Eagle Rock Energy Partners L P (EROC) 10-Q 2013 Q1 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 March 31, 2013

OR

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

Commission File Number 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 159,050,155 common units outstanding as of May 1, 2013.

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements	2
	Unaudited Condensed Consolidated Balance Sheets as of March 31,2013 and December 31, 2012	2
	Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2013 and 2012	3
	Unaudited Condensed Consolidated Statement of Members' Equity for the three months ended March 31, 2013	4
	Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2013 and 2012	5
	Notes to Unaudited Condensed Consolidated Financial Statements	6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	27
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	45
Item 4.	Controls and Procedures	46
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	47
Item 1A.	Risk Factors	47
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47
Item 3.	Defaults Upon Senior Securities	47
Item 4.	Mine Safety Disclosures	47
Item 5.	Other Information	47
Item 6.	Exhibits	47

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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, except unit amounts)

	March 31, 2013		December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	60	$	25
Accounts receivable (a)	144,272		138,732
Risk management assets	14,789		33,340
Prepayments and other current assets	10,122		9,867
Total current assets	169,243		181,964
PROPERTY, PLANT AND EQUIPMENT — Net	1,988,530		1,968,206
INTANGIBLE ASSETS — Net	109,901		111,515
DEFERRED TAX ASSET	1,655		1,656
RISK MANAGEMENT ASSETS	9,752		7,953
OTHER ASSETS	21,530		22,922
TOTAL	$	2,300,611	$	2,294,216
LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	148,689	$	160,473
Accrued liabilities	32,518		19,764
Taxes payable	46		46
Risk management liabilities	3,438		1,231
Total current liabilities	184,691		181,514
LONG-TERM DEBT	1,122,560		1,153,103
ASSET RETIREMENT OBLIGATIONS	41,569		44,814
DEFERRED TAX LIABILITY	41,838		43,000
RISK MANAGEMENT LIABILITIES	9,405		1,700
OTHER LONG TERM LIABILITIES	3,049		1,711
COMMITMENTS AND CONTINGENCIES (Note 12)
MEMBERS' EQUITY (b)	897,499		868,374
TOTAL	$	2,300,611	$	2,294,216

________________________ 

(a) Net of allowance for bad debt of $797 as of March 31, 2013 and $972 as of December 31, 2012.

(b) 155,025,751 and 144,675,751 common units were issued and outstanding as of March 31, 2013 and December 31, 2012, respectively. These amounts do not include unvested restricted common units granted under the Partnership's long-term incentive plan of 2,675,246 and 2,608,035 as of March 31, 2013 and December 31, 2012, 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 March 31,
	2013			2012
REVENUE:
Natural gas, natural gas liquids, oil, condensate, sulfur and helium sales	$	254,200		$	222,713
Gathering, compression, processing and treating fees	20,942			11,511
Commodity risk management losses, net	(17,908		)	(8,608		)
Other revenue	497			139
Total revenue	257,731			225,755
COSTS AND EXPENSES:
Cost of natural gas, natural gas liquids, condensate and helium	179,988			130,454
Operations and maintenance	32,219			27,049
Taxes other than income	3,866			5,150
General and administrative	18,847			16,841
Impairment	—			45,522
Depreciation, depletion and amortization	40,237			39,294
Total costs and expenses	275,157			264,310
OPERATING LOSS	(17,426		)	(38,555		)
OTHER EXPENSE:
Interest expense, net	(17,084		)	(10,241		)
Interest rate risk management losses, net	(156		)	(1,579		)
Other expense, net	(8		)	(49		)
Total other expense	(17,248		)	(11,869		)
LOSS BEFORE INCOME TAXES	(34,674		)	(50,424		)
INCOME TAX BENEFIT	(1,160		)	(91		)
NET LOSS	$	(33,514	)	$	(50,333	)

NET LOSS PER COMMON UNIT—BASIC AND DILUTED:
Net Loss
Common units - Basic and diluted	$	(0.23	)	$	(0.40	)
Weighted Average Units Outstanding (in thousands)
Common units - Basic and diluted	146,171			128,162

 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 THREE MONTHS ENDED MARCH 31, 2013

($ in thousands, except unit amounts)

	Number of Common Units	Common Units			Total
BALANCE — December 31, 2012	144,675,751	$	868,374		$	868,374
Net loss	—	(33,514		)	(33,514		)
Distributions	—	(32,419		)	(32,419		)
Equity based compensation	—	2,647			2,647
Common units issued in equity offering	10,350,000	96,359			96,359
Unit issuance costs for equity offering	—	(3,948		)	(3,948		)
BALANCE — March 31, 2013	155,025,751	$	897,499		$	897,499

 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)

	Three Months Ended March 31,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(33,514	)	$	(50,333	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	40,237			39,294
Impairment	—			45,522
Amortization of debt issuance costs	1,036			699
Reclassing financing derivative settlements	(1,044		)	(3,617		)
Equity-based compensation	2,647			2,194
Other	1,048			77
Changes in assets and liabilities—net of acquisitions:
Accounts receivable	(4,296		)	(9,225		)
Prepayments and other current assets	(255		)	(439		)
Risk management activities	26,664			11,715
Accounts payable	(40		)	(661		)
Accrued liabilities	8,551			3,574
Other assets	436			1,885
Other current liabilities	(628		)	(1,696		)
Net cash provided by operating activities	40,842			38,989
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(70,137		)	(68,521		)
Purchase of intangible assets	(1,006		)	(1,099		)
Net cash used in investing activities	(71,143		)	(69,620		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	171,300			169,450
Repayment of long-term debt	(202,000		)	(134,750		)
Proceeds from derivative contracts	1,044			3,617
Common unit issued in equity offerings	96,359			—
Issuance costs for equity offerings	(3,948		)	—
Exercise of warrants	—			18,958
Distributions to members and affiliates	(32,419		)	(27,340		)
Net cash provided by financing activities	30,336			29,935
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	35			(696		)
CASH AND CASH EQUIVALENTS—Beginning of period	25			877
CASH AND CASH EQUIVALENTS—End of period	$	60		$	181
NONCASH INVESTING AND FINANCING ACTIVITIES:
Investments in property, plant and equipment, not paid	$	16,580		$	25,984
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid—net of amounts capitalized	$	5,310		$	3,379
Cash paid for taxes	$	2		$	521

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 growth-oriented limited partnership engaged in (i) the business of gathering, compressing, treating, processing, transporting, marketing and trading natural gas; fractionating, transporting and marketing natural gas liquids ("NGLs"); and crude oil and condensate logistics and marketing (the “Midstream Business”); and (ii) the business of developing and producing interests in oil and natural gas properties (the “Upstream Business”). The Partnership's midstream assets are strategically located in four productive, mature natural gas producing regions: the Texas Panhandle; East Texas/Louisiana; South Texas; and the Gulf of Mexico. The Partnership's natural gas pipelines gather natural gas from designated points near producing wells and transport these volumes to third-party pipelines, the Partnership's gas processing plants, utilities and industrial consumers. Natural gas transported to the Partnership's gas processing plants, either in the Partnership's pipelines or third party pipelines, is treated to remove contaminants and conditioned or processed into marketable natural gas and NGLs. The Partnership 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 characterized by long-lived, high-working interest properties with extensive production histories and development opportunities. Its upstream assets are located primarily in South Alabama (where it also operates the associated gathering and processing assets), Texas, Oklahoma, Mississippi and Arkansas. 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, 2012. 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 months endedMarch 31, 2013 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2013.

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, 2012. 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 March 31, 2013 and December 31, 2012, the Partnership had $0.7 million and $0.8 million, respectively, of crude oil finished goods inventory, which is recorded as part of Other Current Assets within the unaudited condensed consolidated balance sheet.

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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, accounted for utilizing the successful efforts method, 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 to the proved reserves estimates, unfavorable projections of future prices, the timing of future production and estimates of future costs to produce the oil and natural gas. 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—The Partnership'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 the Partnership 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.  For the Upstream Segment, as of March 31, 2013, the Partnership had long-term imbalance payables totaling $0.3 million. For the Upstream Segment, as of December 31, 2012, the Partnership had long-term imbalance payables totaling $0.6 million.

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

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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 March 31, 2013, the Partnership had imbalance receivables totaling $0.4 million and imbalance payables totaling $2.4 million. For the Midstream Business, as of December 31, 2012, the Partnership had imbalance receivables totaling $0.2 million and imbalance payables totaling $2.1 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 it's 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 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 were effective for the Partnership on January 1, 2013, and did not have a material impact on the Partnership's financial statements for the quarter ended March 31, 2013. See Notes 10 and 11 for the disclosures related to the Partnership's rights of set-off and the gross and net exposure related to its derivative instruments.

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NOTE 4. PROPERTY PLANT AND EQUIPMENT

Fixed assets consisted of the following:

	March 31, 2013			December 31, 2012
	($ in thousands)
Land	$	2,877		$	2,876
Plant	448,372			444,023
Gathering and pipeline	756,255			753,009
Equipment and machinery	41,663			39,889
Vehicles and transportation equipment	3,993			4,021
Office equipment, furniture, and fixtures	1,285			1,285
Computer equipment	12,431			11,431
Linefill	5,180			4,328
Proved properties	1,260,160			1,213,622
Unproved properties	20,304			31,823
Construction in progress	71,768			60,870
	2,624,288			2,567,177
Less: accumulated depreciation, depletion and amortization	(635,758		)	(598,971		)
Net property plant and equipment	$	1,988,530		$	1,968,206

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 March 31,
	2013		2012
	($ in thousands)
Depreciation	$	16,395	$	14,255
Depletion	$	20,871	$	22,050
Capitalized interest costs	$	355	$	358
Impairment expense:
Plant assets (a)	$	—	$	4,164
Pipeline assets (a)	$	—	$	37,148

________________________________

(a) During the three months endedMarch 31, 2012, the Partnership incurred impairment charges in its Midstream Business related to certain plants and pipelines in its East Texas and Other Segment due to reduced throughput volumes as its producer customers curtailed their drilling activity in response to the continued depressed natural gas price environment.

