5,926	)

____________________________

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

17

	As of December 31, 2011
	Level 1		Level 2			Level 3		Netting (a)			Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	11,795		$	—	$	(14,150	)	$	(2,355	)
Natural gas derivatives	—		58,374			—		(17,930		)	40,444
NGL derivatives	—		1,256			—		(1,975		)	(719		)
Total	$	—	$	71,425		$	—	$	(34,055	)	$	37,370
Liabilities:
Crude oil derivatives	$	—	$	(24,051	)	$	—	$	14,150		$	(9,901	)
Natural gas derivatives	—		(1,290		)	—		17,930			16,640
NGL derivatives	—		(3,247		)	—		1,975			(1,272		)
Interest rate swaps	—		(24,009		)	—		—			(24,009		)
Total	$	—	$	(52,597	)	$	—	$	34,055		$	(18,542	)

____________________________

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

The following table sets forth a reconciliation of changes in the fair value of the Level 3 NGL derivatives during the three and six months endedJune 30, 2012 and 2011:

	Three Months Ended June 30,					Six Months Ended June 30,
	2012		2011			2012		2011
	($ in thousands)
Net liability beginning balance	$	—	$	(12,264	)	$	—	$	(5,733	)
Settlements	—		5,669			—		9,406
Total gains or losses (realized and unrealized)	—		(3,037		)	—		(13,305		)
Net liability ending balance	$	���	$	(9,632	)	$	—	$	(9,632	)

The Partnership valued 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 no gains (losses) in the three and six months endedJune 30, 2012 related to Level 3 assets and liabilities. The Partnership recognized losses of $1.6 million and $7.5 million in the three and six months endedJune 30, 2011, respectively, that are attributable to the change in unrealized gains or losses related to those Level 3 assets and liabilities still held at June 30, 2011, 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. 

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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 during the six months ended June 30, 2012:

	June 30, 2012		Level 1		Level 2		Level 3		Total Losses
	($ in thousands)
Plant assets	$	634	$	—	$	—	$	634	$	7,345
Pipeline assets	$	1,884	$	—	$	—	$	1,884	$	41,775
Rights-of-way	$	263	$	—	$	—	$	263	$	3,715
Contracts	$	2,156	$	—	$	—	$	2,156	$	13,304

The Partnership calculated the fair value of the impaired assets using a discounted cash flow analysis to determine the excess of the asset's carrying value over its fair value. Significant inputs to the valuation of fair value of the proved properties included estimates of (i) future estimated cash flows, including revenue, expenses and capital expenditures, (ii) estimated timing of cash flows, (iii) estimated forward commodity prices, adjusted for estimate location differentials and (iv) a discount rate reflective of our cost of capital. For other assets impaired by the Partnership during the six month ended June 30, 2012, the assets were fully written down and thus are not included in the table above. See Notes 4 and 6 for a further discussion of the impairment charges.

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 June 30, 2012, the outstanding debt associated with the Partnership's revolving credit facility bore interest at a floating rate; as such, the Partnership believes that the carrying value of this debt approximates its fair value. The Partnership's 8.375% Senior Notes due 2019 (the "Senior Notes") bear interest at a fixed rate; based on the market price of the Senior Notes as of June 30, 2012, the Partnership estimates that the fair value of the Senior Notes was $298.5 million compared to a carrying value of $298.1 million. Fair value of the senior notes was estimated based on prices quoted from third-party financial institutions, which are characteristic of Level 2 fair value measurement inputs.

NOTE 12. COMMITMENTS AND CONTINGENCIES

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 June 30, 2012 and December 31, 2011 related to legal matters, and 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 the Partnership's 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

19

fluctuate over the past year, reflecting the changing conditions in the insurance markets. 

Environmental—The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, the Partnership must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership's combined results of operations, financial position or cash flows. At June 30, 2012 and December 31, 2011, the Partnership had accrued approximately $3.1 million and $3.2 million, respectively, for environmental matters.

In July 2012, the Alabama Department of Environmental Management (“ADEM”) notified one of the Partnership's subsidiaries that ADEM had made a determination that alleged violations warrant enforcement action and determined that the alleged violations are appropriate for resolution by Consent Order and proposed the terms of a to-be-mutually agreed-upon Consent Order (“Proposed Consent Order”).  Such notification and the Proposed Consent Order are the result of findings made by ADEM relating to the Partnership's subsidiary's Flomaton/Fanny Church Oil and Gas Production and Treating Facility. The Proposed Consent Order primarily relates to allegations of emissions in excess of those allowed by the production rate.  Prior to receiving the Proposed Consent Order, the Partnership self-reported its emission rates and worked with ADEM to complete a series of quality improvement plans to address the causes of the alleged violations. The fine amount proposed by ADEM in the Proposed Consent Order is $100,000, which may be negotiated to a lesser amount at the discretion of ADEM.

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 2011 and does not anticipate doing so in 2012. 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 $2.0 million and $4.4 million for the three and six months endedJune 30, 2012 and 2011, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term.

NOTE 13. SEGMENTS

During the fourth quarter of 2011, the Partnership's chief executive officer (who is it's chief operating decision-maker "CODM") decided that due to the relative size of the East Texas/Louisiana, South Texas and Gulf of Mexico segments, these three reporting segments would be collapsed into a single reporting segment and that a new Marketing and Trading reporting segment would be created.  The Partnership's Marketing and Trading results were previously presented within its Texas Panhandle Segment.  The Partnership now conducts, evaluates and reports on its Midstream Business within three distinct segments—the Texas Panhandle Segment, the East Texas and Other Midstream Segment, which consolidates its former East Texas/Louisiana, South Texas and Gulf of Mexico Segments, and the Marketing and Trading Segment. The Partnership's Upstream Segment and functional (Corporate and Other) segment remain unchanged from what has been previously reported.

Based on the Partnership’s approach to managing its assets, the Partnership believes its operations consist of three segments in its Midstream Business, one Upstream Segment and one Corporate segment:

(i)Midstream—Texas Panhandle Segment:

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gathering, compressing, treating, processing and transporting natural gas; fractionating, transporting and marketing NGLs;

(ii)    Midstream—East Texas and Other Midstream Segment:

gathering, compressing, processing and treating natural gas and marketing of natural gas, NGLs and condensate in South Texas, East Texas, Louisiana, Gulf of Mexico and inland waters of Texas;

(iii)    Midstream—Marketing and Trading Segment:

crude oil logistics and marketing in the Texas Panhandle and Alabama; and natural gas marketing and trading;

(iv)    Upstream Segment:

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

(v)    Corporate and Other Segment:

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

The Partnership's 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:

Three Months Ended June 30, 2012	Texas Panhandle Segment			East Texas and Other Midstream Segment			Marketing and Trading Segment			Total Midstream Business			Upstream Segment		Corporate and Other Segment				Total Segments
($ in thousands)
Sales to external customers	$	62,653	(c)	$	37,597		$	53,389		$	153,639		$	32,800	$	95,965		(a)	$	282,404
Intersegment sales	19,043			6,928			(28,084		)	(2,113		)	12,419		(10,306		)		—
Cost of natural gas and natural gas liquids	51,117			32,550			14,247			97,914			—		—				97,914
Intersegment cost of natural gas, oil and condensate	—			—			10,383			10,383			—		(10,383		)		—
Operating costs and other expenses	12,399			5,764			1			18,164			14,018		18,736				50,918
Depreciation, depletion and amortization	9,873			6,667			25			16,565			21,366		423				38,354
Impairment	—			20,617			—			20,617			785		—				21,402
Operating income (loss) from continuing operations	$	8,307		$	(21,073	)	$	649		$	(12,117	)	$	9,050	$	76,883			$	73,816
Capital Expenditures	$	44,885		$	2,967		$	89		$	47,941		$	45,541	$	612			$	94,094

Three Months Ended June 30, 2011	Texas Panhandle Segment		East Texas and Other Midstream Segment		Marketing and Trading Segment		Total Midstream Business		Upstream Segment		Corporate and Other Segment				Total Segments
($ in thousands)
Sales to external customers	$	121,994	$	77,753	$	38,306	$	238,053	$	39,324	$	34,338		(a)	$	311,715
Intersegment sales	—		—		—		—		13,021		(13,021		)		—
Cost of natural gas and natural gas liquids	87,761		61,186		23,727		172,674		—		—				172,674
Intersegment cost of natural gas, oil and condensate	—		—		13,903		13,903		—		(13,903		)		—
Operating costs and other expenses	11,207		5,373		—		16,580		10,560		13,009				40,149
Intersegment operations and maintenance	—		—		—		—		24		(24		)		—
Depreciation, depletion and amortization	9,116		6,960		—		16,076		15,180		320				31,576
Impairment	4,560		—		—		4,560		—		—				4,560
Operating income from continuing operations	$	9,350	$	4,234	$	676	$	14,260	$	26,581	$	21,915			$	62,756
Capital Expenditures	$	7,816	$	1,470	$	288	$	9,574	$	19,158	$	440			$	29,172

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Six Months Ended June 30, 2012	Texas Panhandle Segment			East Texas and Other Midstream Segment			Marketing and Trading Segment			Total Midstream Business			Upstream Segment		Corporate and Other Segment				Total Segments
($ in thousands)
Sales to external customers	$	140,683	(c)	$	85,428		$	119,971		$	346,082		$	74,720	$	87,357		(a)	$	508,159
Intersegment sales	44,489			16,451			(65,903		)	(4,963		)	27,758		(22,795		)		—
Cost of natural gas and natural gas liquids	122,605			78,058			27,705			228,368			—		—				228,368
Intersegment cost of natural gas, oil and condensate	—			—			24,014			24,014			—		(24,014		)		—
Operating costs and other expenses	24,637			10,893			1			35,531			28,850		35,577				99,958
Depreciation, depletion and amortization	19,390			13,802			55			33,247			43,586		815				77,648
Impairment	—			66,139			—			66,139			785		—				66,924
Operating income (loss) from continuing operations	$	18,540		$	(67,013	)	$	2,293		$	(46,180	)	$	29,257	$	52,184			$	35,261
Capital Expenditures	$	78,287		$	5,652		$	231		$	84,170		$	72,769	$	1,329			$	158,268
Segment Assets	$	615,142		$	324,037		$	31,276		$	970,455		$	1,008,459	$	119,617		(b)	$	2,098,531

Six Months Ended June 30, 2011	Texas Panhandle Segment		East Texas and Other Midstream Segment		Marketing and Trading Segment		Total Midstream Business		Upstream Segment			Corporate and Other Segment				Total Segments
($ in thousands)
Sales to external customers	$	222,406	$	151,731	$	62,758	$	436,895	$	58,291	(d)	$	(26,107	)	(a)	$	469,079
Intersegment sales	—		—		—		—		22,524			(22,524		)		—
Cost of natural gas and natural gas liquids	159,715		119,666		40,612		319,993		—			—				319,993
Intersegment cost of natural gas, oil and condensate	—		—		20,992		20,992		—			(20,992		)		—
Operating costs and other expenses	20,608		10,757		—		31,365		18,566			24,785				74,716
Intersegment operations and maintenance	—		—		—		—		66			(66		)		—
Depreciation, depletion and amortization	18,237		13,920		—		32,157		22,410			707				55,274
Impairment	4,560		—		—		4,560		324			—				4,884
Operating income (loss) from continuing operations	$	19,286	$	7,388	$	1,154	$	27,828	$	39,449		$	(53,065	)		$	14,212
Capital Expenditures	$	15,206	$	2,498	$	288	$	17,992	$	24,820		$	531			$	43,343
Segment Assets	$	563,346	$	383,465	$	6,121	$	952,932	$	973,316		$	27,188		(b)	$	1,953,436

______________________________

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

(b) Includes elimination of intersegment transactions.

