Eagle Rock Energy Partners L P (EROC) 10-Q 2014 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, 2014

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 159,759,188 common units outstanding as of April 28, 2014.

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements	2
	Unaudited Condensed Consolidated Balance Sheets as of March 31, 2014 and December 31, 2013	2
	Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2014 and 2013	3
	Unaudited Condensed Consolidated Statement of Members' Equity for the three months ended March 31, 2014	4
	Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2014 and 2013	5
	Notes to Unaudited Condensed Consolidated Financial Statements	6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	50
Item 4.	Controls and Procedures	51
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	52
Item 1A.	Risk Factors	52
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	53
Item 3.	Defaults Upon Senior Securities	53
Item 4.	Mine Safety Disclosures	53
Item 5.	Other Information	53
Item 6.	Exhibits	53

1

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, 2014		December 31, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	5,623	$	76
Accounts receivable (a)	165,852		145,963
Risk management assets	5,740		9,162
Prepayments and other current assets	12,601		8,183
Total current assets	189,816		163,384
PROPERTY, PLANT AND EQUIPMENT — Net	1,838,925		1,828,768
INTANGIBLE ASSETS — Net	104,149		105,620
DEFERRED TAX ASSET	2,224		1,438
RISK MANAGEMENT ASSETS	1,451		5,461
OTHER ASSETS	18,753		22,879
TOTAL	$	2,155,318	$	2,127,550
LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	202,693	$	170,124
Accrued liabilities	42,442		29,970
Taxes payable	—		149
Risk management liabilities	15,334		11,023
Total current liabilities	260,469		211,266
LONG-TERM DEBT	1,269,433		1,252,062
ASSET RETIREMENT OBLIGATIONS	46,269		45,849
DEFERRED TAX LIABILITY	38,164		37,953
RISK MANAGEMENT LIABILITIES	878		3,848
OTHER LONG TERM LIABILITIES	5,258		2,693
COMMITMENTS AND CONTINGENCIES (Note 12)
MEMBERS' EQUITY (b)	534,847		573,879
TOTAL	$	2,155,318	$	2,127,550

________________________ 

(a) Net of allowance for bad debt of $985 as of March 31, 2014 and $1,188 as of December 31, 2013.

(b) 156,644,153 and 156,644,153 common units were issued and outstanding as of March 31, 2014 and December 31, 2013, respectively. These amounts do not include unvested restricted common units granted under the Partnership's long-term incentive plan of 2,754,383 and 2,743,807 as of March 31, 2014 and December 31, 2013, respectively.

See accompanying notes to unaudited condensed consolidated financial statements.  

2

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit amounts)

	Three Months Ended March 31,
	2014			2013
REVENUE:
Natural gas, natural gas liquids, oil, condensate, sulfur and helium sales	$	340,465		$	254,200
Gathering, compression, processing and treating fees	22,397			20,942
Commodity risk management losses, net	(14,944		)	(17,908		)
Other revenue	156			497
Total revenue	348,074			257,731
COSTS AND EXPENSES:
Cost of natural gas, natural gas liquids, condensate and helium	244,973			179,988
Operations and maintenance	34,671			32,219
Taxes other than income	5,667			3,866
General and administrative	21,391			18,847
Impairment	2,097			—
Depreciation, depletion and amortization	40,508			40,237
Total costs and expenses	349,307			275,157
OPERATING LOSS	(1,233		)	(17,426		)
OTHER INCOME (EXPENSE):
Interest expense, net	(17,986		)	(17,084		)
Interest rate risk management losses, net	(290		)	(156		)
Other expense, net	(7		)	(8		)
Total other expense	(18,283		)	(17,248		)
LOSS BEFORE INCOME TAXES	(19,516		)	(34,674		)
INCOME TAX BENEFIT	(953		)	(1,160		)
NET LOSS	$	(18,563	)	(33,514		)

NET LOSS PER COMMON UNIT—BASIC AND DILUTED:
Net Loss
Common units - Basic and diluted	$	(0.12	)	$	(0.23	)
Weighted Average Units Outstanding
Common units - Basic and diluted	156,644			146,171

 See accompanying notes to unaudited condensed consolidated financial statements.