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

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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:

	2013			2012
	($ in thousands)
Asset retirement obligations—December 31 (a)	$	48,755		$	33,303
Additional liabilities	746			815
Liabilities settled	(570		)	(1,551		)
Accretion expense	840			528
Asset retirement obligations—March 31 (a)	$	49,771		$	33,095

_____________________________________

(a) As of March 31, 2013 and December 31, 2012, $8.2 million and $3.9 million, respectively, were included within accrued liabilities in the Unaudited Condensed Consolidated Balance Sheets.

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 periods for contracts range from 5 to 20 years.  Intangible assets consisted of the following:

	March 31, 2013			December 31, 2012
	($ in thousands)
Rights-of-way and easements—at cost	$	128,381		$	127,375
Less: accumulated amortization	(31,526		)	(29,959		)
Contracts	36,941			38,009
Less: accumulated amortization	(23,895		)	(23,910		)
Net intangible assets	$	109,901		$	111,515

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 March 31,
	2013		2012
	($ in thousands)
Amortization	$	2,961	$	2,989
Impairment expense:
Rights-of-way (a)	$	—	$	3,154
Contracts (a)	$	—	$	1,056

_____________________________________

(a) During the three months endedMarch 31, 2012, the Partnership incurred impairment charges in its Midstream Business related to certain plants and pipelines in its East Texas and Other Segment due to reduced throughput volumes as its producer customers curtailed their drilling activity in response to the continued depressed natural gas price environment.

Estimated future amortization expense related to the intangible assets at March 31, 2013, is as follows (in thousands):

10

Year ending December 31,
2012	$	5,318
2013	$	7,619
2014	$	7,619
2015	$	7,619
2016	$	7,618
Thereafter	$	74,108

NOTE 7. LONG-TERM DEBT

Long-term debt consisted of the following:

	March 31, 2013			December 31, 2012
	($ in thousands)
Revolving credit facility:	$	577,800		$	608,500
Senior notes:
8.375% Senior Notes due 2019	550,000			550,000
Unamortized bond discount	(5,240		)	(5,397		)
Total Senior Notes	544,760			544,603
Total long-term debt	$	1,122,560		$	1,153,103

The Partnership currently pays an annual fee of 0.45% on the unused commitment under the revolving credit facility. As of March 31, 2013, the Partnership had approximately $26.8 million of outstanding letters of credit and approximately $215.4 million of availability under its revolving credit facility, based on total commitments and before considering covenant limitations. The revolving credit facility matures on June 22, 2016.

As of March 31, 2013, the Partnership was in compliance with the financial covenants under the revolving credit facility.

NOTE 8. MEMBERS’ EQUITY

At March 31, 2013 and December 31, 2012, there were 155,025,751 and 144,675,751 unrestricted common units outstanding, respectively. In addition, there were 2,675,246 and 2,608,035 unvested restricted common units outstanding at March 31, 2013 and December 31, 2012, respectively.

On May 31, 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. During the three months endedMarch 31, 2013, no units were issued under this program.

On March 12, 2013, the Partnership closed an underwritten public offering of 10,350,000 common units for net proceeds of approximately $92.5 million.

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 three months endedMarch 31, 2013. 

Quarter Ended	Distribution per Common Unit		Record Date*	Payment Date
December 31, 2012	$	0.2200	February 7, 2013	February 14, 2013
March 31, 2013+	$	0.2200	May 7, 2013	May 15, 2013

_____________________________

+ The distribution excludes certain restricted unit grants.

* The "Record Date" set forth in the table above means the close of business on each of the listed Record Dates.

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NOTE 9. RELATED PARTY TRANSACTIONS

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

	Three Months Ended March 31,
	2013		2012
Affiliates of Natural Gas Partners:	($ in thousands)
Natural gas purchases from affiliates	$	123	$	941

	March 31, 2013		December 31, 2012
Affiliates of Natural Gas Partners:	($ in thousands)
Payable (related to natural gas purchases)	$	—	$	428

NOTE 10. RISK MANAGEMENT ACTIVITIES

Interest Rate Swap Derivative Instruments

To mitigate its interest rate risk, the Partnership has entered into interest rate swaps. These swaps convert the variable-rate revolving credit facility 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 interest rate swaps as of March 31, 2013:

Effective Date	Expiration Date	Notional Amount		Fixed Rate
6/22/2011	6/22/2015	$	250,000,000	2.950	%

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 less than its total expected future production. While hedging at this level of production does not eliminate all of the volatility in the Partnership's cash flows, it allows the Partnership to mitigate the risk of situations where a modest loss of production would 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

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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 historical relationship of the prices of the two commodities 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 currently required to post any collateral, nor does it require collateral from its counterparties. The Partnership minimizes the credit risk in derivative instruments by limiting 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, and when possible, the Partnership nets the open positions of each counterparty. See Note 11 for the impact to the Partnership's unaudited condensed consolidated balance sheets of the netting of these derivative contracts.

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.

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Commodity derivatives, as of March 31, 2013, that will mature during the years ended December 31, 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 2013
Natural Gas	Costless Collar	2,760,000	4.85	5.46
Natural Gas	Swap (Pay Floating/Receive Fixed)	9,005,000	4.84
Crude Oil	Costless Collar	63,000	74.29	101.38
Crude Oil	Swap (Pay Floating/Receive Fixed)	1,582,650	96.54
Propane	Swap (Pay Floating/Receive Fixed)	18,900,000	1.23
IsoButane	Swap (Pay Floating/Receive Fixed)	2,683,800	1.91
Normal Butane	Swap (Pay Floating/Receive Fixed)	3,288,600	1.82
Portion of Contracts Maturing in 2014
Natural Gas	Swap (Pay Floating/Receive Fixed)	13,800,000	4.49
Crude Oil	Costless Collar	240,000	90.00	106.00
Crude Oil	Swap (Pay Floating/Receive Fixed)	2,040,000	96.45
Portion of Contracts Maturing in 2015
Natural Gas	Swap (Pay Floating/Receive Fixed)	9,000,000	4.11
Crude Oil	Costless Collar	480,000	90.00	97.55
Crude Oil	Swap (Pay Floating/Receive Fixed)	480,000	90.15
Portion of Contracts Maturing in 2016
Natural Gas	Swap (Pay Floating/Receive Fixed)	5,400,000	4.27
Crude Oil	Swap (Pay Floating/Receive Fixed)	480,000	85.10

_______________________

(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 in $/MMbtu for natural gas, $/barrel for crude oil and $/gallon for natural gas liquids.

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.

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.

Through the Partnership's natural gas marketing activity, the Partnership has credit exposure to additional counterparties. The Partnership minimizes the credit risk associated with natural gas marketing by limiting its exposure to any single counterparty and monitoring the creditworthiness of its counterparties on an ongoing basis. In addition, the Partnership's natural gas purchase and sale contracts for certain counterparties, are subject to counterparty netting agreements governing settlement under such natural gas purchase and sales contracts, and when possible, the Partnership nets the open positions of each counterparty. See Note 11 for the impact to the Partnership's unaudited condensed consolidated balance sheets of the netting of these contracts.

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Marketing and Trading commodity derivative instruments, as of March 31, 2013, that will mature during the years ended December 31, 2013 and 2014:

Type	Notional Volumes (MMbtu)
Portion of Contracts Maturing in 2013
Basis Swaps - Purchases	10,530,000
Basis Swaps - Sales	10,530,000
Index Swap - Sales	2,590,000
Swap (Pay Fixed/Receive Floating) - Purchases	1,125,000
Swap (Pay Floating/Received Fixed) - Sales	1,125,000
Forward purchase contract - index	14,215,370
Forward sales contract - index	10,339,570
Forward purchase contract - fixed price	1,797,000
Forward sales contract - fixed price	1,800,000
Portion of Contracts Maturing in 2014
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.

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Fair Value of Interest Rate and Commodity Derivatives

Fair values of interest rate and commodity derivative instruments not designated as hedging instruments in the unaudited condensed consolidated balance sheet as of March 31, 2013 and December 31, 2012:

	As of March 31, 2013
	Derivative Assets				Derivative Liabilities
	Balance Sheet Classification	Fair Value			Balance Sheet Classification	Fair Value
	($ in thousands)
Interest rate derivatives - liabilities	Current assets	$	—		Current liabilities	$	(6,141	)
Interest rate derivatives - liabilities	Long-term assets	—			Long-term liabilities	(7,110		)
Commodity derivatives - assets	Current assets	17,478			Current liabilities	5,992
Commodity derivatives - assets	Long-term assets	10,627			Long-term liabilities	2,088
Commodity derivatives - liabilities	Current assets	(2,689		)	Current liabilities	(3,289		)
Commodity derivatives - liabilities	Long-term assets	(875		)	Long-term liabilities	(4,383		)
Total derivatives		$	24,541			$	(12,843	)
	As of December 31, 2012
	Derivative Assets				Derivative Liabilities
	Balance Sheet Classification	Fair Value			Balance Sheet Classification	Fair Value
	($ in thousands)
Interest rate derivatives - liabilities	Current assets	$	(4,844	)	Current liabilities	$	(1,201	)
Interest rate derivatives - liabilities	Long-term assets	(7,002		)	Long-term liabilities	(1,700		)
Commodity derivatives - assets	Current assets	39,182			Current liabilities	19
Commodity derivatives - assets	Long-term assets	17,338			Long-term liabilities	—
Commodity derivatives - liabilities	Current assets	(998		)	Current liabilities	(49		)
Commodity derivatives - liabilities	Long-term assets	(2,383		)	Long-term liabilities	—
Total derivatives		$	41,293			$	(2,931	)

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 March 31,
			2013			2012
		($ in thousands)
Interest rate derivatives	Interest rate risk management losses		$	(156	)	$	(1,579	)
Commodity derivatives	Commodity risk management losses		(17,908		)	(8,608		)
Commodity derivatives - trading	Natural gas, natural gas liquids, oil, condensate and sulfur sales		(1,150		)	637
	Total		$	(19,214	)	$	(9,550	)

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).