(c) Sales to external customers in the Texas Panhandle Segment for the three and six months endedJune 30, 2012, includes $2.9 million of business interruption insurance recovery related to damage sustained by the Partnership's Cargray processing facility due to severe winter weather in 2011, which is recognized as part of Other Revenue in the unaudited condensed consolidated statements of operations.

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

NOTE 14. INCOME TAXES

Provision for Income Taxes -The Partnership's provision for income taxes relates to (i) state taxes for the Partnership and (ii) federal taxes for Eagle Rock Energy Acquisition Co., Inc. and Eagle Rock Energy Acquisition Co. II, Inc. and their wholly-owned subsidiary corporations, Eagle Rock Upstream Development Company, Inc. and Eagle Rock Upstream Development Company II, Inc., which are subject to federal income taxes (collectively, the "C Corporations").

Effective Rate - The effective rate for the six months endedJune 30, 2012 was (1.5)% compared to (342.5)% for the six months endedJune 30, 2011. 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 six months endedJune 30, 2012 as compared to the six months endedJune 30, 2011.

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NOTE 15. 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, of which, as of June 30, 2012, a total of 1,704,897 common units remained available for issuance. Grants of common units under the LTIP are made at the discretion of the board. 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 awards generally vest over three years on the basis of one third of the award each year. The Partnership recognizes compensation expense on a straight-line basis over the requisite service period for the restricted unit grants. During the restriction period, distributions associated with the granted awards will be distributed to the awardees.

A summary of the restricted common units’ activity for the six months endedJune 30, 2012 is provided below:

	Number of Restricted Units		Weighted Average Fair Value
Outstanding at December 31, 2011	2,560,110		$	9.35
Granted	1,234,955		$	9.49
Vested	(145,562	)	$	8.54
Forfeited	(63,585	)	$	8.99
Outstanding at June 30, 2012	3,585,918		$	8.98

For the three and six months endedJune 30, 2012 and 2011, non-cash compensation expense of approximately $2.8 million, $5.0 million, $1.0 million and $1.9 million, respectively, was recorded related to the granted restricted units as general and administrative expense on the unaudited condensed consolidated statements of operations.

As of June 30, 2012, unrecognized compensation costs related to the outstanding restricted units under the LTIP totaled approximately $24.7 million. The remaining expense is to be recognized over a weighted average of 2.37 years.

In connection with the vesting of certain restricted units during the three months endedJune 30, 2012, the Partnership cancelled 32,526 of the newly-vested common units in satisfaction of $0.3 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 16. 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 and restricted common units), 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 June 30, 2012 and 2011, 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 units 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 units outstanding.

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

	Three Months Ended June 30,		Six Months Ended June 30,
	2012	2011	2012	2011
	(in thousands)
Weighted average units outstanding during period:
Common units - Basic	131,905	108,117	130,034	96,130
Effect of Dilutive Securities:
Warrants	366	6,795	960	6,927
Restricted Units	1,168	985	1,107	893
Common units - Diluted	133,439	115,897	132,101	103,950

The restricted common units granted under the LTIP, as discussed in Note 15, contain non-forfeitable rights to the distributions declared by the Partnership and therefore meet the definition of participating securities. Participating securities are required to be included in the computation of earnings per unit pursuant to the two-class method. For the three and six months endedJune 30, 2012 and 2011, 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 and diluted income per unit for the three months endedJune 30, 2012:

	Total		Common Units		Restricted Common Units
	($ in thousands, except for per unit amounts)
Net income	61,789
Distributions	30,053		$	29,264	$	789
Assumed net income after distribution to be allocated	31,736		30,949		787
Assumed net income to be allocated	$	61,789	$	60,213	$	1,576
Basic and diluted income per unit			$	0.46

The following table presents the Partnership's basic and diluted income per unit for the six months endedJune 30, 2012:

	Total			Common Units			Restricted Common Units
	($ in thousands, except for per unit amounts)
Net income	11,456
Distributions	59,424			$	58,033		$	1,391
Assumed net loss after distribution to be allocated	(47,968		)	(47,968		)	—
Assumed net income to be allocated	$	11,456		$	10,065		$	1,391
Basic and diluted income per unit				$	0.08

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

	Total			Common Units			Restricted Common Units
	($ in thousands, except for per unit amounts)
Net income from continuing operations	$	55,382
Distributions	20,549			$	20,272		$	277
Assumed net income from continuing operations after distribution to be allocated	34,833			34,266			567
Assumed allocation of net income from continuing operations	55,382			54,538			844
Discontinued operations, net of tax	(311		)	(311		)	—
Assumed net income to be allocated	$	55,071		$	54,227		$	844
Basic income from continuing operations per unit				$	0.50
Basic discontinued operations per unit				$	—
Basic income per unit				$	0.50

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

	Total			Common Units			Restricted Common Units
	($ in thousands, except for per unit amounts)
Net income from continuing operations	$	55,382
Distributions	21,823			$	21,546		$	277
Assumed net income from continuing operations after distribution to be allocated	33,559			33,025			534
Assumed allocation of net income from continuing operations	55,382			54,571			811
Discontinued operations, net of tax	(311		)	(311		)	—
Assumed net income to be allocated	$	55,071		$	54,260		$	811
Diluted income from continuing operations per unit				$	0.47
Diluted discontinued operations per unit				$	—
Diluted income per unit				$	0.47

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The following table presents the Partnership's basic and diluted income per unit for the six months endedJune 30, 2011:

	Total			Common Units			Restricted Common Units
	($ in thousands, except for per unit amounts)
Net income from continuing operations	$	947
Distributions	31,151			$	30,660		$	491
Assumed net loss from continuing operations after distribution to be allocated	(30,204		)	(30,204		)	—
Assumed allocation of net income from continuing operations	947			456			491
Discontinued operations, net of tax	407			407			—
Assumed net income to be allocated	$	1,354		$	863		$	491
Basic and diluted income from continuing operations per unit				$	—
Basic and diluted discontinued operations per unit				$	—
Basic and diluted income per unit				$	0.01

NOTE 17.   DISCONTINUED OPERATIONS

The following table represents activity from discontinued operations for the three and six months endedJune 30, 2011:

	Wildhorse System (a)			Minerals Business (b)
($ in thousands)
Three Months Ended June 30, 2011:
Revenues	$	1,812		$	—
Income from Operations	$	138		$	—
Discontinued operations, net of tax	$	(449	)	$	138
Loss from the sale	$	(587	)
Proceeds from sale	$	5,712
Six Months Ended June 30, 2011:
Revenues	$	6,890		$	—
Income from Operations	$	579		$	—
Discontinued operations, net of tax	$	(18	)	$	425

_____________________________

(a) On May 20, 2011, the Partnership sold its Wildhorse Gathering System (which was accounted for in its East Texas and Other Midstream Segment).

(b) On May 24, 2010, the Partnership completed the sale of its Minerals Business. During the three and six months endedJune 30, 2011, the Partnership received payments related to pre-effective date operations and recorded this amount as part of discontinued operations for the period.

NOTE 18. 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 could no longer be triggered. Due to the expiration of the repurchase obligations during the year ended December 31, 2011, the Partnership released its reserve for these receivables and recorded other operating income of $2.9 million related to these reserves.

NOTE 19. SUBSIDIARY GUARANTORS

As of June 30, 2012, the Partnership had issued registered debt securities guaranteed by its subsidiaries.  As of June 30, 2012, all guarantors are wholly-owned or available to be pledged and such guarantees are joint and several and full

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and unconditional.  In accordance with Rule 3-10 of SEC Regulation S-X, the Partnership has prepared Unaudited Condensed Consolidating Financial Statements as supplemental information.  The following unaudited condensed consolidating balance sheets at June 30, 2012 and December 31, 2011, unaudited condensed consolidating statements of operations for the three and six months endedJune 30, 2012 and 2011, and unaudited condensed consolidating statements of cash flows for the six months endedJune 30, 2012 and 2011, 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

June 30, 2012

	Parent Issuer		Co-Issuer		Subsidiary Guarantors		Non-Guarantor Investments		Consolidating Entries			Total
	($ in thousands)
ASSETS:
Accounts receivable – related parties	$	601,253	$	—	$	—	$	—	$	(601,253	)	$	—
Other current assets	51,640		1		99,313		—		—			150,954
Total property, plant and equipment, net	1,613		—		1,798,567		—		—			1,800,180
Investment in subsidiaries	1,207,386		—		—		997		(1,208,383		)	—
Total other long-term assets	40,824		—		106,573		—		—			147,397
Total assets	$	1,902,716	$	1	$	2,004,453	$	997	$	(1,809,636	)	$	2,098,531
LIABILITIES AND EQUITY:
Accounts payable – related parties	$	—	$	—	$	601,253	$	—	$	(601,253	)	$	—
Other current liabilities	8,551		—		122,633		—		—			131,184
Other long-term liabilities	9,595		—		73,182		—		—			82,777
Long-term debt	885,954		—		—		—		—			885,954
Equity	998,616		1		1,207,385		997		(1,208,383		)	998,616
Total liabilities and equity	$	1,902,716	$	1	$	2,004,453	$	997	$	(1,809,636	)	$	2,098,531

Unaudited Condensed Consolidating Balance Sheet

December 31, 2011

	Parent Issuer		Co-Issuer		Subsidiary Guarantors		Non-Guarantor Investments		Consolidating Entries			Total
	($ in thousands)
ASSETS:
Accounts receivable – related parties	$	541,384	$	—	$	—	$	—	$	(541,384	)	$	—
Other current assets	15,749		1		109,778		—		—			125,528
Total property, plant and equipment, net	1,393		—		1,762,281		—		—			1,763,674
Investment in subsidiaries	1,229,606		—		—		1,033		(1,230,639		)	—
Total other long-term assets	30,928		—		125,558		—		—			156,486
Total assets	$	1,819,060	$	1	$	1,997,617	$	1,033	$	(1,772,023	)	$	2,045,688
LIABILITIES AND EQUITY:
Accounts payable – related parties	$	—	$	—	$	541,384	$	—	$	(541,384	)	$	—
Other current liabilities	18,110		—		152,745		—		—			170,855
Other long-term liabilities	14,150		—		73,883		—		—			88,033
Long-term debt	779,453		—		—		—		—			779,453
Equity	1,007,347		1		1,229,605		1,033		(1,230,639		)	1,007,347
Total liabilities and equity	$	1,819,060	$	1	$	1,997,617	$	1,033	$	(1,772,023	)	$	2,045,688