3

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF MEMBERS’ EQUITY

FOR THE THREE MONTHS ENDED MARCH 31, 2014

($ in thousands, except unit amounts)

	Number of Common Units	Common Units			Total
BALANCE — December 31, 2013	156,644,153	$	573,879		$	573,879
Net loss	—	(18,563		)	(18,563		)
Distributions	—	(23,801		)	(23,801		)
Equity based compensation	—	3,332			3,332
BALANCE — March 31, 2014	156,644,153	$	534,847		$	534,847

 See accompanying notes to unaudited condensed consolidated financial statements.  

4

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

($ in thousands)

	Three Months Ended March 31,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(18,563	)	$	(33,514	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	40,508			40,237
Impairment	2,097			—
Amortization of debt issuance costs	1,228			1,036
Loss from risk management activities, net	16,221			19,214
Derivative settlements	(5,740		)	6,406
Equity-based compensation	3,332			2,647
Other	222			1,048
Changes in assets and liabilities—net of acquisitions:
Accounts receivable	(19,889		)	(4,296		)
Prepayments and other current assets	(4,418		)	(255		)
Accounts payable	35,797			(40		)
Accrued liabilities	15,339			8,551
Other assets	3,250			436
Other current liabilities	(831		)	(628		)
Net cash provided by operating activities	68,553			40,842
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(53,938		)	(70,137		)
Purchase of intangible assets	(554		)	(1,006		)
Net cash used in investing activities	(54,492		)	(71,143		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	144,250			171,300
Repayment of long-term debt	(127,050		)	(202,000		)
Payment of debt issuance costs	(205		)	—
Proceeds from derivative contracts	(1,708		)	1,044
Common unit issued in equity offerings	—			96,359
Issuance costs for equity offerings	—			(3,948		)
Distributions to members and affiliates	(23,801		)	(32,419		)
Net cash (used in) provided by financing activities	(8,514		)	30,336
NET INCREASE IN CASH AND CASH EQUIVALENTS	5,547			35
CASH AND CASH EQUIVALENTS—Beginning of period	76			25
CASH AND CASH EQUIVALENTS—End of period	$	5,623		$	60
NONCASH INVESTING AND FINANCING ACTIVITIES:
Investments in property, plant and equipment, not paid	$	6,241		$	16,580
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid—net of amounts capitalized	$	5,558		$	5,310
Cash paid for taxes	$	—		$	2

See accompanying notes to unaudited condensed consolidated financial statements.  

5

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. ORGANIZATION AND DESCRIPTION OF BUSINESS

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.

Recent Developments—On December 23, 2013, the Partnership announced that it had entered into a definitive agreement to contribute its Midstream Business (the "Midstream Business Contribution") to Regency Energy Partners LP ("Regency") for total consideration of up to $1.325 billion, consisting of $200 million of newly issued Regency common units (8,245,859 common units, calculated by taking the volume-weighted average price of a single Regency common unit for the ten trading days immediately preceding the announcement date) and a combination of cash and assumed debt, subject to certain closing conditions. As part of the transaction, Regency is conducting an offer to exchange the Partnership's $550 million of outstanding senior unsecured notes for an equivalent amount of Regency senior unsecured notes with the same tenor, coupon and a comparable covenant package. The cash portion of the purchase price will be reduced by the amount of notes exchanged subject to a 10% adjustment factor, such that if all $550 million of bonds are exchanged, the total consideration will equal $1.27 billion ($1.325 billion less $55 million) consisting of $200 million in Regency units, $550 million of assumed debt and $520 million of cash proceeds.

The Midstream Business Contribution was approved by the Partnership's common unitholders on April 29, 2014. As of that date, all significant closing conditions for the transaction had been satisfied other than the approval from the Federal Trade Commissions ("FTC") anti-trust review. On February 27, 2014, the Partnership and Regency received a Request for Additional Information and Documentary Materials ("Second Request") from the FTC in connection with the Midstream Business Contribution. On April 30, 2014, the Partnership and Regency certified their substantial compliance with the FTC's Second Request and entered into a timing agreement with the FTC agreeing to extend the FTC's review period until June 30, 2014, unless the FTC completes its investigation earlier.