The three levels of the fair value hierarchy are as follows:

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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 March 31, 2013, the Partnership 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 classified the inputs to measure the fair value of its interest rate swaps, crude oil derivatives, NGL derivatives and natural gas derivatives as Level 2. 

The following tables disclose the fair value of the Partnership's derivative instruments as of March 31, 2013 and December 31, 2012: 

	As of March 31, 2013
	Level 1		Level 2			Level 3		Netting (a)			Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	12,530		$	—	$	(8,241	)	$	4,289
Natural gas derivatives	—		15,812			—		(836		)	14,976
NGL derivatives	—		7,843			—		(2,567		)	5,276
Total	$	—	$	36,185		$	—	$	(11,644	)	$	24,541
Liabilities:
Crude oil derivatives	$	—	$	(5,315	)	$	—	$	8,241		$	2,926
Natural gas derivatives	—		(5,921		)	—		836			(5,085		)
NGL derivatives	—		—			—		2,567			2,567
Interest rate swaps	—		(13,251		)	—		—			(13,251		)
Total	$	—	$	(24,487	)	$	—	$	11,644		$	(12,843	)

____________________________

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

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	As of December 31, 2012
	Level 1		Level 2			Level 3		Netting (a)			Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	19,410		$	—	$	(1,814	)	$	17,596
Natural gas derivatives	—		27,340			—		(1,586		)	25,754
NGL derivatives	—		9,789			—		—			9,789
Interest rate swaps	—		—			—		(11,846		)	(11,846		)
Total	$	—	$	56,539		$	—	$	(15,246	)	$	41,293
Liabilities:
Crude oil derivatives	$	—	$	(1,814	)	$	—	$	1,814		$	—
Natural gas derivatives	—		(1,616		)	—		1,586			(30		)
Interest rate swaps	—		(14,747		)	—		11,846			(2,901		)
Total	$	—	$	(18,177	)	$	—	$	15,246		$	(2,931	)

____________________________

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

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

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

The 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 March 31, 2013, 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 bear interest at a fixed rate; based on the market price of the Senior Notes as of March 31, 2013, the Partnership estimates that the fair value of the Senior Notes was $580.3 million compared to a carrying value of $544.8 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 March 31, 2013 or December 31, 2012 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 for indemnification up to the contractual limits.

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,

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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.

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 March 31, 2013 and December 31, 2012, the Partnership had accrued approximately $2.8 million for environmental matters.

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

The retained revenue interests affect the Partnership's interest in 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 2012 and does not anticipate doing so in 2013. 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 $2.1 million and $2.3 million for the three months endedMarch 31, 2013 and 2012, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term.

NOTE 13. SEGMENTS

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

(i)Midstream—Texas Panhandle Segment: 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 and condensate 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.

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The Partnership's chief operating decision maker ("CODM") currently reviews its operations using these segments. The CODM evaluates segment performance based on segment operating income or loss from continuing operations. Summarized financial information concerning the Partnership's reportable segments is shown in the following tables:

Three Months Ended March 31, 2013	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	$	118,915	$	35,746	$	86,776		$	241,437		$	34,202	$	(17,908	)	(a)	$	257,731
Intersegment sales	49,135		8,538		(59,468		)	(1,795		)	13,100		(11,305		)		—
Cost of natural gas and natural gas liquids	132,226		33,234		14,528			179,988			—		—				179,988
Intersegment cost of natural gas, oil and condensate	19		—		11,093			11,112			—		(11,112		)		—
Operating costs and other expenses	17,134		4,829		6			21,969			14,116		18,847				54,932
Depreciation, depletion and amortization	13,845		5,002		84			18,931			20,929		377				40,237
Operating income (loss) from continuing operations	$	4,826	$	1,219	$	1,597		$	7,642		$	12,257	$	(37,325	)		$	(17,426	)
Capital Expenditures	$	18,303	$	1,776	$	154		$	20,233		$	34,050	$	1,667			$	55,950
Segment Assets	$	924,894	$	246,458	$	55,331		$	1,226,683		$	1,030,091	$	43,837		(b)	$	2,300,611

Three Months Ended March 31, 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	$	78,030	$	47,831		$	66,582		$	192,443		$	41,920	$	(8,608	)	(a)	$	225,755
Intersegment sales	25,446		9,523			(37,819		)	(2,850		)	15,339		(12,489		)		—
Cost of natural gas and natural gas liquids	71,488		45,508			13,458			130,454			—		—				130,454
Intersegment cost of natural gas, oil and condensate	—		—			13,631			13,631			—		(13,631		)		—
Operating costs and other expenses	12,238		5,129			—			17,367			14,832		16,841				49,040
Depreciation, depletion and amortization	9,517		7,135			30			16,682			22,220		392				39,294
Impairment	—		45,522			—			45,522			—		—				45,522
Operating income (loss) from continuing operations	$	10,233	$	(45,940	)	$	1,644		$	(34,063	)	$	20,207	$	(24,699	)		$	(38,555	)
Capital Expenditures	$	33,393	$	2,685		$	142		$	36,220		$	27,228	$	725			$	64,173
Segment Assets	$	596,243	$	359,347		$	32,982		$	988,572		$	990,275	$	51,112		(b)	$	2,029,959

______________________________

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

(b) Includes elimination of intersegment transactions.

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., all of which are subject to federal income taxes.

Effective Rate - The effective rate for the three months endedMarch 31, 2013 was a benefit of 3.3% compared to 0.2% for the three months endedMarch 31, 2012. 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 three months endedMarch 31, 2013 as compared to the three months endedMarch 31, 2012.

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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, the "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 March 31, 2013, a total of 1,913,998 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, where such restricted units are eligible to receive distributions, 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 are distributed to the awardees.

A summary of the restricted common units’ activity for the three months endedMarch 31, 2013 is provided below:

	Number of Restricted Units		Weighted Average Fair Value
Outstanding at December 31, 2012	2,608,035		$	9.38
Granted	126,975		$	9.07
Forfeited	(59,764	)	$	9.45
Outstanding at March 31, 2013	2,675,246		$	9.36

For the three months endedMarch 31, 2013 and 2012, non-cash compensation expense of approximately $2.6 million and $2.2 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 March 31, 2013, unrecognized compensation costs related to the outstanding restricted units under the LTIP totaled approximately $17.1 million. The remaining expense is to be recognized over a weighted average of 1.83 years.

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 March 31, 2013 and 2012, the Partnership had unvested restricted common units outstanding, which are considered dilutive securities. These units are considered in the diluted weighted average common units outstanding number in periods of net income. In periods of net losses, these units are excluded from the diluted weighted average common units outstanding number.

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

	Three Months Ended March 31,
	2013	2012
	(in thousands)
Weighted average units outstanding during period:
Common units - Basic and diluted	146,171	128,162

21

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.

The following table presents the Partnership's basic income per unit for the three months endedMarch 31, 2013:

	Total			Common Units			Restricted Common Units
	($ in thousands, except for per unit amounts)
Net loss	$	(33,514	)
Distributions	34,694			$	34,106		$	588
Assumed net loss after distribution to be allocated	(68,208		)	(68,208		)	—
Assumed net loss	$	(33,514	)	$	(34,102	)	$	588
Basic and diluted loss per unit				$	(0.23	)

The following table presents the Partnership's diluted income per unit for the three months endedMarch 31, 2012:

	Total			Common Units			Restricted Common Units
	($ in thousands, except for per unit amounts)
Net loss	$	(50,333	)
Distributions	29,366			$	28,769		$	597
Assumed net loss after distribution to be allocated	(79,699		)	(79,699		)	—
Assumed net loss to be allocated	$	(50,333	)	$	(50,930	)	$	597
Basic and diluted loss per unit				$	(0.40	)

NOTE 17. SUBSIDIARY GUARANTORS

The Partnership has issued registered debt securities guaranteed by its subsidiaries.  As of March 31, 2013, all guarantors were wholly-owned or available to be pledged and such guarantees were joint and several and full and unconditional.  Although the guarantees of our subsidiary guarantors are considered full and unconditional, the guarantees are subject to certain customary release provisions. Such guarantees may be released in the following customary circumstances:

• in connection with any sale or other disposition of all or substantially all of the properties or assets of that guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) an issuer or a restricted subsidiary of us;

• in connection with any sale or other disposition of capital stock of that guarantor to a person that is not (either before or after giving effect to such transaction) an issuer or a restricted subsidiary of us, such that, the guarantor ceases to be a restricted subsidiary of us as a result of the sale or other disposition;

• if we designate any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the applicable provisions of the indenture;

• upon legal defeasance or satisfaction and discharge of the indenture;

• upon the liquidation or dissolution of such guarantor provided no default or event of default has occurred that is continuing;

• at such time as such guarantor ceases to guarantee any other indebtedness of either of the issuers or any guarantor; or

• upon such guarantor consolidating with, merging into or transferring all of its properties or assets to us or another guarantor, and as a result of, or in connection with, such transaction such guarantor dissolving or otherwise ceasing to exist.