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Unaudited Condensed Consolidating Statement of Operations

For the Three Months Ended June 30, 2012

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	70,771		$	—	$	211,633		$	—					$	282,404
Cost of natural gas and natural gas liquids	—			—		97,914			—			—			97,914
Operations and maintenance	—			—		27,562			—			—			27,562
Taxes other than income	—			—		4,620			—			—			4,620
General and administrative	3,170			—		15,566			—			—			18,736
Depreciation, depletion and amortization	79			—		38,275			—			—			38,354
Impairment	—			—		21,402			—			—			21,402
Income from operations	67,522			—		6,294			—			—			73,816
Interest expense, net	(10,647		)	—		—			—			—			(10,647		)
Other non-operating income	2,238			—		2,744			—			(4,982		)	—
Other non-operating expense	(3,332		)	—		(3,108		)	(1		)	4,982			(1,459		)
Income (loss) before income taxes	55,781			—		5,930			(1		)	—			61,710
Income tax provision (benefit)	437			—		(516		)	—			—			(79		)
Equity in earnings of subsidiaries	6,445			—		—			—			(6,445		)	—
Net income (loss)	$	61,789		$	—	$	6,446		$	(1	)	$	(6,445	)	$	61,789

Unaudited Condensed Consolidating Statement of Operations

For the Three Months Ended June 30, 2011

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	33,627		$	—	$	278,088		$	—		$	—		$	311,715
Cost of natural gas and natural gas liquids	—			—		172,674			—			—			172,674
Operations and maintenance	—			—		21,951			—			—			21,951
Taxes other than income	—			—		5,189			—			—			5,189
General and administrative	723			—		15,179			—			—			15,902
Other operating income	—			—		(2,893		)	—			—			(2,893		)
Depreciation, depletion and amortization	40			—		31,536			—			—			31,576
Impairment	—			—		4,560			—			—			4,560
Income from operations	32,864			—		29,892			—			—			62,756
Interest expense, net	(6,303		)	—		(5		)	—			—			(6,308		)
Other non-operating income	2,160			—		1,113			—			(3,273		)	—
Other non-operating expense	(2,428		)	—		(2,596		)	(6		)	3,273			(1,757		)
Income (loss) before income taxes	26,293			—		28,404			(6		)	—			54,691
Income tax benefit	(224		)	—		(467		)	—			—			(691		)
Equity in earnings of subsidiaries	28,554			—		—			—			(28,554		)	—
Income (loss) from continuing operations	55,071			—		28,871			(6		)	(28,554		)	55,382
Discontinued operations, net of tax	—			—		(311		)	—			—			(311		)
Net income (loss)	$	55,071		$	—	$	28,560		$	(6	)	$	(28,554	)	$	55,071

28

Unaudited Condensed Consolidating Statement of Operations

For the Six Months Ended June 30, 2012

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	65,964		$	—	$	442,195		$	—		$	—		$	508,159
Cost of natural gas and natural gas liquids	—			—		228,368			—			—			228,368
Operations and maintenance	—			—		54,611			—			—			54,611
Taxes other than income	—			—		9,770			—			—			9,770
General and administrative	5,538			—		30,039			—			—			35,577
Depreciation, depletion and amortization	151			—		77,497			—			—			77,648
Impairment	—			—		66,924			—			—			66,924
Income (loss) from operations	60,275			—		(25,014		)	—			—			35,261
Interest expense, net	(20,888		)	—		—			—			—			(20,888		)
Other non-operating income	4,499			—		5,488			—			(9,987		)	—
Other non-operating expense	(6,781		)	—		(6,283		)	(10		)	9,987			(3,087		)
Income (loss) before income taxes	37,105			—		(25,809		)	(10		)	—			11,286
Income tax provision (benefit)	860			—		(1,030		)	—			—			(170		)
Equity in earnings of subsidiaries	(24,789		)	—		—			—			24,789			—
Net income (loss)	$	11,456		$	—	$	(24,779	)	$	(10	)	$	24,789		$	11,456

29

Unaudited Condensed Consolidating Statement of Operations

For the Six Months Ended June 30, 2011

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	(19,482	)	$	—	$	488,561		$	—		$	—		$	469,079
Cost of natural gas and natural gas liquids	—			—		319,993			—			—			319,993
Operations and maintenance	—			—		41,426			—			—			41,426
Taxes other than income	—			—		8,505			—			—			8,505
General and administrative	1,717			—		25,961			—			—			27,678
Other operating income	—			—		(2,893		)	—			—			(2,893		)
Depreciation, depletion and amortization	80			—		55,194			—			—			55,274
Impairment	—			—		4,884			—			—			4,884
(Loss) income from operations	(21,279		)	—		35,491			—			—			14,212
Interest expense, net	(9,521		)	—		(8		)	—			—			(9,529		)
Other non-operating income	4,280			—		2,218			—			(6,498		)	—
Other non-operating expense	(5,200		)	—		(5,756		)	(11		)	6,498			(4,469		)
(Loss) income before income taxes	(31,720		)	—		31,945			(11		)	—			214
Income tax provision (benefit)	196			—		(929		)	—			—			(733		)
Equity in earnings of subsidiaries	33,270			—		—			—			(33,270		)	—
Income (loss) from continuing operations	1,354			—		32,874			(11		)	(33,270		)	947
Discontinued operations, net of tax	—			—		407			—			—			407
Net income (loss)	$	1,354		$	—	$	33,281		$	(11	)	$	(33,270	)	$	1,354

30

Unaudited Condensed Consolidating Statement of Cash Flows

For the Six Months Ended June 30, 2012

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments		Consolidating Entries			Total
	($ in thousands)
Net cash flows (used in) provided by operating activities	$	(81,285	)	$	—	$	143,029		$	27	$	—		$	61,771
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(373		)	—		(149,650		)	—		—			(150,023		)
Purchase of intangible assets	—			—		(2,176		)	—		—			(2,176		)
Contribution to subsidiaries	(2,581		)	—		—			—		2,581			—
Net cash flows used in investing activities	(2,954		)	—		(151,826		)	—		2,581			(152,199		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	373,850			—		—			—		—			373,850
Repayment of long-term debt	(267,450		)	—		—			—		—			(267,450		)
Proceeds from derivative contracts	8,420			—		—			—		—			8,420
Exercise of warrants	31,804			—		—			—		—			31,804
Repurchase of common units	(292		)	—		—			—		—			(292		)
Distributions to members and affiliates	(56,711		)	—		—			—		—			(56,711		)
Contribution from parent	—			—		2,581			—		(2,581		)	—
Net cash flows provided by financing activities	89,621			—		2,581			—		(2,581		)	89,621
Net increase (decrease) in cash and cash equivalents	5,382			—		(6,216		)	27		—			(807		)
Cash and cash equivalents at beginning of year	1,319			1		(572		)	129		—			877
Cash and cash equivalents at end of year	$	6,701		$	1	$	(6,788	)	$	156	$	—		$	70

31

Unaudited Condensed Consolidating Statement of Cash Flows

For the Six Months Ended June 30, 2011

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments		Consolidating Entries			Total
	($ in thousands)
Net cash flows (used in) provided by operating activities	$	(1,215	)	$	—	$	26,851		$	57	$	—		$	25,693
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions, net of cash acquired	—			—		(220,326		)	—		—			(220,326		)
Additions to property, plant and equipment	—			—		(31,195		)	—		—			(31,195		)
Purchase of intangible assets	—			—		(1,315		)	—		—			(1,315		)
Proceeds from sale of asset	—			—		6,093			—		—			6,093
Contributions to subsidiaries	(227,583		)	—		—			—		227,583			—
Net cash flows used in investing activities	(227,583		)	—		(246,743		)	—		227,583			(246,743		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	709,329			—		—			—		—			709,329
Repayment of long-term debt	(791,329		)	—		—			—		—			(791,329		)
Proceed from senior notes	297,837			—		—								297,837
Payment of debt issuance cost	(13,802		)	—		—								(13,802		)
Repurchase of common units	(119		)	—		—			—		—			(119		)
Exercise of warrants	45,897			—		—			—		—			45,897
Proceeds from derivative contracts	2,443			—		—			—		—			2,443
Contributions from parent	—			—		227,583			—		(227,583		)	—
Distributions to members and affiliates	(26,250		)	—		—			—		—			(26,250		)
Net cash flows provided by financing activities	224,006			—		227,583			—		(227,583		)	224,006
Net cash flows used in discontinued operations	—			—		(180		)	—		—			(180		)
Net (decrease) increase in cash and cash equivalents	(4,792		)	—		7,511			57		—			2,776
Cash and cash equivalents at beginning of year	4,890			—		(884		)	43		—			4,049
Cash and cash equivalents at end of year	$	98		$	—	$	6,627		$	100	$	—		$	6,825

32

NOTE 20. SUBSEQUENT EVENTS

Successful Re-Start of Phoenix-Arrington Ranch Plant

On July 2, 2012, the Partnership announced the successful re-start of its Phoenix-Arrington Ranch Plant in Hemphill County, Texas. The plant had been shut down since April 30, 2012, due to an incident and resulting fire that caused damage to the inlet header system. The Partnership estimates the cost of the repairs to the facility to be approximately $2.4 million. The Partnership has property insurance and will pursue reimbursement for the repairs associated with the incident above the associated deductible of $500,000.

Senior Unsecured Notes

On July 10, 2012, the Partnership, along with its subsidiary, Eagle Rock Energy Finance Corp. ("Finance Corp"), as co-issuer, completed the sale of $250.0 million of senior unsecured notes (the "Senior Notes") through a private placement. The Senior Notes were issued under the same indenture of the Partnership's existing senior unsecured notes issued on May 27, 2011. The Senior Notes bear a coupon of 8.375% and will mature on June 1, 2019. Interest on the Senior Notes is payable on each June 1 and December 1, commencing December 1, 2012. After the original discount of $3.7 million and excluding related offering expenses, the Partnership received net proceeds of approximately $246.3 million, which were used to repay borrowings outstanding under the Partnership's revolving credit facility. The Senior Notes and the notes originally issued on May 27, 2011 will be treated as a single class of debt securities under the same indenture.

33

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 Securities and Exchange Commission (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 known material risks, please read our risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2011 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 (including sustained declines) in commodity prices;

• Our significant existing indebtedness;

• 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 transporting of natural gas liquids ("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;

• 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.