As the sale of the Midstream Business at March 31, 2014 remained conditioned upon, among other things, the approval of the Partnership's common unitholders (see above and Note 18) and the expiration or termination of all applicable waiting periods under the Hart-Scott-Rodino Antitrust Improvement Act of 1976, as amended, the Partnership has not classified the assets of its Midstream Business as assets-held-for-sale or the operations as discontinued.

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, 2013. 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

6

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

flows for the respective periods. Operating results for the three months endedMarch 31, 2014 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2014.

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, 2013. 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, 2014 and December 31, 2013, the Partnership had $0.3 million and $1.0 million, respectively, of crude oil finished goods inventory, which is recorded as part of Other Current Assets within the unaudited condensed consolidated balance sheet.

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

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

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

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

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

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

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

For its oil and natural gas long-lived assets, accounted for utilizing the successful efforts method, the Partnership reviews its proved properties at the depletion unit 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.

7

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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, sulfur and helium; 

• 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, sulfur and helium 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, the Partnership had long-term imbalance payables totaling $0.3 million and $0.3 million as of March 31, 2014 and December 31, 2013, respectively.

Transportation and Exchange Imbalances—In the course of transporting natural gas and NGLs for others, the Partnership may receive for redelivery different quantities of natural gas or NGLs than the quantities actually delivered. These transactions result in transportation and exchange imbalance receivables or payables which are recovered or repaid through the receipt or delivery of natural gas or NGLs in future periods, if not subject to cash out provisions. Imbalance receivables are included in accounts receivable and imbalance payables are included in accounts payable on the unaudited condensed consolidated balance sheets and marked-to-market using current market prices in effect for the reporting period of the outstanding imbalances. For the Midstream Business, as of March 31, 2014, the Partnership had imbalance receivables totaling $1.8 million and imbalance payables totaling $0.6 million. For the Midstream Business, as of December 31, 2013, the Partnership had imbalance receivables totaling $0.7 million and imbalance payables totaling $1.6 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—The prior period within the unaudited condensed consolidated statements of cash flows has been reclassified to conform to current period presentation. Amounts have been reclassified to new rows titled “Loss from risk management activities, net” that combines settled and mark-to-market gains/losses on derivative instruments and “Derivative settlements” that includes cash attributable to derivative instruments that settled during the periods. The revisions to the cash flow presentation had no impact on “Net cash provided by operating activities.”

8

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS

In February 2013, the Financial Accounting Standards Board ("FASB") issued new guidance related to obligations resulting from joint and several liability arrangements. The new guidance provides for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. The amendments in this update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013 and did not have a material impact on the Partnership’s unaudited condensed consolidated financial statements.

On April 10, 2014, the FASB issued new guidance which amends the definition of a discontinued operation and requires entities to provide additional disclosures about disposal transactions that do not meet the discontinued-operations criteria. Under the new guidance, a discontinued operation is defined as a disposal of a component or group of components that is disposed of or is classified as held for sale and represents a strategic shift that has or will have a major effect on an entity's operations and financial results. The new guidance is effective prospectively for all disposals (except disposals classified as held for sale before the adoption date) or components initially classified as held for sale in periods beginning on or after December 15, 2014, with early adoption permitted. The Partnership is currently evaluating the potential impact, if any, of the adoption of this new guidance on its financial statements.

NOTE 4. PROPERTY, PLANT AND EQUIPMENT

Fixed assets consisted of the following:

	March 31, 2014			December 31, 2013
	($ in thousands)
Land	$	2,877		$	2,877
Plant	519,392			521,103
Gathering and pipeline	782,577			777,446
Equipment and machinery	58,153			53,999
Vehicles and transportation equipment	4,017			4,001
Office equipment, furniture, and fixtures	1,328			1,309
Computer equipment	17,117			14,806
Linefill	5,142			5,180
Proved properties	1,195,188			1,156,896
Unproved properties	10,276			10,022
Construction in progress	25,457			33,824
	2,621,524			2,581,463
Less: accumulated depreciation, depletion and amortization	(782,599		)	(752,695		)
Net property, plant and equipment	$	1,838,925		$	1,828,768