22

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 March 31, 2013 and December 31, 2012, and unaudited condensed consolidating statements of operations for the three months endedMarch 31, 2013 and 2012, and unaudited condensed consolidating statements of cash flows for the three months endedMarch 31, 2013 and 2012, 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

March 31, 2013

	Parent Issuer		Co-Issuer		Subsidiary Guarantors		Non-Guarantor Investments		Consolidating Entries			Total
	($ in thousands)
ASSETS:
Accounts receivable – related parties	$	705,871	$	—	$	—	$	—	$	(705,871	)	$	—
Other current assets	9,700		1		159,542		—		—			169,243
Total property, plant and equipment, net	1,781		—		1,986,749		—		—			1,988,530
Investment in subsidiaries	1,313,424		—		—		944		(1,314,368		)	—
Total other long-term assets	23,170		—		119,668		—		—			142,838
Total assets	$	2,053,946	$	1	$	2,265,959	$	944	$	(2,020,239	)	$	2,300,611
LIABILITIES AND EQUITY:
Accounts payable – related parties	$	—	$	—	$	705,871	$	—	$	(705,871	)	$	—
Other current liabilities	17,370		—		167,321		—		—			184,691
Other long-term liabilities	16,517		—		79,344		—		—			95,861
Long-term debt	1,122,560		—		—		—		—			1,122,560
Equity	897,499		1		1,313,423		944		(1,314,368		)	897,499
Total liabilities and equity	$	2,053,946	$	1	$	2,265,959	$	944	$	(2,020,239	)	$	2,300,611

Unaudited Condensed Consolidating Balance Sheet

December 31, 2012

	Parent Issuer		Co-Issuer		Subsidiary Guarantors		Non-Guarantor Investments		Consolidating Entries			Total
	($ in thousands)
ASSETS:
Accounts receivable – related parties	$	660,898	$	—	$	—	$	—	$	(660,898	)	$	—
Other current assets	27,688		1		154,275		—		—			181,964
Total property, plant and equipment, net	2,657		—		1,965,549		—		—			1,968,206
Investment in subsidiaries	1,324,293		—		—		958		(1,325,251		)	—
Total other long-term assets	22,061		—		121,985		—		—			144,046
Total assets	$	2,037,597	$	1	$	2,241,809	$	958	$	(1,986,149	)	$	2,294,216
LIABILITIES AND EQUITY:
Accounts payable – related parties	$	—	$	—	$	660,898	$	—	$	(660,898	)	$	—
Other current liabilities	6,734		—		174,780		—		—			181,514
Other long-term liabilities	9,386		—		81,839		—		—			91,225
Long-term debt	1,153,103		—		—		—		—			1,153,103
Equity	868,374		1		1,324,292		958		(1,325,251		)	868,374
Total liabilities and equity	$	2,037,597	$	1	$	2,241,809	$	958	$	(1,986,149	)	$	2,294,216

23

Unaudited Condensed Consolidating Statement of Operations

For the Three Months EndedMarch 31, 2013

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	(4,522	)	$	—	$	262,253		$	—		$	—		$	257,731
Cost of natural gas and natural gas liquids	—			—		179,988			—			—			179,988
Operations and maintenance	—			—		32,219			—			—			32,219
Taxes other than income	—			—		3,866			—			—			3,866
General and administrative	3,012			—		15,835			—			—			18,847
Depreciation, depletion and amortization	47			—		40,190			—			—			40,237
Loss from operations	(7,581		)	—		(9,845		)	—			—			(17,426		)
Interest expense, net	(16,304		)	—		(780		)	—			—			(17,084		)
Other non-operating income	2,281			—		2,334			—			(4,615		)	—
Other non-operating expense	(1,616		)	—		(3,158		)	(5		)	4,615			(164		)
Loss before income taxes	(23,220		)	—		(11,449		)	(5		)	—			(34,674		)
Income tax provision (benefit)	(575		)	—		(585		)	—			—			(1,160		)
Equity in earnings of subsidiaries	(10,869		)	—		—			—			10,869			—
Net loss	$	(33,514	)	$	—	$	(10,864	)	$	(5	)	$	10,869		$	(33,514	)

Unaudited Condensed Consolidating Statement of Operations

For the Three Months EndedMarch 31, 2012

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	(4,807	)	$	—	$	230,562		$	—		$	—		$	225,755
Cost of natural gas and natural gas liquids	—			—		130,454			—			—			130,454
Operations and maintenance	—			—		27,049			—			—			27,049
Taxes other than income	—			—		5,150			—			—			5,150
General and administrative	2,368			—		14,473			—			—			16,841
Depreciation, depletion and amortization	72			—		39,222			—			—			39,294
Impairment	—			—		45,522			—			—			45,522
Loss from operations	(7,247		)	—		(31,308		)	—			—			(38,555		)
Interest expense, net	(10,241		)	—		—			—			—			(10,241		)
Other non-operating income	2,260			—		2,745			—			(5,005		)	—
Other non-operating expense	(3,448		)	—		(3,176		)	(9		)	5,005			(1,628		)
Loss before income taxes	(18,676		)	—		(31,739		)	(9		)	—			(50,424		)
Income tax provision (benefit)	423			—		(514		)	—			—			(91		)
Equity in earnings of subsidiaries	(31,234		)	—		—			—			31,234			—
Net loss	$	(50,333	)	$	—	$	(31,225	)	$	(9	)	$	31,234		$	(50,333	)

24

Unaudited Condensed Consolidating Statement of Cash Flows

For the Three Months EndedMarch 31, 2013

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments		Consolidating Entries		Total
	($ in thousands)
Net cash flows (used in) provided by operating activities	$	(31,952	)	$	—	$	72,785		$	9	$	—	$	40,842
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(54		)	—		(70,083		)	—		—		(70,137		)
Purchase of intangible assets	—			—		(1,006		)	—		—		(1,006		)
Net cash flows used in investing activities	(54		)	—		(71,089		)	—		—		(71,143		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	171,300			—		—			—		—		171,300
Repayment of long-term debt	(202,000		)	—		—			—		—		(202,000		)
Proceeds from derivative contracts	1,044			—		—			—		—		1,044
Common unit issued in equity offerings	96,359			—		—			—		—		96,359
Issuance costs for equity offerings	(3,948		)	—		—			—		—		(3,948		)
Distributions to members and affiliates	(32,419		)	—		—			—		—		(32,419		)
Net cash flows provided by financing activities	30,336			—		—			—		—		30,336
Net increase (decrease) in cash and cash equivalents	(1,670		)	—		1,696			9		—		35
Cash and cash equivalents at beginning of year	1,670			1		(1,832		)	186		—		25
Cash and cash equivalents at end of year	$	—		$	1	$	(136	)	$	195	$	—	$	60

25

Unaudited Condensed Consolidating Statement of Cash Flows

For the Three Months EndedMarch 31, 2012

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments		Consolidating Entries			Total
	($ in thousands)
Net cash flows (used in) provided by operating activities	$	(27,422	)	$	—	$	66,395		$	16	$	—		$	38,989
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(316		)	—		(68,205		)	—		—			(68,521		)
Purchase of intangible assets	—			—		(1,099		)	—		—			(1,099		)
Contributions to subsidiaries	(2,581		)	—		—			—		2,581			—
Net cash flows used in investing activities	(2,897		)	—		(69,304		)	—		2,581			(69,620		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	169,450			—		—			—		—			169,450
Repayment of long-term debt	(134,750		)	—		—			—		—			(134,750		)
Proceeds from derivative contracts	3,617			—		—			—		—			3,617
Exercise of warrants	18,958			—		—			—		—			18,958
Distributions to members and affiliates	(27,340		)	—		—			—		—			(27,340		)
Contributions from parent	—			—		2,581			—		(2,581		)	—
Net cash flows provided by financing activities	29,935			—		2,581			—		(2,581		)	29,935
Net (decrease) increase in cash and cash equivalents	(384		)	—		(328		)	16		—			(696		)
Cash and cash equivalents at beginning of year	1,319			1		(572		)	129		—			877
Cash and cash equivalents at end of year	$	935		$	1	$	(900	)	$	145	$	—		$	181

NOTE 18. SUBSEQUENT EVENTS

Borrowing Base Redetermination

On April 17, 2013, the Partnership announced that the Upstream Segment component of the borrowing base under the Partnership's revolving credit facility was set at $375 million as part of its regularly scheduled semi-annual borrowing base redetermination by its commercial lenders. This represented a decrease of $25 million from the previous level of $400 million. The redetermined borrowing base was effective April 1, 2013, with no additional fees or increase in interest rate spread incurred. The Partnership's total borrowing base, including its Midstream Segment component (as last determined at December 31, 2012) and giving effect to the new Upstream Segment component, was approximately $827 million. The total borrowing capacity under the revolving credit facility is limited to the lower of the borrowing base and the total lender commitments, which remain unchanged at $820 million.