34

OVERVIEW

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, 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, 2011.

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 NGLs; and crude oil logistics and marketing; and

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

During the fourth quarter of 2011, we decided that due to the relative size of the East Texas/Louisiana, South Texas and Gulf of Mexico segments, these three reporting segments would be aggregated into a single reporting segment and that a new Marketing and Trading reporting segment would be created.  Our Marketing and Trading results were previously presented within our Texas Panhandle Segment.

We now conduct, evaluate and report on our Midstream Business within three segments—the Texas Panhandle Segment, the East Texas and Other Midstream Segment (which consolidates our former East Texas/Louisiana, South Texas and Gulf of Mexico Segments) and the Marketing and Trading Segment. Our Texas Panhandle Segment consists of gathering and processing assets in the Texas Panhandle. Our East Texas and Other Midstream Segment consists of gathering and processing assets in East Texas/Northern Louisiana, South Texas, Southern Louisiana, the Gulf of Mexico and Galveston Bay. Our Marketing and Trading Segment consists of crude oil logistics and marketing in the Texas Panhandle and Alabama and natural gas marketing and trading.  During the three and six months endedJune 30, 2012, our Midstream Business had an operating loss from continuing operations of $12.1 million and $46.2 million, respectively, compared to operating income from continuing operations of $14.3 million and $27.8 million generated during the three and six months endedJune 30, 2011, respectively.  

We conduct, evaluate and report on our Upstream Business as one segment. On May 3, 2011, we completed the acquisition of CC Energy II L.L.C. ("Crow Creek Energy"). Our Upstream Segment includes operated and non-operated wells located in the Mid-Continent (which includes areas in Oklahoma, Arkansas, the Texas Panhandle and North Texas); Permian (which includes areas in West Texas); East Texas / South Texas / Mississippi; and Southern Alabama (which also includes two treating facilities, and one natural gas processing plant and related gathering systems).  During the three and six months endedJune 30, 2012, our Upstream Business generated operating income of $9.1 million and $29.3 million, respectively, compared to operating income of $26.6 million and $39.4 million generated during the three and six months endedJune 30, 2011, respectively.  

Our final reporting segment is our Corporate and Other Segment, which is where we account for our risk management activity (excluding any risk management activity associated with our natural gas marketing and trading activities), intersegment eliminations and our general and administrative expenses.  During the three and six months endedJune 30, 2012, our Corporate and Other Segment generated operating income of $76.9 million and $52.2 million, respectively, compared to operating income (loss), of $21.9 million and $(53.1) million during the three and six months endedJune 30, 2011, respectively.  Results reflected a net gain, realized and unrealized, on our commodity derivatives of $96.0 million and $87.4 million during the three and six months endedJune 30, 2012, respectively, compared to a net gain (loss), realized and unrealized, on our commodity derivatives of $34.3 million and $(26.1) million during the three and six months endedJune 30, 2011, respectively.  See "Results of Operations - Corporate and Other Segment" for a further discussion of the impact of our commodity derivatives.

Impairment

During the three and six months endedJune 30, 2012, we recorded an impairment charge in our Midstream Business for certain assets within our East Texas and Other Midstream Segment of $20.6 million and $66.1 million, respectively, due to (i) reduced throughput volumes as our producer customers curtailed their drilling activity in response to the continued depressed natural gas price environment during the first six months of 2012 and (ii) the loss of two significant gathering contracts on our Panola system during the three months endedJune 30, 2012. During the three and six months endedJune 30,

35

2011, we recorded an impairment charge of $4.6 million in our Texas Panhandle Segment to fully write-down our idle Turkey Creek plant. During the three and six months endedJune 30, 2012 we recorded an impairment charge of $0.8 million compared to $0.3 million during the six months endedJune 30, 2011, within our Upstream Segment related to certain wells in our unproved properties as we determined it would not be economical to develop these unproved locations.

Pursuant to 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.

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 (the "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 our 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 through the end of 2013 at our Alabama facilities.  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, reduce the frequency of plant turnarounds 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 has determined, based on an analysis of the expected cost of the plant upgrades relative to their expected incremental cash flows, to classify 55% of the total capital invested to achieve the SO₂ emissions standard at our Alabama operations as maintenance capital and the balance as growth capital, which will reduce the amount of distributable cash flow we recognize in the periods in which the capital is spent. To the extent such expectations change, management will adjust accordingly the percentage of total capital invested that is classified as maintenance capital.

Subsequent Events

Successful Re-start of Phoenix-Arrington Ranch Plant- On July 2, 2012, we announced the successful re-start of our Phoenix-Arrington Ranch Plant in Hemphill County, Texas. The plant had been shut down since April 30, 2012, due to an incident and resulting fire that caused damage to the inlet header system. We estimate the cost of the repairs to the facility to be approximately $2.4 million. We have property insurance and will pursue reimbursement for the repairs associated with the incident above the associated deductible of $500,000.

Senior Unsecured Notes - On July 10, 2012, we, along with our subsidiary, Eagle Rock Energy Finance Corp. ("Finance Corp"), as co-issuer, completed the sale of $250.0 million of senior unsecured notes (the "Senior Notes") through a private placement. The Senior Notes were issued as an add-on to our existing senior unsecured notes issued on May 27, 2011. The Senior Notes bear a coupon of 8.375% and will mature on June 1, 2019. Interest on the Senior Notes is payable on each June 1 and December 1, commencing December 1, 2012. After the original discount of $3.7 million and excluding related offering expenses, we received net proceeds of approximately $246.3 million, which were used to repay borrowings outstanding under our revolving credit facility. The Senior Notes and the notes originally issued on May 27, 2011 will be treated as a single class of debt securities under the same indenture.

36

RESULTS OF OPERATIONS

Summary of Consolidated Operating Results

Below is a table of a summary of our consolidated operating results for the three and six months endedJune 30, 2012and 2011.

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	($ in thousands)
Revenues:
Natural gas, natural gas liquids, oil, condensate and sulfur sales	$	172,945		$	265,317		$	395,658		$	468,372
Gathering, compression, processing and treating fees	10,451			12,304			21,962			25,549
Realized commodity derivative gains (losses)	16,463			(8,813		)	22,626			(15,260		)
Unrealized commodity derivative gains (losses)	79,502			43,151			64,731			(10,847		)
Other revenue	3,043			(244		)	3,182			1,265
Total revenue	282,404			311,715			508,159			469,079
Cost of natural gas, natural gas liquids, and condensate	97,914			172,674			228,368			319,993
Costs and expenses:
Operations and maintenance	27,562			21,951			54,611			41,426
Taxes other than income	4,620			5,189			9,770			8,505
General and administrative	18,736			15,902			35,577			27,678
Other operating income	—			(2,893		)	—			(2,893		)
Impairment	21,402			4,560			66,924			4,884
Depreciation, depletion and amortization	38,354			31,576			77,648			55,274
Total costs and expenses	110,674			76,285			244,530			134,874
Operating income	73,816			62,756			35,261			14,212
Other income (expense):
Interest expense, net	(10,647		)	(6,308		)	(20,888		)	(9,529		)
Unrealized interest rate derivatives gains	2,007			2,791			3,803			5,356
Realized interest rate derivative losses	(3,470		)	(4,434		)	(6,845		)	(9,661		)
Other expense, net	4			(114		)	(45		)	(164		)
Total other expense	(12,106		)	(8,065		)	(23,975		)	(13,998		)
Income from continuing operations before income taxes	61,710			54,691			11,286			214
Income tax benefit	(79		)	(691		)	(170		)	(733		)
Income from continuing operations	61,789			55,382			11,456			947
Discontinued operations, net of tax	—			(311		)	—			407
Net income	$	61,789		$	55,071		$	11,456		$	1,354
Adjusted EBITDA(a)	$	57,668		$	53,948		$	120,493		$	84,242

________________________

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

37

Midstream Business (Three Segments)

Texas Panhandle Segment

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Natural gas, natural gas liquids and condensate sales	$	55,937		$	117,767		$	129,017		$	214,393
Intersegment sales - natural gas and condensate	19,043			—			44,489			—
Gathering, compression, processing and treating fees	3,852			4,227			8,802			8,013
Other revenue	2,864			—			2,864			—
Total revenue	81,696			121,994			185,172			222,406
Cost of natural gas, natural gas liquids, and condensate	51,117			87,761			122,605			159,715
Operating costs and expenses:
Operations and maintenance	12,399			11,207			24,637			20,608
Depreciation and amortization	9,873			9,116			19,390			18,237
Impairment	—			4,560			—			4,560
Total operating costs and expenses	22,272			24,883			44,027			43,405
Operating income	$	8,307		$	9,350		$	18,540		$	19,286
Capital expenditures	$	44,885		$	7,816		$	78,287		$	15,206
Realized prices:
Condensate (per Bbl)	$	82.29		$	87.54		$	89.28		$	83.81
Natural gas (per Mcf)	$	1.93		$	4.00		$	2.19		$	4.00
NGLs (per Bbl)	$	38.30		$	58.27		$	42.40		$	56.48
Production volumes:
Gathering volumes (Mcf/d)(a)	133,590			153,870			146,749			149,103
NGLs (net equity Bbls)(b)	297,688			181,186			626,802			377,132
Condensate (net equity Bbls)(b)	163,320			243,238			335,414			468,632
Natural gas (MMbtu/d)(a)	(5,629		)	(360		)	(6,546		)	(4,551		)

_______________________

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

(b) Effective January 2012, reported NGL volumes include those volumes recovered from our equity condensate through stabilization. These NGL volumes were previously reported as condensate. This change results in an increase to reported NGL equity barrels and a corresponding decrease to reported condensate equity barrels.

Revenues and Cost of Natural Gas, NGLs and Condensate. For the three and six months endedJune 30, 2012, revenues minus cost of natural gas, NGLs and condensate for our Texas Panhandle Segment operations totaled $30.6 million and $62.6 million, respectively, compared to $34.2 million and $62.7 million for the three and six months endedJune 30, 2011, respectively. These decreases were primarily driven by the decline in commodity prices and the downtime experienced by our Phoenix-Arrington Ranch processing facility. On April 30, 2012, we reported an incident and related fire at our Phoenix-Arrington Ranch processing facility which caused the facility to remain shut-in until July 2, 2012. We estimate that our results (revenues less cost of natural gas, NGLs and condensate) were negatively impacted due to the downtime by approximately $2.1 million. We have property and business interruption insurance and expect to pursue reimbursement for the downtime associated with the incident above the associated deductibles. As of June 30, 2012, we have not accrued any amounts related to our property or business interruption insurance. In addition, during the three months ended March 31, 2012, a third-party owned fractionation plant, which services all of our Panhandle processing plants, experienced downtime for approximately nine days. During that time, we curtailed NGL production through reduced recoveries at our plants. We estimate that our results for

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the six months endedJune 30, 2012, were negatively impacted by approximately $1.0 million due to the fractionation plant's downtime.