26

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

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report includes “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, 2012 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 and the indenture governing our Senior Notes;

• 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, including our recent acquisition of the BP Texas Panhandle midstream assets;

• 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.

27

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 our Annual Report on Form 10-K for the year ended December 31, 2012 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, 2012.

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 and condensate logistics and marketing; and

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

We conduct, evaluate and report on our Midstream Business within three segments—the Texas Panhandle Segment, the East Texas and Other Midstream Segment and the Marketing and Trading Segment. On October 1, 2012, we completed our acquisition of BP America Production Company's ("BP") Texas Panhandle midstream assets (the "Panhandle Acquisition"), as discussed further below. 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 and condensate logistics and marketing in the Texas Panhandle and Alabama and natural gas marketing and trading.  During the three months endedMarch 31, 2013, our Midstream Business had operating income from continuing operations of $7.6 million compared to an operating loss from continuing operations of $34.1 million during the three months endedMarch 31, 2012.  

We conduct, evaluate and report on our Upstream Business as one segment, which includes operated and non-operated wells located in the Mid-Continent (which includes areas in Oklahoma, Arkansas, and the Texas Panhandle); 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 months endedMarch 31, 2013, our Upstream Business had operating income of $12.3 million compared to operating income of $20.2 million during the three months endedMarch 31, 2012.  

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 months endedMarch 31, 2013, our Corporate and Other Segment incurred an operating loss of $37.3 million compared to an operating loss of $24.7 million during the three months endedMarch 31, 2012.  Results reflected a net (loss), realized and unrealized, on our commodity derivatives of $17.9 million during the three months endedMarch 31, 2013 compared to a net loss, realized and unrealized, on our commodity derivatives of $8.6 million during the three months endedMarch 31, 2012.  See "-Results of Operations - Corporate and Other Segment" for a further discussion of the impact of our commodity derivatives.

Acquisitions

On October 1, 2012, we completed the acquisition of BP's Texas Panhandle midstream assets, including the Sunray and Hemphill processing plants and associated 2,500 mile gathering system, for $230.6 million, which included certain closing adjustments.

In addition, on October 1, 2012, we entered into a 20-year, fixed-fee Gas Gathering and Processing Agreement with BP under which we will gather and process BP's natural gas production from the existing wells connected to the newly-acquired Panhandle System. Furthermore, BP has committed itself to us under the same agreement, and committed its farmees to us under substantially the same terms, with respect to all future natural gas production from new wells drilled within an initial two-year period from closing, subject to mutually-agreed extensions, and within a two-mile radius of any portion of our gathering system serving such BP connected wells.

28

Impairment

During the three months endedMarch 31, 2013, we recorded no impairment charges in our Midstream or Upstream Businesses. During the three months endedMarch 31, 2012, we recorded an impairment charge of $45.5 million in our Midstream Business related to certain plants and pipelines in our East Texas and Other Segment due to reduced throughput volumes as our producer customers curtailed their drilling activity in response to the continued depressed natural gas price environment. We did not incur any impairment charges in our Upstream Business during the three months endedMarch 31, 2012.

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

In order to lower sulfur dioxide (SO₂) emissions from our Big Escambia Creek processing facility in Alabama, as required by our existing air emissions permit, our operating subsidiary initiated the first phase of an SO₂ emissions reduction project at our Big Escambia Creek processing facility in December 2011. This phase of the project involved adding a Superclaus reactor to the existing sulfur recovery unit to achieve the desired reduction in SO₂ emissions. The new unit began operations on December 17, 2012, and as of year-end 2012 and March 31, 2013 had resulted in increased sulfur production and reductions in SO₂ emissions to levels well below the required permitted levels. The total cost of this phase was approximately $20.8 million net to our interest.

The second and final phase of our SO₂ emissions reduction project involves replacing or upgrading certain components of our existing sulfur recovery unit at the Big Escambia Creek processing facility. This phase is designed to improve the operational reliability of the processing facility, further increase the quantity of marketable sulfur recovered from the inlet gas stream, reduce the frequency of facility turnarounds, extend the facility's operating life and achieve cost savings across our operations in Southern Alabama. The improvements to our sulfur recovery unit will also further reduce SO₂ emissions, helping to ensure our compliance with the National Ambient Air Quality Standards the Environmental Protection Agency enacted in mid-2010. In the first of these planned upgrades, we expect to replace the incinerator portion of the sulfur recovery unit in 2014 at a cost of approximately $16.5 million net to our interest. We currently expect to complete the final upgrades in 2016.

Subsequent Events

Borrowing Base Redetermination

On April 17, 2013, we announced that the Upstream Segment component of the borrowing base under our revolving credit facility was set at $375 million as part of the regularly-scheduled semi-annual borrowing base redetermination by our commercial lenders. This represented a decrease of $25 million from the previous level of $400 million. The redetermined borrowing base was effective April 1, 2013, with no additional fees or increase in interest rate spread incurred. Our total borrowing base, including our Midstream Segment component (as last determined at December 31, 2012) and giving effect to the new Upstream Segment component, was approximately $827 million. The total borrowing capacity under the revolving credit facility is limited to the lower of the borrowing base and the total lender commitments, which remain unchanged at $820 million.

29

RESULTS OF OPERATIONS

Summary of Consolidated Operating Results

Below is a table of a summary of our consolidated operating results for the three months endedMarch 31, 2013and 2012.

	Three Months Ended March 31,
	2013			2012
	($ in thousands)
Revenues:
Natural gas, natural gas liquids, oil, condensate, sulfur and helium sales	$	254,200		$	222,713
Gathering, compression, processing and treating fees	20,942			11,511
Realized commodity derivative gains	9,998			6,163
Unrealized commodity derivative losses	(27,906		)	(14,771		)
Other revenue	497			139
Total revenue	257,731			225,755
Cost of natural gas, natural gas liquids, condensate and helium	179,988			130,454
Costs and expenses:
Operations and maintenance	32,219			27,049
Taxes other than income	3,866			5,150
General and administrative	18,847			16,841
Impairment	—			45,522
Depreciation, depletion and amortization	40,237			39,294
Total costs and expenses	95,169			133,856
Operating loss	(17,426		)	(38,555		)
Other income (expense):
Interest expense, net	(17,084		)	(10,241		)
Unrealized interest rate derivatives gains	1,495			1,796
Realized interest rate derivative losses	(1,651		)	(3,375		)
Other expense, net	(8		)	(49		)
Total other expense	(17,248		)	(11,869		)
Loss before income taxes	(34,674		)	(50,424		)
Income tax benefit	(1,160		)	(91		)
Net loss	$	(33,514	)	$	(50,333	)
Adjusted EBITDA(a)	$	53,617		$	62,824

________________________

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

30

Midstream Business (Three Segments)

Texas Panhandle Segment

	Three Months Ended March 31,
	2013		2012
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Natural gas, natural gas liquids, condensate and helium sales	$	106,394	$	73,080
Intersegment sales - natural gas and condensate	49,135		25,446
Gathering, compression, processing and treating fees	12,521		4,950
Total revenue	168,050		103,476
Cost of natural gas, natural gas liquids, condensate and helium (b)	132,245		71,488
Operating costs and expenses:
Operations and maintenance	17,134		12,238
Depreciation and amortization	13,845		9,517
Total operating costs and expenses	30,979		21,755
Operating income	$	4,826	$	10,233
Capital expenditures	$	18,303	$	33,393
Realized prices:
Condensate (per Bbl)	$	80.34	$	92.11
Natural gas (per MMbtu)	$	3.27	$	2.41
NGLs (per Bbl)	$	35.53	$	44.08
Production volumes:
Gathering volumes (Mcf/d)(a)	342,346		159,907
NGLs (net equity Bbls)	64,551		287,800
Condensate (net equity Bbls)	275,692		213,616
Natural gas (MMbtu/d)(a)	3,379		(7,463		)

_______________________

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

(b) Includes purchase of natural gas of $19 from the Upstream Segment for the three months endedMarch 31, 2013.

Revenues and Cost of Natural Gas, NGLs and Condensate. For the three months endedMarch 31, 2013, revenues minus cost of natural gas, NGLs and condensate for our Texas Panhandle Segment operations totaled $35.8 million compared to $32.0 million for the three months endedMarch 31, 2012. The addition of volumes from the Panhandle Acquisition, which closed on October 1, 2012, positively impacted the Texas Panhandle Segment's revenues minus cost of natural gas, NGLs, condensate and helium relative to the corresponding prior year period by $11.4 million during the three months endedMarch 31, 2013. Excluding the acquisition, revenues minus cost of natural gas, NGLs, condensate and helium decreased, primarily driven by the decline in condensate and NGL prices and lower NGL equity volumes. NGL equity volumes were lower in part due to the harsh winter storms in the Texas Panhandle in early January and late February 2013, which resulted in lower volumes and lower-than-normal NGL recovery rates. The impact of these lower recovery rates on equity NGL volumes was even more pronounced because we pay many producers in the Texas Panhandle on a contractually-fixed theoretical recovery rate for NGL volumes (i.e., fixed recovery contracts). As such, vis-a-vis many of these producers, we were “short” actual NGL volumes during the three months endedMarch 31, 2012. NGL equity volumes were also lower due to the our decision to reject ethane during the three months endedMarch 31, 2012.  Our election to reject ethane is an economic decision based on our contract portfolio and the price spread between ethane and natural gas. Despite the negative impact on ethane equity volumes, this decision is made to enhance our overall economics.

In addition, the results for the three months endedMarch 31, 2013 were impacted by adjustments to amounts recorded during the three months ended December 31, 2012. During the three months endedMarch 31, 2013, we received new information related to the assets acquired in the Panhandle Acquisition, which were operated by BP during the three months

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ended December 31, 2012. We were informed that the cost of natural gas, NGLs and condensate on the assets was higher than previously communicated. As a result, an adjustment was recorded.

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 the three months ended March 31, 2012, were negatively impacted by approximately $1.0 million due to the fractionation plant's downtime.

Our Texas Panhandle Segment lies within 14 counties in Texas and consists of our East Panhandle System and our West Panhandle 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; however, the limited drilling activity on this system is not sufficient to offset the natural declines of the existing wells. 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 expect drilling activity and the resulting volumes to continue during the remainder of 2013.

Operating Expenses. Operating expenses, including taxes other than income, for the three months endedMarch 31, 2013, increased $4.9 million as compared to the three months endedMarch 31, 2012. The increase was primarily driven by $4.5 million in costs related to the operation of the assets acquired in the Panhandle Acquisition. Excluding the acquisition, operating expenses increased primarily due to labor and related expenses associated with our Woodall Plant, which was placed into service on June 2, 2012.

Depreciation and Amortization. Depreciation and amortization expenses for the three months endedMarch 31, 2013 increased $4.3 million from the three months endedMarch 31, 2012. The increase was due to increased depreciation expense primarily associated with the new Woodall Plant, the assets acquired in the Panhandle Acquisition and other capital projects placed into service during the period.

Capital Expenditures. Capital expenditures for the three months endedMarch 31, 2013, decreased by $15.1 million compared to the three months endedMarch 31, 2012. The decrease was primarily driven by spending related to the construction of our Woodall Plant in 2012, partially offset by spending related to construction of our Wheeler Plant in 2013.

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 the Wheeler Plant to our existing processing infrastructure in the Texas Panhandle Segment 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 $64 million, of which $47.9 million had been spent through March 31, 2013.

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East Texas and Other Midstream Segment

	Three Months Ended March 31,
	2013		2012
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Natural gas, natural gas liquids and condensate sales	$	27,388	$	41,270
Intersegment sales - natural gas	8,538		9,523
Gathering, compression, processing and treating fees	8,358		6,561
Total revenue	44,284		57,354
Cost of natural gas, natural gas liquids, condensate and helium	33,234		45,508
Operating costs and expenses:
Operations and maintenance	4,829		5,129
Impairment	—		45,522
Depreciation and amortization	5,002		7,135
Total operating costs and expenses	9,831		57,786
Operating (loss) income	$	1,219	$	(45,940	)
Capital expenditures	$	1,776	$	2,685
Realized prices:
Condensate (per Bbl)	$	94.25	$	103.65
Natural gas (per MMbtu)	$	3.36	$	2.88
NGLs (per Bbl)	$	29.98	$	44.60
Production volumes:
Gathering volumes (Mcf/d)(a)	200,700		292,449
NGLs (net equity Bbls)	53,204		91,344
Condensate (net equity Bbls)	5,226		11,324
Natural gas (MMbtu/d)(a)	344		109

_________________________

(a) Gathering volumes (Mcf/d) and natural gas positions (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 months endedMarch 31, 2013, revenues minus cost of natural gas and NGLs for our East Texas and Other Midstream Segment totaled $11.1 million compared to $11.8 million for the three months endedMarch 31, 2012. During the three months endedMarch 31, 2013, we recorded revenues associated with deficiency payments of $2.1 million. 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 months endedMarch 31, 2013 and 2012, would have been $9.0 million and $11.8 million, respectively. The decrease, excluding deficiency payments, for the three months endedMarch 31, 2013 compared to the three months endedMarch 31, 2012, is primarily due to a decrease in gathering and equity volumes and lower condensate and NGL prices.

The gathering, NGL and condensate volumes for the three months endedMarch 31, 2013, decreased as compared to the three months endedMarch 31, 2012, due in part to the impact of Hurricane Isaac in August 2012, which caused significant damage to the Yscloskey Plant in Louisiana, in which we have a non-operated ownership interest. The owners of the Yscloskey Plant elected to shut down the facility following Hurricane Isaac. We estimate this negatively impacted 2013 gathering volumes by approximately 53 MMcf/d and 2013 NGL volumes by approximately 7,009 Bbls. The loss of customers on our Panola system, which we estimate negatively impacted 2013 gathering volumes by approximately 4 MMcf/d, NGL volumes by approximately 9,634 Bbls and condensate volumes by approximately 2,081 Bbls. Also contributing to the decrease in gathering, NGL and condensate volumes were 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 months endedMarch 31, 2013, decreased $0.3 million compared to the three months endedMarch 31, 2012.

Impairment. No impairment charges were recorded during the three months endedMarch 31, 2013. We recorded impairment charges of $45.5 million during the three months endedMarch 31, 2012 on certain assets due to reduced throughput volumes as our producer customers curtailed their drilling activity during that time period in response to the depressed natural gas price environment.

Depreciation and Amortization. Depreciation and amortization expenses for the three months endedMarch 31, 2013, decreased $2.1 million compared to the three months endedMarch 31, 2012. The decrease was a result of the impairment charge recorded during 2012.

Capital Expenditures. Capital expenditures for the three months endedMarch 31, 2013, decreased $0.9 million compared to the three months endedMarch 31, 2012 due to capital expenditures incurred in 2012 related to the Indian Springs plant.

Marketing and Trading Segment

	Three Months Ended March 31,
	2013			2012
	($ in thousands)
Revenues:
Natural gas, oil and condensate sales	$	86,713		$	66,582
Intersegment sales - natural gas and condensate	(59,468		)	(37,819		)
Gathering, compression, processing and treating fees	63			—
Total revenue	27,308			28,763
Cost of oil and condensate	14,528			13,458
Intersegment cost of oil and condensate	11,093			13,631
Operating costs and expenses:
Operations and maintenance	6			—
Depreciation and amortization	84			30
Total operating costs and expenses	90			30
Operating income	$	1,597		$	1,644
Capital Expenditures	$	154		$	142

Our Marketing and Trading Segment is comprised of our crude and condensate marketing operations and our natural gas marketing and trading activities. Our crude and condensate operations consist of developing and implementing marketing uplift strategies surrounding crude oil and condensate production in Alabama and in the Texas Panhandle. Through our natural gas marketing and trading activities, we seek to capitalize on 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, among other things: (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

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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 months endedMarch 31, 2013 and 2012, revenues minus cost of oil and condensate totaled $1.7 million. Revenues for the three months endedMarch 31, 2013, include an unrealized mark-to-market loss of $0.3 million and a gain of $0.2 million for the three months endedMarch 31, 2012 related to the financial derivatives and physical contracts.

Upstream Segment

	Three Months Ended March 31,
	2013		2012
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Oil and condensate	$	12,313	$	17,465
Intersegment sales - condensate	11,286		12,489
Natural gas	8,181		7,318
Intersegment sales - natural gas	1,814		2,850
NGLs	10,276		12,741
Sulfur	2,935		4,257
Other	497		139
Total revenue	47,302		57,259
Operating Costs and expenses:
Operations and maintenance	14,116		14,832
Depletion, depreciation and amortization	20,929		22,220
Total operating costs and expenses	35,045		37,052
Operating (loss) income	$	12,257	$	20,207
Capital expenditures	$	34,050	$	27,228
Realized average prices:
Oil and condensate (per Bbl)	$	84.56	$	92.46
Natural gas (per Mcf)	$	3.19	$	2.48
NGLs (per Bbl)	$	35.45	$	45.10
Sulfur (per Long ton)	$	110.34	$	145.70
Production volumes:
Oil and condensate (Bbl)	279,069		323,944
Natural gas (Mcf)	3,129,052		4,095,805
NGLs (Bbl)	289,866		278,731
Total (Mcfe)	6,542,662		7,711,855
Sulfur (Long ton)	26,598		28,992

Revenues. For the three months endedMarch 31, 2013, Upstream Segment revenues decreased by $10.0 million as compared to the three months endedMarch 31, 2012.  The decrease in revenues was due to lower realized oil, NGL and sulfur prices and lower volumes, partially offset by higher gas prices for the three months endedMarch 31, 2013 compared to the three months endedMarch 31, 2012.

On February 7, 2013, we suspended operations at our Flomaton facility in Escambia County, Alabama due to failure of certain plant equipment and insufficient inlet volumes to operate the facility's sulfur recovery unit. During this period, we unsuccessfully attempted to workover two wells connected to the facility. We resumed facility operations on April 18, 2013, after repairing the equipment and by diverting natural gas production from a nearby operated well. We estimate the lost revenue from these two events at approximately $0.6 million for the three months endedMarch 31, 2013, with increased facility

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expense of less than $0.1 million and increased operating expense of $2.4 million from the attempted workovers. In March 2012, we completed a scheduled turnaround of this facility which was for approximately twelve days. We estimate the revenue impact due to the loss of production was approximately $0.5 million and the turnaround expense was approximately $0.6 million for the three months endedMarch 31, 2012.

In March 2013, we booked an adjustment related to 2011 revenues for certain of our wells in East Texas processed at the third-party owned Eustace plant. These adjustments decreased previously reported revenues by approximately $0.8 million and were made by the third-party plant operator.