On June 4, 2012, we announced the successful start-up of a 60 MMcf/d cryogenic processing facility in the Granite Wash play in the Texas Panhandle (the "Woodall Plant"). Due to an incident in early June 2012 on a third-party pipeline that serves as a residue outlet, processing was curtailed at the Woodall Plant. We have mitigated this reduced flow by utilizing capacity on another residue outlet. We estimate that our results were negatively impacted by this incident by approximately $0.6 million during the three and six months endedJune 30, 2012.

These decreases were offset by improved run-times at certain of our processing facilities, as compared to the same period in the prior year, and the receipt of insurance proceeds related to business interruptions incurred in the prior year. In January and February 2011, severe winter weather caused operating downtime at three facilities and a reduction in existing volumes of natural gas, NGLs and condensate. This severe winter weather 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 $2.0 million and $4.1 million across the Texas Panhandle Segment during the three and six months endedJune 30, 2011, respectively. During the three months endedJune 30, 2012, we received an insurance payment of $2.9 million, which was recorded as other revenue, for business interruption related to the downtime caused by the severe winter weather in 2011.

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. The combination of our contract mix and the high NGL content of the natural gas gathered in the West Panhandle System provides us with a high level of equity NGL and condensate production. As such, any declines in gathered volumes from the West Panhandle System must be offset with increases in gathered volumes from other systems on a greater than one-to-one basis in order to maintain our total equity NGL and condensate production. We have seen continued drilling activity in the East Panhandle System by our producer customers and continue to expect drilling activity and the resulting volumes to continue during the remainder of 2012. Accordingly, in early August 2011 and April 2012, we entered into amendments to our Natural Gas Liquids Exchange Agreement with ONEOK to increase the maximum allowable volumes of natural gas liquids 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 amendments also provided for additional volumes expected after completion of our Woodall and Wheeler Plants in the Granite Wash play, which are discussed below.

Operating Expenses. Operating expenses, including taxes other than income, for the three and six months endedJune 30, 2012, increased $1.2 million and $4.0 million, respectively, as compared to the three and six months endedJune 30, 2011. The increase was primarily driven by increased costs related to the expansion of the Phoenix-Arrington Ranch Plant, which was completed in the fourth quarter of 2011, labor and related expenses associated with the new Woodall Plant and repair costs related to the Phoenix incident.

Depreciation and Amortization. Depreciation and amortization expenses for the three and six months endedJune 30, 2012 increased $0.8 million and $1.2 million from the three and six months endedJune 30, 2011, respectively. The increase was due to increased depreciation expense associated with the capital expenditures placed into service during the period.

Impairment. No impairment charges were incurred during the three and six months endedJune 30, 2012. During the three and six months endedJune 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.

Capital Expenditures. Capital expenditures for the three and six months endedJune 30, 2012, increased by $37.1 million and $63.1 million respectively, compared to the three and six months endedJune 30, 2011. The increase was primarily driven by spending related to the construction of our Woodall and Wheeler Plants.

The construction of the Woodall Plant and associated gathering and compression is expected to cost approximately $75 million, of which $72.8 million had been spent through June 30, 2012.

On October 31, 2011, we announced our intention to install a high-efficiency cryogenic processing plant in Wheeler County, Texas, in the heart of the Granite Wash play. We expect the installation of the new 60 MMcf/d processing plant (the "Wheeler Plant") and construction of the associated infrastructure to be completed in the second quarter of 2013. The addition of our Woodall and Wheeler Plants to our existing processing infrastructure in the Texas Panhandle Segment, together with the

39

Phoenix-Arrington Ranch Plant Expansion, is in response to incremental processing needs driven by increased drilling activity by producers in the Granite Wash play. The construction of the Wheeler Plant and associated gathering and compression is expected to cost approximately $63 million, of which $15.3 million had been spent through June 30, 2012.

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East Texas and Other Midstream Segment

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Natural gas, natural gas liquids and condensate sales	$	30,998		$	69,676		$	72,268		$	134,195
Intersegment sales - natural gas	6,928			—			16,451			—
Gathering, compression, processing and treating fees	6,599			8,077			13,160			17,536
Total revenue	44,525			77,753			101,879			151,731
Cost of natural gas, natural gas liquids, and condensate	32,550			61,186			78,058			119,666
Operating costs and expenses:
Operations and maintenance	5,764			5,373			10,893			10,757
Impairment	20,617			—			66,139			—
Depreciation and amortization	6,667			6,960			13,802			13,920
Total operating costs and expenses	33,048			12,333			90,834			24,677
Operating (loss) income from continuing operations	(21,073		)	4,234			(67,013		)	7,388
Discontinued operations (a)	—			(449		)	—			3
Operating (loss) income	$	(21,073	)	$	3,785		$	(67,013	)	$	7,391
Capital expenditures	$	2,967		$	1,470		$	5,652		$	2,498
Realized prices:
Condensate (per Bbl)	$	103.71		$	109.51		$	103.68		$	94.32
Natural gas (per Mcf)	$	2.22		$	4.50		$	2.59		$	4.46
NGLs (per Bbl)	$	39.72		$	55.11		$	42.53		$	50.43
Production volumes:
Gathering volumes (Mcf/d)(b)	265,472			334,537			278,961			340,610
NGLs (net equity Bbls)	84,981			126,925			176,325			230,975
Condensate (net equity Bbls)	10,403			6,939			21,727			24,907
Natural gas (MMbtu/d)(b)	3,952			1,861			2,031			2,067

_________________________

(a) Includes sales of natural gas of $24 and $66 to the Upstream Segment for the three and six months endedJune 30, 2011, respectively.

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

Revenues and Cost of Natural Gas, NGLs and Condensate. For the three and six months endedJune 30, 2012, revenues minus cost of natural gas and NGLs for our East Texas and Other Midstream Segment totaled $12.0 million and $23.8 million, respectively, compared to $16.6 million and $32.1 million for the three and six months endedJune 30, 2011, respectively. During the three and six months endedJune 30, 2012 and 2011, we recorded revenues associated with deficiency payments of $0.7 million, $0.7 million, $0.2 million and $1.4 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 six months endedJune 30, 2012 and 2011, would have been $11.3 million, $23.1 million, $16.4 million and $30.7 million, respectively. The decrease, excluding deficiency payments, for the three and six months endedJune 30, 2012 compared to the three and six months endedJune 30, 2011, is primarily due to a decrease in gathering and equity volumes and lower natural gas and NGL prices.

The gathering volumes for the three and six months endedJune 30, 2012 decreased as compared to the three and six months endedJune 30, 2011, due to natural declines in the production of the existing wells and reduced drilling activity in dry-gas formations related to a decline in natural gas prices.

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Operating Expenses. Operating expenses for the three and six months endedJune 30, 2012 increased $0.4 million and $0.1 million, respectively, compared to the three and six months endedJune 30, 2011 as a result of higher maintenance costs.

Impairment. We recorded impairment expense of $20.6 million and $66.1 million during the three and six months endedJune 30, 2012, respectively, on certain assets due to (i) reduced throughput volumes as our producer customers curtailed their drilling activity in response to the continued depressed natural gas price environment during the first six months of 2012 and (ii) the loss of two significant gathering contracts on our Panola system during the three months endedJune 30, 2012. No impairment charges were incurred in the three and six months endedJune 30, 2011.

Depreciation and Amortization. Depreciation and amortization expenses for the three and six months endedJune 30, 2012 decreased $0.3 million and $0.1 million, respectively, compared to the three and six months endedJune 30, 2011. The decrease was due to decreased depreciation expense as a result of the impairment charge recorded during the first three months of 2012.

Capital Expenditures. Capital expenditures for the three and six months endedJune 30, 2012 increased $1.5 million and $3.2 million, respectively, compared to the three and six months endedJune 30, 2011. Capital expenditures for the three and six months endedJune 30, 2011, were offset by the sale of $2.3 million of excess pipe inventory related to the East Texas Mainline expansion project which was cancelled in 2010. Excluding this transaction, capital expenditures in the six months endedJune 30, 2012, increased $0.9 million compared to the same period in 2011, due to capital expenditures related to the installation of vapor recovery units at two compressor sites.

Discontinued Operations.  No discontinued operations were recorded during the three and six months endedJune 30, 2012. On May 20, 2011, we sold the Wildhorse Gathering System. For the three and six months endedJune 30, 2011, we generated revenues of $1.8 million and $6.9 million, respectively, and income from operations of less than $0.1 million and $0.6 million, respectively.

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Marketing and Trading Segment

	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012			2011
	($ in thousands)
Revenues:
Natural gas, oil and condensate sales	$	53,389		$	38,306	$	119,971		$	62,758
Intersegment sales - natural gas and condensate	(28,084		)	—		(65,903		)	—
Total revenue	25,305			38,306		54,068			62,758
Cost of oil and condensate	14,247			23,727		27,705			40,612
Intersegment cost of oil and condensate	10,383			13,903		24,014			20,992
Operating costs and expenses:
Operations and maintenance	1			—		1			—
Depreciation and amortization	25			—		55			—
Total operating costs and expenses	26			—		56			—
Operating income	$	649		$	676	$	2,293		$	1,154
Capital Expenditures	$	89		$	288	$	231		$	288

We formed a crude and condensate marketing subsidiary during the fourth quarter of 2010 to develop and implement marketing uplift strategies surrounding crude oil and condensate production in Alabama and in the Texas Panhandle. In Alabama, we purchase product from our Upstream Segment and certain other working interest owners in the Big Escambia Creek, Fanny Church and Flomaton fields, and seek to increase the value of the product through: (i) blending and treating to lower the gravity and reduce the contaminants, respectively, of the purchased condensate; and (ii) transporting the higher quality condensate to premium market locations. In this regard, neither our Upstream Segment nor the other participating working interest owners bear increased risk in the relocating and treating of the condensate.

In the Texas Panhandle area, we are currently evaluating various storage and transportation opportunities to aggregate our product along with other third-party condensate and move it to more attractive markets.

We also conduct natural gas marketing and trading activities, which activities began during the third quarter of 2011. We seek to capitalize on the physical and financial arbitrage opportunities that naturally extend from our upstream and midstream assets. Where in the past, we generally sold to wholesale buyers at the tailgates and wellheads of our assets, now we hold transportation agreements and move our product to many locations and types of buyers. This strategy diversifies our credit and performance risk and allows us to capitalize on daily, monthly and seasonal changes in market conditions.

As part of our natural gas marketing and trading activities, we enter into both financial derivatives and physical contracts. Our 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.

A commodity-related derivative contract may be designated as a "normal" purchase or sale if the commodity is to be physically received or delivered for use or sale in the normal course of business. If designated as "normal," the derivative contract is accounted for under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of the contract until settlement. Commodity-related contracts that do not qualify for the normal designation are accounted for as derivatives and are marked-to-market each period.