In addition, on December 20, 2012, we sold our Barnett Shale properties located in Denton and Tarrant Counties, Texas. During the three months ended March 31, 2012, the field averaged 6.2 MMcfe/d with revenue of $1.0 million and operating expenses of $0.9 million

Operating Expenses. Operating expenses, including severance and ad valorem taxes, decreased $0.7 million for the three months endedMarch 31, 2013 as compared to the three months endedMarch 31, 2012.  The decrease was primarily due to lower severance taxes resulting from the decreased sales and from a refund received from the state of Oklahoma for prior years taxes paid. These items were partially offset by the higher workover costs related to the two Alabama wells discussed above.

On July 19, 2012, one of our operated wells in Wayne County, Mississippi experienced an uncontrolled flow event during a well workover operation. We have Control of Well insurance and are currently pursuing reimbursement for this incident. We estimate the cost of the incident and the subsequent attempts to bring the well on-line to be in excess of $25.0 million. We have offset amounts paid above our deductible of $150,000 by recording a receivable for reimbursement up to $20 million, which is the maximum amount recoverable under our insurance policy. As of March 31, 2013, we had received $9.0 million as reimbursement for this incident and had a receivable of $10.8 million related to expected reimbursements. We have classified spending above the $20 million recoverable under our insurance policy as capital expenditures.

Depletion, Depreciation and Amortization. Depletion, depreciation and amortization expense decreased by $1.3 million for the three months endedMarch 31, 2013 as compared to the same period in the prior year.  The decrease was primarily a result of the impairment charge recorded during 2012 .

Capital Expenditures.  Capital expenditures increased by $6.8 million for the three months endedMarch 31, 2013 as compared to the three months endedMarch 31, 2012.   During the three months endedMarch 31, 2013, we drilled two gross operated wells, completed one gross operated well and participated in six gross non-operated wells on leases in the Mid-Continent region. One of the two operated wells drilled during the three months ended March 31, 2013 was plugged and abandoned due to mechanical and hole conditions. Additionally, during the three months endedMarch 31, 2013, we conducted seven capital workovers and one unsuccessful recompletion across our operations.

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Corporate and Other Segment

	Three Months Ended March 31,
	2013			2012
	($ in thousands)
Revenues:
Realized commodity derivative gains	$	9,998		$	6,163
Unrealized commodity derivative losses	(27,906		)	(14,771		)
Intersegment elimination - Sales of natural gas and condensate	(11,305		)	(12,489		)
Total revenue	(29,213		)	(21,097		)
Intersegment elimination - Cost of natural gas and condensate	(11,112		)	(13,631		)
General and administrative	18,847			16,841
Depreciation and amortization	377			392
Operating loss	(37,325		)	(24,699		)
Other income (expense):
Interest expense, net	(17,084		)	(10,241		)
Unrealized interest rate derivatives gains	1,495			1,796
Realized interest rate derivative losses	(1,651		)	(3,375		)
Other expense, net	(8		)	(49		)
Total other expense	(17,248		)	(11,869		)
Loss before income taxes	(54,573		)	(36,568		)
Income tax benefit	(1,160		)	(91		)
Segment income loss	$	(53,413	)	$	(36,477	)

Revenues. Our Corporate and Other Segment's revenue consists of our intersegment eliminations and our commodity derivative activity (excluding any risk management activity associated with our natural gas marketing and trading activity). Our commodity derivative activity impacts 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 months endedMarch 31, 2013, unrealized losses in our commodity derivative portfolio increased by $13.1 million, as compared to the three months endedMarch 31, 2012, due to increases in the natural gas and crude oil forward curves. 

During the three months endedMarch 31, 2013, realized gains in our commodity derivatives increased by $3.8 million compared to realized commodity derivative gains during the three months endedMarch 31, 2012. The increase in the realized gains for the three months endedMarch 31, 2013, as compared to the same period in the prior year, was due to lower oil and NGL market prices, partially offset by higher natural gas market prices, 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.

Intersegment Eliminations. During the three months endedMarch 31, 2013 and 2012, our Upstream Segment sold natural gas and condensate to the Marketing and Trading Segment within our Midstream Business for resale. In addition, during the three months endedMarch 31, 2013, our Upstream Segment sold natural gas to our Panhandle Segment.

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General and Administrative Expenses. General and administrative expenses increased by $2.0 million for the three months endedMarch 31, 2013 as compared to the same periods in 2012. This increase was primarily due to higher salaries and benefits, which was due to (i) an increase in our headcount due to the Panhandle Acquisition and (ii) increased equity compensation expense due to additional grants.

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. During July 2012, in conjunction with our issuance of $250.0 million of senior unsecured notes, which increased our fixed interest rate exposure, we terminated the full $200.0 million notional amount of our existing 4.295% and 4.095% fixed rate interest rate swaps. During the three months endedMarch 31, 2013, our realized settlement losses decreased by $1.7 million as compared to the three months endedMarch 31, 2012, due to the transactions described above. For the three months endedMarch 31, 2013, we recognized unrealized gains of $1.5 million as compared to unrealized gains of $1.8 million during the same period in 2012. These unrealized mark-to-market losses did not have any impact on cash activities for the period, and are excluded by definition from our calculation of Adjusted EBITDA.

Interest expense increased by $6.8 million during the three months endedMarch 31, 2013 as compared to the three months endedMarch 31, 2012.  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 July 13, 2012, we issued an additional $250 million of senior unsecured notes.

Income Tax (Benefit) Provision. Income tax provision for 2013 and 2012 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., all of which are subject to federal income taxes.

Adjusted EBITDA

Adjusted EBITDA, as defined under "-Liquidity and Capital Resources - Non-GAAP Financial Measures," decreased by $9.2 million from $62.8 million for the three months endedMarch 31, 2012 to $53.6 million for the three months endedMarch 31, 2013.

As described above, revenues minus cost of natural gas and NGLs for the Midstream Business (excluding unrealized gains from the Marketing and Trading Segment) increased by $3.5 million during the three months endedMarch 31, 2013 as compared to the comparable period in 2012. The Upstream Segment revenues (excluding imbalances) decreased $9.8 million during the three months endedMarch 31, 2013 as compared to the comparable period in 2012. Intercompany eliminations of revenues minus cost of natural gas and condensate resulted in a $1.3 million decrease during the three months endedMarch 31, 2013 as compared to the comparable period in 2012. Our Corporate and Other Segment's realized commodity derivatives gains increased by $3.8 million during the three months endedMarch 31, 2013, as compared to the comparable period in 2012. This resulted in total incremental revenues minus cost of natural gas and NGLs decreasing by $3.8 million during the three months endedMarch 31, 2013 as compared to the comparable period in 2012.  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 $4.6 million for the three months endedMarch 31, 2013 as compared to the same period in 2012, and operating expenses (including taxes other than income) for the Upstream Segment decreased $0.7 million for the three months endedMarch 31, 2013 as compared to the comparable period in 2012.

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 by $1.6 million during the three months endedMarch 31, 2013 as compared to the respective period in 2012.

As a result, revenues (excluding the impact of unrealized commodity derivative activity) minus cost of natural gas, NGLs and condensate for the three months endedMarch 31, 2013, as compared to the same period in 2012, decreased by $3.8 million, operating expenses increased by $3.9 million and general and administrative expenses increased by $1.6 million.  The decreases in revenues minus the cost of natural gas, NGLs and condensate and the increases in operating costs and general and

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administrative expenses, resulted in an decrease to Adjusted EBITDA for the three months endedMarch 31, 2013, as compared to the three months endedMarch 31, 2012.

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.

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.

Equity Offerings

On May 31, 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. During the three months endedMarch 31, 2013, no units were issued under this program. As of March 31, 2013, a total of 834,327 units had been issued under this program for net proceeds of approximately $7.3 million. As of March 31, 2013, issuance costs associated with the program totaled $0.6 million.

During the first quarter of 2013, we closed an underwritten public offering of 10,350,000 common units for net proceeds of approximately $92.5 million. The net proceeds were used to repay a portion of the outstanding borrowings under our revolving credit facility.

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 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 2013 capital budget anticipates that we will spend approximately $208 million in total, of which $70 million relates to maintenance capital expenditures and $138 million relates to growth capital expenditures. Our capital expenditures were approximately $56.0 million for the three months endedMarch 31, 2013, of which $12.7 million were related to maintenance capital expenditures and $43.2 million were related to growth capital expenditures.

In order to lower sulfur dioxide (SO₂) emissions from our Big Escambia Creek processing facility in Alabama, as required by our existing air emissions permit, our operating subsidiary initiated the first phase of an SO₂ emissions reduction project at our Big Escambia Creek processing facility in December 2011. This phase of the project involved adding a Superclaus reactor to the existing sulfur recovery unit to achieve the desired reduction in SO₂ emissions. The new unit began operations on December 17, 2012, and as of year-end 2012 and March 31, 2013 had resulted in increased sulfur production and

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reductions in SO₂ emissions to levels well below the required permitted levels. The total cost of this phase was approximately $20.8 million net to our interest.

The second and final phase of our SO₂ emissions reduction project involves replacing or upgrading certain components of our existing sulfur recovery unit at the Big Escambia Creek processing facility. This phase is designed to improve the operational reliability of the processing facility, further increase the quantity of marketable sulfur recovered from the inlet gas stream, reduce the frequency of facility turnarounds, extend the facility's operating life and achieve cost savings across our operations in Southern Alabama. The improvements to our sulfur recovery unit will also further reduce SO₂ emissions, helping to ensure our compliance with the National Ambient Air Quality Standards the Environmental Protection Agency enacted in mid-2010. In the first of these planned upgrades, we expect to replace the incinerator portion of the sulfur recovery unit in 2014 at a cost of approximately $16.5 million net to our interest. We currently expect to complete the final upgrades in 2016.

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 and cash equivalents on hand at the end of that quarter (or, if the general partner chooses, on the date of determination) less the amount of cash reserves established by the general partner 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 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 and documentation agent and swingline lender, Bank of America, N.A. and The Royal Bank of Scotland plc, as co-syndication agents, and the other lenders who are parties to the Credit Agreement.

On December 31, 2012, aggregate commitments under the Credit Agreement increased from $675 million to $820 million. We have the option to request further increases, subject to the terms and conditions of the Credit Agreement, 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 March 31, 2013, our borrowing base exceeded our total commitments of $820 million, and we had approximately $215.4 million of availability under the revolving credit facility, based on total commitments and before considering covenant limitations. Availability under the revolving credit facility as of March 31, 2013, based on covenant limitations, was approximately $52 million.

Concurrent with the increase in commitments on December 31, 2012, we and our lending group agreed to amend the Credit Agreement to: (i) allow for a temporary step-up in the Total Leverage Ratio from 4.50x to 4.75x through the third quarter of 2013; (ii) institute a new Senior Secured Leverage Ratio of 2.85x through the third quarter of 2013; and (iii) increase the amount of permitted "other Investments" as defined in the Credit Agreement.

Senior Unsecured Notes

On May 27, 2011, we completed the sale of $300 million of our 8.375% senior unsecured notes due 2019 (the "Senior Notes") through a private placement, which were exchanged for registered notes on February 15, 2012. The Senior 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 13, 2012, we completed the sale of an additional $250.0 million of Senior 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.

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Debt Covenants

Our revolving credit facility requires us to maintain certain leverage, current and interest coverage ratios. As of March 31, 2013, we were in compliance with all of our debt covenants, and we believe that we will remain in compliance with our financial covenants through 2013. Our financial covenant requirements and actual ratios as of March 31, 2013, are as follows:

	Per Credit Agreement	Actual
Interest coverage ratio	2.5 (Min)	3.5
Total leverage ratio	4.75 (Max)	4.5
Senior secured leverage ratio	2.85 (Max)	2.3
Current ratio	1.0 (Min)	2.2

Our long-term target is to maintain our ratio of outstanding debt to Adjusted EBITDA, or "total leverage ratio," at or below 3.5 to 1.0 on a long-term basis, while acknowledging that at times this ratio may exceed our targeted levels, particularly following acquisitions or major development projects. For example, our total leverage ratio exceeded our long-term target as of March 31, 2013, due in part to: (i) our borrowings related to our acquisition of BP America Production Company's Texas Panhandle midstream assets on October 1, 2012; (ii) our funding of ongoing drilling and other capital projects; and (iii) lower NGL prices and other factors negatively impacting our Adjusted EBITDA. We expect our efforts to maintain or reduce our leverage ratio during 2013 will be primarily through investing in attractive growth opportunities that will increase our Adjusted EBITDA.

Our Senior Notes were 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 March 31, 2013, we were in compliance with our covenants under the Senior Notes indenture.

For a further discussion of our revolving credit facility and Senior 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, 2012.

Cash Flows

Cash Distributions

On January 28, 2013, we declared our fourth quarter 2012 cash distribution of $0.22 per unit to our common unitholders of record as of the close of business on February 7, 2013. The distribution was paid on February 14, 2013.

On April 23, 2013, we declared our first quarter 2013 cash distribution of $0.22 per unit to our common unitholders of record as of the close of business on May 7, 2013 (excluding certain restricted unit grants). The distribution will be paid on May 15, 2013.

Working Capital

Working capital is the amount by which current assets exceed current liabilities. As of March 31, 2013, working capital was a negative $15.4 million as compared to a positive $0.5 million as of December 31, 2012.

The net decrease in working capital of $15.9 million from December 31, 2012 to March 31, 2013, resulted primarily from the following factors:

• risk management net working capital balance decreased by a net $20.8 million as a result of changes in current portion of mark-to-market unrealized positions as a result of increases to the forward natural gas, oil and NGL price curves;

• accrued liabilities increased by $12.8 million primarily reflecting accrued interest.

These decreases were partially offset by the following factors:

41

• accounts payable decreased by $11.8 million primarily as a result of lower volumes and the timing of payments of unbilled expenditures related primarily to capital expenditures; and

• trade accounts receivable increased by $5.5 million primarily from the timing of receipts.

Cash Flows for the Three Months Ended March 31,2013 Compared to the Three Months Ended March 31,2012

Cash Flow from Operating Activities. Cash flows from operating activities increased $1.9 million during the three months endedMarch 31, 2013, as compared to the three months endedMarch 31, 2012. This increase was primarily due to an increase in our results of operations, excluding unrealized gains on derivatives, from our Panhandle Acquisition and declines in oil and NGL prices during the three months endedMarch 31, 2013, resulting in us realizing net settlement gains on our commodity derivatives, of which $1.0 million was reclassed to cash flows from financing activities. During the three months endedMarch 31, 2012, $3.6 million was reclassed to cash flows from financing activities. During the three months endedMarch 31, 2013, we did not make any payments to unwind any derivative contracts. We made a payment of $1.1 million to partially unwind certain commodity derivative contracts during the three months endedMarch 31, 2012.

Cash Flows from Investing Activities. Cash flows used in investing activities for the three months endedMarch 31, 2013 were $71.1 million as compared to cash flows used in investing activities of $69.6 million for the three months endedMarch 31, 2012. The key difference between periods was the $1.6 million increase in capital expenditures, in particular, spending related to our Wheeler Plant, as well as increased drilling in our Upstream Segment.  

Cash Flows from Financing Activities. Cash flows provided by financing activities during the three months endedMarch 31, 2013 were $30.3 million as compared to cash flows provided by financing activities of $29.9 million for the three months endedMarch 31, 2012. Key differences between periods included net proceeds of $92.4 million from our equity offering which closed on March 12, 2013. Cash outflows related to our net prepayments on our revolving credit facility were $30.7 million during the three months endedMarch 31, 2013, as compared to net proceeds of $34.7 million during the three months endedMarch 31, 2012. Cash outflows related to our distributions increased to $32.4 million during the three months endedMarch 31, 2013, as compared to $27.3 million during the three months endedMarch 31, 2012, as a result of an increase in our units outstanding. During the three months endedMarch 31, 2012, we received $19.0 million from the exercise of warrants.

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.

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 of this Form 10-Q.

Off-Balance Sheet Obligations.

We had no off-balance sheet transactions or obligations as of March 31, 2013. 

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 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.

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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 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.

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

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

	Three Months Ended March 31,
	2013			2012
	($ 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	$	40,842		$	38,989
Add (deduct):
Depreciation, depletion, amortization and impairment	(40,237		)	(84,816		)
Amortization of debt issuance costs	(1,036		)	(699		)
Risk management portfolio value changes	(26,664		)	(11,715		)
Reclassing financing derivative settlements	1,044			3,617
Other	(3,695		)	(2,271		)
Accounts receivable and other current assets	4,551			9,664
Accounts payable and accrued liabilities	(8,511		)	(2,913		)
Other assets and liabilities	192			(189		)
Net loss	(33,514		)	(50,333		)
Add (deduct):
Interest expense, net	18,743			13,664
Depreciation, depletion, amortization and impairment	40,237			84,816
Income tax expense (benefit)	(1,160		)	(91		)
EBITDA	24,306			48,056
Add:
Unrealized losses from derivative activity	26,664			12,772
Restricted unit compensation expense	2,647			2,194
Non-cash mark-to-market Upstream imbalances	—			(198		)
ADJUSTED EBITDA	$	53,617		$	62,824

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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. Historically, we have hedged a substantial portion of our exposure to changes in NGL prices with crude or natural gas hedges, which we call "proxy hedges." To the extent the price of the underlying physical product (NGL) does not correlate with the price of the designated proxy hedge product (crude or natural gas), these hedges can be ineffective in reducing our commodity price exposure. 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 March 31, 2013, our commodity hedge portfolio totaled a net asset position of $24.9 million, consisting of assets aggregating $36.2 million and liabilities aggregating $11.2 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-

45

based variable-rate payments to fixed-rate payments. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense.

We have not designated our contracts as accounting hedges. As a result, we mark our derivatives to market with the resulting change in fair value included in our statement of operations. As of March 31, 2013, the fair value liability of these interest rate contracts totaled approximately $13.3 million. For additional information about our interest rate swaps and related fair values, see Part I, Item 1. Financial Statement Notes 10 and 11.

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 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 at March 31, 2013, not including counterparties of our marketing and trading business, included 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, Regions Financial Corporation 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.

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, 2012, 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, 2012.

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

None

Item 3. Defaults Upon Senior Securities

None

Item 4. Mine Safety Disclosures

None

Item 5. Other Information

None

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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**†	Eagle Rock Energy G&P, LLC 2013 Short-Term Incentive Bonus Plan (incorporated by reference to Exhibit 10.1 to the registrant's current report on Form 8-K filed on February 11, 2013)
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

** Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto.

*** Furnished herewith

† Portions of this exhibit have been omitted pursuant to a request for confidential treatment.

48

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 May 3, 2013.

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

49

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**†	Eagle Rock Energy G&P, LLC 2013 Short-Term Incentive Bonus Plan (incorporated by reference to Exhibit 10.1 to the registrant's current report on Form 8-K filed on February 11, 2013)
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

** Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto.

*** Furnished herewith

† Portions of this exhibit have been omitted pursuant to a request for confidential treatment.