For the three and six months endedJune 30, 2012, revenues minus cost of oil and condensate totaled $0.7 million and $2.3 million, respectively, compared to $0.7 million and $1.2 million for the three and six months endedJune 30, 2011, respectively. Revenues for the three and six months ended ended June 30, 2012, include an unrealized mark-to-market loss of $0.5 million and $0.3 million, respectively, related to the financial derivatives and physical contracts.

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Upstream Segment

	Three Months Ended June 30,					Six Months Ended June 30,
	2012		2011 (a)			2012		2011 (a)
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Oil and condensate	$	12,247	$	11,172		$	29,712	$	16,530
Intersegment sales - condensate	10,306		13,021			22,795		22,524
Natural gas (b)	6,832		11,886			14,150		15,280
Intersegment sales - natural gas	2,113		—			4,963		—
NGLs (c)	10,340		11,826			23,081		17,492
Sulfur (d)	3,202		4,684			7,459		7,724
Other	179		(244		)	318		1,265
Total revenue	45,219		52,345			102,478		80,815
Operating Costs and expenses:
Operations and maintenance (e)	14,018		10,584			28,850		18,632
Depletion, depreciation and amortization	21,366		15,180			43,586		22,410
Impairment	785		—			785		324
Total operating costs and expenses	36,169		25,764			73,221		41,366
Operating income	$	9,050	$	26,581		$	29,257	$	39,449
Capital expenditures	$	45,541	$	19,158		$	72,769	$	24,820
Realized average prices (f):
Oil and condensate (per Bbl)	$	84.60	$	88.67		$	88.92	$	83.17
Natural gas (per Mcf)	$	2.06	$	3.74		$	2.27	$	3.81
NGLs (per Bbl)	$	38.63	$	58.29		$	42.24	$	57.61
Sulfur (per Long ton)	$	147.55	$	182.73		$	147.15	$	174.70
Production volumes:
Oil and condensate (Bbl)	266,580		272,850			590,524		469,584
Natural gas (Mcf)	4,341,298		3,165,060			8,437,103		3,997,365
NGLs (Bbl)	267,673		206,251			546,404		305,609
Total (Mcfe)	7,546,811		6,039,672			15,258,666		8,648,524
Sulfur (Long ton)	21,705		25,268			50,697		43,803

________________________

(a) Includes operations related to the acquisition of Crow Creek Energy starting on May 3, 2011.

(b) Revenues include a change in the value of product imbalances by $(49), $(55), $53 and $60 for the three and six months endedJune 30, 2012 and 2011, respectively.

(c) Revenues include a change in the value of product imbalances by $(257), $(86), $(195) and $(115) for the three and six months endedJune 30, 2012 and 2011, respectively.

(d) Revenues include a change in the value of product imbalances by $(2), $32, $66 and $71 for the three and six months endedJune 30, 2012 and 2011, respectively.

(e) Includes purchase of natural gas of $24 and $66 from the East Texas and Other Midstream Segment for the three and six months endedJune 30, 2011.

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

Revenues. For the three and six months endedJune 30, 2012, Upstream Segment revenues decreased by $7.1 million

and increased $21.7 million, respectively, as compared to the three and six months endedJune 30, 2011.  The addition of production volumes from the acquisition of Crow Creek Energy, which closed on May 3, 2011, positively impacted the Upstream Segment's revenues by $3.5 million and $28.0 million during the three and six months endedJune 30, 2012, compared to the same period in 2011. Excluding the acquisition, revenues decreased due to lower realized prices and lower volumes for the three and six months endedJune 30, 2012 compared to the three and six months endedJune 30, 2011.

In August 2010, we announced that our East Texas oil and natural gas production was temporarily shut-in due to an

44

unscheduled shut-down of the Eustace processing facility owned and operated by a third-party. The shut-in negatively impacted our net revenues from January 1, 2011 to March 11, 2011, the date the plant was brought back into service, by approximately $3.9 million (excluding recoveries). 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.

In May and June 2012, we completed turnarounds of approximately eight and seven days, respectively, of our Big Escambia Creek facility to make certain equipment repairs and routine inspections of equipment. We estimate the net revenue impact due to the loss of production was approximately $3.8 million and the turnaround expense was approximately $0.5 million. The turnarounds reduced our production in the three months ended June 30, 2012 by approximately 23 MBbls of oil, 88 MMcf of residue gas, 18 MBbls of NGLs and 3,400 long ton of sulfur.

Operating Expenses. Operating expenses, including severance and ad valorem taxes, increased by $3.4 million and$10.2 million for the three and six months endedJune 30, 2012, respectively, as compared to the three and six months endedJune 30, 2011.  The increase is due to an increase in production expenses and severance taxes related to the increase in production, of which $3.6 million and $9.4 million was directly related to the operation of the properties acquired in the acquisition of Crow Creek Energy during the three and six months endedJune 30, 2012, respectively, compared to the same period in 2011.

Depletion, Depreciation and Amortization. Depletion, depreciation and amortization expense increased by $6.2 million and $21.2 million for the three and six months endedJune 30, 2012, respectively, as compared to the same period in the prior year.  The increase was primarily due to $7.2 million and $20.1 million of depletion and amortization expense incurred during the three and six months endedJune 30, 2012, respectively, for the properties acquired in the acquisition of Crow Creek Energy.

Impairment.  During the three and six months endedJune 30, 2012, we incurred impairment charges of $0.8 million related to certain wells in our unproved properties that the leasehold will expire next year and we determined we will not drill. During the six months endedJune 30, 2011, we incurred impairment charges of $0.3 million related to certain wells in our unproved properties that we determined would not be economical to develop.

Capital Expenditures.  Capital expenditures increased by $26.4 million and $47.9 million for the three and six months endedJune 30, 2012, respectively, as compared to the three and six months endedJune 30, 2011.   During the three months endedJune 30, 2012, we drilled and completed three gross operated wells and participated in four gross non-operated wells on leases in the Mid-Continent region, drilled and completed one gross operated well in the Permian region, and drilled and completed one gross non-operated well in East Texas. Additionally, during the three months endedJune 30, 2012, we conducted four workovers and one recompletion across our operations.

Upstream Well Incident - On July 19, 2012, one of our operated wells, located in Wayne County, Mississippi, experienced an uncontrolled flow event during a well workover operation. The incident required the mobilization of our emergency response personnel to control the well's flow and secure the nearby area in coordination with local, county and state emergency management agencies. Various contractors, including well control contractors, were mobilized to assist our response team. The flow from the well was fully controlled and secured on July 24, 2012. We estimate the cost of the incident to be between $2 - $4 million. We have Control of Well insurance and will pursue reimbursement above the associated deductible of $150,000.

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Corporate and Other Segment

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	($ in thousands)
Revenues:
Realized commodity derivative gains (losses)	$	16,463		$	(8,813	)	$	22,626		$	(15,260	)
Unrealized commodity derivative gains (losses)	79,502			43,151			64,731			(10,847		)
Intersegment elimination - Sales of natural gas and condensate	(10,306		)	(13,021		)	(22,795		)	(22,524		)
Total revenue	85,659			21,317			64,562			(48,631		)
Intersegment elimination - Cost of natural gas and condensate	(10,383		)	(13,903		)	(24,014		)	(20,992		)
General and administrative	18,736			15,902			35,577			27,678
Intersegment elimination - Operations and maintenance	—			(24		)	—			(66		)
Other operating income	—			(2,893		)	—			(2,893		)
Depreciation and amortization	423			320			815			707
Operating income (loss)	76,883			21,915			52,184			(53,065		)
Other income (expense):
Interest expense, net	(10,647		)	(6,308		)	(20,888		)	(9,529		)
Unrealized interest rate derivatives gains	2,007			2,791			3,803			5,356
Realized interest rate derivative losses	(3,470		)	(4,434		)	(6,845		)	(9,661		)
Other expense, net	4			(114		)	(45		)	(164		)
Total other expense	(12,106		)	(8,065		)	(23,975		)	(13,998		)
Income (loss) from continuing operations before taxes	64,777			13,850			28,209			(67,063		)
Income tax benefit	(79		)	(691		)	(170		)	(733		)
Income (loss) from continuing operations	64,856			14,541			28,379			(66,330		)
Discontinued operations, net of tax	—			138			—			404
Segment income (loss)	$	64,856		$	14,679		$	28,379		$	(65,926	)

Revenues. 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 the change in the mark-to-market value of our derivative position from the beginning of a period to the end.  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 six months endedJune 30, 2012, unrealized gains in our commodity derivative portfolio increased, as compared to the three and six months endedJune 30, 2011, due to decreases in the natural gas, NGL and crude oil forward curves. 

We recognized realized commodity derivative gains during the three and six months endedJune 30, 2012, compared to realized commodity derivative losses during the three and six months endedJune 30, 2011. The increase in the realized gains for the three and six months endedJune 30, 2012, as compared to the same period in the prior year, was due to the settlement of contracts assumed in the acquisition of Crow Creek Energy and lower natural gas, NGL and crude oil market prices during the three and six months endedJune 30, 2012, in relation to the strike prices of our settled contracts, as compared to the same period in the prior year.

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.

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Intersegment Eliminations. During the three and six months endedJune 30, 2012 and 2011, our Upstream Segment sold condensate to the Marketing and Trading Segment within our Midstream Business for resale. In addition, during the three and six months endedJune 30, 2011, our East Texas and Other Midstream Segment sold natural gas to our Upstream Segment to be used as fuel.

General and Administrative Expenses. General and administrative expenses increased by $2.8 million and $7.9 million for the three and six months endedJune 30, 2012, respectively, as compared to the same period in 2011. This increase was due to higher salaries and benefits, which was due to (i) an increase in our headcount due to the acquisition of Crow Creek Energy, (ii) increased equity compensation expense due to additional grants and (iii) higher insurance expense related to the increase in our insurable property and to higher insurance rates. The increases were partially offset by higher professional fees primarily associated with the acquisition of Crow Creek Energy in May 2011.

At the present time, we do not allocate our general and administrative expenses to our operational segments.

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 the three and six months endedJune 30, 2012, our realized settlements losses decreased by about $1.0 million and $2.8 million, respectively, as compared to the three and six months endedJune 30, 2011, as a result of increased LIBOR rates in 2012 and due to the two transactions described above. For the three and six months endedJune 30, 2012, we recognized unrealized gains of $2.0 million and $3.8 million, respectively, as compared to unrealized gains of $2.8 million and $5.4 million during the same period in 2011, as a result of a decrease 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 $4.3 million and $11.4 million during the three and six months endedJune 30, 2012, respectively, as compared to 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 (which were exchanged for registered notes on February 15, 2012) with a coupon of 8 3/8%, and on June 22, 2011, we entered into an Amended and Restated Credit Agreement, which bears interest currently at LIBOR plus 2.50%.  The increase in interest expense is due to the transactions discussed above and to higher LIBOR rates during 2012, as compared to the same period in 2011.

Income Tax (Benefit) Provision. Income tax provision for 2012 and 2011 relates to (i) state taxes due by us and (ii) federal taxes due by Eagle Rock Energy Acquisition Co., Inc. and Eagle Rock Energy Acquisition Co. II, Inc. and their wholly-owned subsidiary corporations, Eagle Rock Upstream Development Company, Inc. and Eagle Rock Upstream Development Company II, Inc., which are subject to federal income taxes (the "C Corporations").

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 three and six months endedJune 30, 2011, we received payments of $0.1 million and $0.4 million related to pre-effective date operations and recorded this amount as part of discontinued operations, respectively.

Adjusted EBITDA

Adjusted EBITDA, as defined under "Non-GAAP Financial Measures," increased by $3.7 million and $36.3 million from $53.9 million and $84.2 million for the three and six months endedJune 30, 2011, respectively, to $57.7 million and $120.5 million for the three and six months endedJune 30, 2012, respectively.

As described above, revenues minus cost of natural gas and NGLs for the Midstream Business (excluding unrealized gains from the Marketing and Trading Segment) decreased by $7.8 million and $6.9 million during the three and six months endedJune 30, 2012, respectively, as compared to the comparable period in 2011. The Upstream Segment revenues (excluding imbalances) decreased $6.9 million and increased $21.8 million during the three and six months endedJune 30, 2012, respectively, as compared to the comparable period in 2011. Intercompany eliminations of revenues minus cost of natural gas and condensate resulted in a $0.8 million decrease and a $2.8 million increase during the three and six months endedJune 30, 2012, respectively, as compared to the comparable period in 2011. Our Corporate and Other Segment's realized commodity derivatives gains increased by $25.3 million and $37.9 million during the three and six months endedJune 30, 2012, as compared to the comparable period in 2011. This resulted in total incremental revenues minus cost of natural gas and NGLs

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increasing by $9.8 million and $55.5 million during the three and six months endedJune 30, 2012, respectively, as compared to the comparable period in 2011.  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 $1.6 million and $4.2 million for the three and six months endedJune 30, 2012, respectively, as compared to the same period in 2011, and operating expenses (including taxes other than income) for the Upstream Segment increased $3.4 million and $10.2 million for the three and six months endedJune 30, 2012, respectively, as compared to the comparable period in 2011.

General and administrative expenses, 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 six months endedJune 30, 2012 by $1.1 million and $4.9 million, respectively, as compared to the respective period in 2011.

As a result, revenues (excluding the impact of unrealized commodity derivative activity) minus cost of natural gas, NGLs and condensate for the three and six months endedJune 30, 2012, as compared to the same period in 2011, increased by $9.8 million and $55.5 million, respectively, operating expenses increased by $5.0 million and $14.4 million, respectively, and general and administrative expenses increased by $1.1 million and $4.9 million, respectively.  The increases in revenues minus the cost of natural gas, NGLs and condensate, while partially offset by the increases in operating costs and general and administrative expenses, resulted in an increase to Adjusted EBITDA for the three and six months endedJune 30, 2012, as compared to the three and six months endedJune 30, 2011.

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 and administrative expenses, 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 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 six months endedJune 30, 2012, 5,300,588 warrants were exercised for which we received proceeds of $31.8 million. The final exercise date for the warrants was May 15, 2012, and on that date the remaining unexercised warrants expired.

During the second quarter of 2012, we announced a program through which we may issue common units, from time to time, with an aggregate market value of up to $100 million. We are under no obligation to issue equity under the program. We intend to use the net proceeds from any sales under the program for general partnership purposes, which may include, among other things, repayment of indebtedness, acquisitions, capital expenditures and additions to working capital. As of June 30, 2012, no units had been issued under this program.

We believe that our historical sources of liquidity, will be sufficient to satisfy our short-term liquidity needs and to fund our committed capital expenditures for at least the next twelve months. Our growth strategy entails substantial expenditures on organic projects in our Midstream Business and new drilling activity in our Upstream Business. We also intend to continue to pursue attractive development and acquisition opportunities in the midstream and upstream sectors. Accordingly, we may utilize various available financing sources, including the issuance of equity or debt securities, to fund all or 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 (i) acquire, construct, expand or upgrade our gathering, processing and treating assets or (ii) grow our natural gas, NGL, crude or sulfur production; or

• maintenance capital expenditures, which are made to (i) replace partially or fully depreciated assets, meet regulatory

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requirements, or maintain the existing operating capacity of our gathering, processing and treating assets or (ii) maintain our natural gas, NGL, crude or sulfur production.

The primary impact of this categorization is that we reduce the amount of cash we consider available for distribution by the amount of our maintenance capital expenditures.

Our current 2012 capital budget anticipates that we will spend approximately $287 million in total in 2012. Our capital expenditures were approximately $94.1 million and $158.3 million for the three and six months endedJune 30, 2012, respectively, of which $11.8 million and $19.8 million related to maintenance capital expenditures and $82.3 million and $138.5 million related to growth capital expenditures.

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 (the "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 our 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 through the end of 2013 at our Alabama facilities.  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, reduce the frequency of plant turnarounds 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 has determined, based on an analysis of the expected cost of the plant upgrades relative to their expected incremental cash flows, to classify 55% of the total capital invested to achieve the SO₂ emissions standard at our Alabama operations as maintenance capital and the balance as growth capital, which will reduce the amount of distributable cash flow we recognize in the periods in which the capital is spent. To the extent such expectations change, management will adjust accordingly the percentage of total capital invested that is classified as maintenance capital.

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:

• 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 revolving credit facility under the Credit Agreement consists of aggregate 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 revolving credit facility is subject to a borrowing base comprised of two components: the upstream component and the midstream component. As of June 30, 2012, our borrowing base exceeded our total commitments of $675 million, and we had approximately $77.6 million of availability under the revolving credit facility. The Credit Agreement matures on June 22, 2016.

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Senior Unsecured Notes

On May 27, 2011, we completed the sale of $300 million of our 8 3/8% senior unsecured notes through a private placement, which were exchanged for registered notes on February 15, 2012. The senior unsecured notes will mature on June 1, 2019, and interest is payable on June 1 and December 1 each year. We used the net proceeds of approximately $290.3 million to repay borrowings outstanding under our revolving credit facility.

On July 10, 2012, we completed the sale of an additional $250.0 million of senior unsecured notes through a private placement. After the original discount of $3.7 million and excluding related offering expenses, we received net proceeds of approximately $246.3 million, which were used to repay borrowings outstanding under our revolving credit facility. These notes were issued under the same indenture of the Partnership's and Finance Corp's existing senior unsecured notes issued on May 27, 2011. Both senior unsecured notes issuances will be treated as a single class of debt securities under the same indenture.

Debt Covenants

Our revolving credit facility requires us to maintain certain leverage, current and interest coverage ratios. As of June 30, 2012, we were in compliance with all of our debt covenants, and we believe that we will remain in compliance with our financial covenants through 2012. Our financial covenant requirements and actual ratios as of June 30, 2012, are as follows:

	Per Credit Agreement	Actual
Interest coverage ratio	2.5 (Min)	4.6
Leverage ratio	4.5 (Max)	3.5
Current ratio	1.0 (Min)	1.4

Our goal is to maintain our ratio of outstanding debt to Adjusted EBITDA, or "leverage ratio," at or below 3.5 on a sustained basis. We believe this leverage ratio level to be appropriate for our business.  We expect our efforts to maintain or reduce our leverage ratio during 2012 will be primarily through investing in attractive growth opportunities that will increase our Adjusted EBITDA.

Our senior unsecured notes are issued under an indenture that contains certain covenants limiting our ability to, among others, pay distributions, repurchase our equity securities, make certain investments, incur additional indebtedness, and sell assets. At June 30, 2012, we were in compliance with our covenants under the senior unsecured notes indenture.

For a further discussion of our revolving credit facility and senior unsecured notes see Note 8 to our consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data included in our Annual Report on Form 10-K for the year ended December 31, 2011.

Cash Flows

Cash Distributions

On January 26, 2012, we declared our fourth quarter 2011 cash distribution of $0.21 per unit to our common unitholders of record as of the close of business on February 7, 2012. The distribution was paid on February 14, 2012.

On April 24, 2012, we declared our first quarter 2012 cash distribution of $0.22 per unit to our common unitholders of record as of the close of business on May 8, 2012 (excluding certain restricted unit grants). The distribution was be paid on May 15, 2012.

On July 24, 2012, we declared our second quarter 2012 cash distribution of $0.22 per unit to our common unitholders of record as of the close of business on August 7, 2012. The distribution will be paid on August 14, 2012.

Working Capital

Working capital is the amount by which current assets exceed current liabilities. As of June 30, 2012, working capital

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was a positive $19.8 million as compared to a negative $45.3 million as of December 31, 2011.

The net increase in working capital of $65.1 million from December 31, 2011 to June 30, 2012 resulted primarily from the following factors:

• risk management net working capital balance increased by a net $49.0 million as a result of changes in current portion of mark-to-market unrealized positions as a result of decreases to the forward natural gas, oil and NGL price curves;

• accounts payable decreased by $32.1 million primarily as a result of downtime at our Phoenix-Arrington Ranch processing facility, lower volumes and timing of payments, partially offset by;

• trade accounts receivable decreased by $14.3 million primarily from the impact of lower revenues due to lower commodity prices and downtime at our Phoenix-Arrington Ranch processing facility;

• accrued liabilities increased by $0.3 million primarily reflecting accrued interest and the timing of payment of unbilled expenditures related primarily to capital expenditures; and

• cash balances and marketable securities decreased overall by $0.8 million.

Cash Flows for the Six Months Ended June 30,2012 Compared to the Six Months Ended June 30,2011

Cash Flow from Operating Activities. Cash flows from operating activities increased $36.1 million during the six months endedJune 30, 2012, as compared to the six months endedJune 30, 2011. This increase was primarily due to an increase in our results of operations from our acquisition of Crow Creek Energy and a decrease in payments made to terminate or reset certain derivative contracts. During the six months endedJune 30, 2011, we made payments of $5.0 million and $4.8 million to unwind interest rate derivative contracts and certain commodity derivative contracts, respectively, and a $14.6 million payment to adjust the strike price on certain existing commodity derivative contracts, as compared to our payment of $1.1 million to partially unwind certain commodity derivative contracts during the six months endedJune 30, 2012. Declines in natural gas prices during the six months endedJune 30, 2012, resulted in us realizing net settlement gains on our commodity derivatives, of which $8.4 million was reclassed to cash flows from financing activities.

Cash Flows from Investing Activities. Cash flows used in investing activities for the six months endedJune 30, 2012 were $152.2 million as compared to cash flows used in investing activities of $246.7 million for the six months endedJune 30, 2011. The key difference between periods is the decrease in our net cash outlay of $220.3 million for acquisitions, partially offset by an increase of $118.8 million for capital expenditures, in particular spending related to our Woodall and Wheeler Plants, as well as increased drilling in our Upstream Segment.  

Cash Flows from Financing Activities. Cash flows provided by financing activities during the six months endedJune 30, 2012 were $89.6 million as compared to cash flows provided by financing activities of $224.0 million for the six months endedJune 30, 2011. Key differences between periods include net borrowings under our revolving credit facility of $106.4 million during the six months endedJune 30, 2012 as compared to net repayments of $82.0 million on our revolving credit facility during the six months endedJune 30, 2011.  We also received $297.8 million from the sale of our Senior Notes during the six months endedJune 30, 2011. Cash outflows related to our distributions increased to $56.7 million during the six months endedJune 30, 2012, as compared to $26.3 million during the six months endedJune 30, 2011, as a result of increasing our quarterly distribution from $0.15 for the payments made in the first two quarters of 2011 (for the fourth quarter of 2010 and the first quarter of 2011) to $0.21 paid in the first quarter of 2012 (for the fourth quarter of 2011) and $0.22 paid in the second quarter of 2012 (for the first quarter of 2012). We also received $31.8 million due to the exercise of warrants during the six months endedJune 30, 2012, as compared to $45.9 million from the exercise of warrants during the same period in 2011.

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, during the six months ended June 30, 2012, we partially unwound two 2013 calendar year WTI crude oil swaps, totaling 28,400 barrels per month, at a cost of about $1.1 million. We were using

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these WTI crude oil swaps to hedge against changes in NGL prices. To continue hedging these NGL volumes, we entered into two calendar year 2013 propane swaps totaling 2,100,000 gallons per month.

During July 2012, we enhanced our commodity derivative portfolio by paying $2.8 million to adjust the strike price from $68.30 to $92.00 (the forward market price at the date of the transaction) per barrel on an existing WTI crude oil swap of 20,000 barrels per month for the six months ended December 31, 2012.

During July 2012, we also adjusted our interest rate hedge portfolio to re-balance our mix of floating and fixed interest rate exposure following our issuance of $250 million of senior unsecured notes with a fixed coupon of 8.375%. To accomplish this, we terminated $200 million notional amount of our existing fixed rate interest rate swaps with original maturities of December 31, 2012 for a total cost of $3.9 million.

For further description of our hedging activity, see Note 10 to our unaudited condensed consolidated financial statements included in Part I, Item 1. Financial Statements and Supplementary Data starting on page 2 of this Form 10-Q.

Off-Balance Sheet Obligations.

We had no off-balance sheet transactions or obligations at June 30, 2012. 

Recent Accounting Pronouncements

For recent accounting pronouncements, please see Note 3 of our unaudited condensed consolidated financial statements included in Part I, Item 1. Financial Statements and Supplementary Data starting on page 2 of this Form 10-Q.

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 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.

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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.

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 June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	($ in thousands)
Reconciliation of Adjusted EBITDA to net cash flows provided by (used in) operating activities and net income:
Net cash flows provided by operating activities	$	22,782		$	6,059		$	61,771		$	25,693
Add (deduct):
Discontinued operations	—			(311		)	—			407
Depreciation, depletion, amortization and impairment	(59,756		)	(36,136		)	(144,572		)	(60,158		)
Amortization of debt issuance costs	(707		)	(806		)	(1,406		)	(1,046		)
Risk management portfolio value changes	81,037			71,202			69,322			19,769
Reclassing financing derivative settlements	4,803			2,443			8,420			2,443
Other	(3,032		)	2,273			(5,303		)	1,128
Accounts receivable and other current assets	(24,641		)	(18,434		)	(14,977		)	5,483
Accounts payable and accrued liabilities	41,780			28,208			38,867			7,020
Other assets and liabilities	(477		)	573			(666		)	615
Net income	61,789			55,071			11,456			1,354
Add (deduct):
Interest expense, net	14,113			10,856			27,778			19,354
Depreciation, depletion, amortization and impairment	59,756			36,136			144,572			60,158
Income tax expense (benefit)	(79		)	(691		)	(170		)	(733		)
EBITDA	135,579			101,372			183,636			80,133
Add:
Unrealized (gains) losses from derivative activity	(81,036		)	(45,942		)	(68,264		)	5,491
Restricted unit compensation expense	2,818			1,024			5,012			1,934
Non-cash mark-to-market Upstream imbalances	307			76			109			(16		)
Discontinued operations	—			311			—			(407		)
Other income	—			90			—			90
Other operating income	—			(2,983		)	—			(2,983		)
ADJUSTED EBITDA	$	57,668		$	53,948		$	120,493		$	84,242

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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. As of June 30, 2012, our commodity hedge portfolio totaled a net asset position of $108.4 million, consisting of assets aggregating $112.6 million and liabilities aggregating $4.3 million. For additional information about our hedging activities and related fair values, see Part I, Item 1. Financial Statement Notes 10 and 11.

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. 

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.

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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. As of June 30, 2012, the fair value liability of these interest rate contracts totaled approximately $20.2 million.

Credit Risk

Our principal natural gas sales customers are large gas marketing companies that, in turn, typically sell to large end users such as local distribution companies and electrical utilities. 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, BBVA Compass Bank, Royal Bank of Canada and CITIBANK, N.A.

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

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.

In July 2012, the Alabama Department of Environmental Management (“ADEM”) notified one of our subsidiaries that ADEM had made a determination that alleged violations warrant enforcement action and determined that the alleged violations are appropriate for resolution by Consent Order and proposed the terms of a to-be-mutually-agreed-upon Consent Order (“Proposed Consent Order”).  Such notification and the Proposed Consent Order are the result of findings made by ADEM relating to our subsidiary's Flomaton/Fanny Church Oil and Gas Production and Treating Facility. The Proposed Consent Order primarily relates to allegations of emissions in excess of those allowed by the production rate.  Prior to receiving the Proposed Consent Order, we self-reported our emission rates and worked with ADEM to complete a series of quality improvement plans to address the causes of the alleged violations. The fine amount proposed by ADEM in the Proposed Consent Order is $100,000, which may be negotiated to a lesser amount at the discretion of ADEM.

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, 2011, 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. 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, 2011.

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

On May 15, 2012, Montierra Minerals & Production, L.P., an entity affiliated with Natural Gas Partners, exercised 273,484 warrants (“Warrants”) to purchase our common units, and we issued an equivalent number of common units, for an aggregate exercise price of $1,640,904. 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 our 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. Joseph A. Mills, the Chief Executive Officer of Eagle Rock Energy G&P, LLC, the general partner of the general partner of us, also serves as Chief Executive Officer and as a manager of Montierra Management LLC, which is the general partner of Montierra Minerals & Production, LP.

The following table sets forth certain information with respect to repurchases of common units during the three months endedJune 30, 2012:

Period	Total Number of Units Purchased	Average Price Paid Per Unit		Total Number of Units Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) or Units that May Yet Be Purchased Under the Plans or Programs
April 1, 2012 - April 30, 2012	—	$	—	—	—
May 1, 2012 - May 31, 2012	32,526	$	8.97	—	—
June 1, 2012 - June 30, 2012	—	$	—	—	—
Total	32,526	$	8.97	—	—

All of the units were surrendered by employees to pay tax withholding in connection with the vesting of restricted common

56

units. As a result, we are deeming the surrenders to be "repurchases." These repurchases were not part of a publicly announced program to repurchase our common units, nor do we have a publicly announced program to repurchase our common units.

Item 3. Defaults Upon Senior Securities

None

Item 4. Mine Safety Disclosures

None

Item 5. Other Information

None

57

Item 6. Exhibits

Exhibit Number	Description
3.1	Certificate of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 of the registrant'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 of the registrant's current report on Form 8-K filed with the Commission on May 25, 2010)
3.3	Certificate of Limited Partnership of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.3 of the registrant's registration statement on Form S-1 (File No. 333-134750))
3.4	Limited Partnership Agreement of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.4 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
3.5	Certificate of Formation of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 3.5 of the registrant's registration statement on Form S-1 (File No. 333-134750))
3.6	Third Amended and Restated Limited Liability Company Agreement of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 42 of the registrant's current report on Form 8-K filed with the Commission on July 30, 2010)
3.7	Amendment No. 1 to the Second Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 4.1 of the registrant'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. (successor to ONEOK Texas Field Services, L.P.) dated April 6, 2012 (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on April 12, 2012)
10.2*	Confidentiality and Noncompete Agreement by and between Eagle Rock Energy G&P, LLC and Joseph A. Mills dated August 3, 2012
10.3*	Confidentiality and Noncompete agreement by and between Eagle Rock Energy G&P, LLC and Jeffrey P. Wood dated August 3, 2012
10.4*	Confidentiality and Non-Solicitation Agreement by and between Eagle Rock Energy G&P, LLC. and Charles C. Boettcher  dated August 3, 2012
10.5*	Confidentiality and non-solicitation agreement by and between Eagle Rock Energy Partners, L.P. and Joseph Schimelpfening  dated August 3, 2012
10.6*	Confidentiality and Non-Solicitation Agreement by and between Eagle Rock Energy G&P, LLC and Steven Hendrickson  dated August 3, 2012
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
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document

* Filed herewith

** Furnished herewith

58

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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, on August 3, 2012.

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

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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 of the registrant'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 of the registrant's current report on Form 8-K filed with the Commission on May 25, 2010)
3.3	Certificate of Limited Partnership of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.3 of the registrant's registration statement on Form S-1 (File No. 333-134750))
3.4	Limited Partnership Agreement of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.4 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
3.5	Certificate of Formation of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 3.5 of the registrant's registration statement on Form S-1 (File No. 333-134750))
3.6	Third Amended and Restated Limited Liability Company Agreement of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 42 of the registrant's current report on Form 8-K filed with the Commission on July 30, 2010)
3.7	Amendment No. 1 to the Second Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 4.1 of the registrant'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. (successor to ONEOK Texas Field Services, L.P.) dated April 6, 2012 (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on April 12, 2012)
10.2*	Confidentiality and Noncompete Agreement by and between Eagle Rock Energy G&P, LLC and Joseph A. Mills dated August 3, 2012
10.3*	Confidentiality and Noncompete agreement by and between Eagle Rock Energy G&P, LLC and Jeffrey P. Wood dated August 3, 2012
10.4*	Confidentiality and Non-Solicitation Agreement by and between Eagle Rock Energy G&P, LLC. and Charles C. Boettcher dated August 3, 2012
10.5*	Confidentiality and non-solicitation agreement by and between Eagle Rock Energy Partners, L.P. and Joseph Schimelpfening dated August 3, 2012
10.6*	Confidentiality and Non-Solicitation Agreement by and between Eagle Rock Energy G&P, LLC and Steven Hendrickson dated August 3, 2012
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
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document

* Filed herewith

** Furnished herewith