9

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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,
		2014		2013
	($ in thousands)
Depreciation		$	18,861	$	16,395
Depletion		$	19,672	$	20,871
Capitalized interest costs		$	144	$	355
Impairment expense:
Plant assets (a)		$	132	$	—
Pipeline assets (a)		$	1,904	$	—

________________________________

(a) During the three months ended March 31, 2014, the Partnership incurred impairment charges in its Midstream Business related to certain plants and pipelines in its East Texas and Other Segment due to the loss of two customers.

NOTE 5. ASSET RETIREMENT OBLIGATIONS

The Partnership recognizes asset retirement obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. The Partnership records the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The Partnership makes estimates of property abandonment costs that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to significant revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors that may be difficult to predict. Although uncertainty about the timing and/or method of settlement may exist and may be conditional upon a future event, the obligation to perform the asset retirement activity is unconditional. Accordingly, the Partnership is required to recognize a liability for the fair value of a conditional asset retirement obligation upon initial recognition if the fair value of the liability can be reasonably estimated. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of (i) remediation costs, (ii) remaining lives, (iii) future inflation factors and (iv) a credit-adjusted risk free interest rate.

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

	2014			2013
	($ in thousands)
Asset retirement obligations—January 1 (a)	$	58,964		$	48,755
Additional liabilities	39			746
Liabilities settled	(682		)	(570		)
Revision to liabilities	(105		)	—
Accretion expense	980			840
Asset retirement obligations—March 31 (a)	$	59,196		$	49,771

_____________________________________

(a) As of March 31, 2014 and December 31, 2013, $12.9 million and $13.1 million, respectively, were included within accrued liabilities in the Unaudited Condensed Consolidated Balance Sheets.

During the three months endedMarch 31, 2014, the Partnership made revisions of $0.1 million to decrease certain asset retirement obligations due to changes in the estimated costs to remediate.

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, 2014			December 31, 2013
	($ in thousands)
Rights-of-way and easements—at cost	$	131,580		$	131,088
Less: accumulated amortization	(37,846		)	(36,228		)
Contracts	22,742			22,742
Less: accumulated amortization	(12,327		)	(11,982		)
Net intangible assets	$	104,149		$	105,620

10

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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,
		2014		2013
	($ in thousands)
Amortization		$	1,964	$	2,961
Impairment expense:
Rights-of-way (a)		$	61	$	—

_____________________________________

(a) During the three months ended March 31, 2014, the Partnership incurred impairment charges in its Midstream Business related to certain rights-of-way in its East Texas and Other Segment due to the loss of two customers.

Estimated future amortization expense related to the intangible assets at March 31, 2014, is as follows (in thousands):

Year ending December 31,
2014	$	5,936
2015	$	7,914
2016	$	7,913
2017	$	7,912
2018	$	7,911
Thereafter	$	66,563

NOTE 7. LONG-TERM DEBT

Long-term debt consisted of the following:

	March 31, 2014			December 31, 2013
	($ in thousands)
Revolving credit facility:	$	724,000		$	706,800
Senior notes:
8.375% Senior Notes due 2019	550,000			550,000
Unamortized bond discount	(4,567		)	(4,738		)
Total Senior Notes	545,433			545,262
Total long-term debt	$	1,269,433		$	1,252,062

The Partnership currently pays an annual fee of 0.50% on the unused commitment under the revolving credit facility. As of March 31, 2014, the Partnership had approximately $21.7 million of outstanding letters of credit and approximately $69.1 million of availability under its revolving credit facility, based on its borrowing base of $815 million. The revolving credit facility matures on June 22, 2016.

On February 26, 2014, the Partnership entered into an amended credit agreement with its lender group which allowed for greater liquidity under the senior secured credit facility and for greater covenant flexibility for the first quarter of 2014. Specifically, the amendment provides for: (i) an increase in the Total Leverage Ratio and Senior Secured Leverage Ratio (as defined in the Credit Agreement) for the quarter ended March 31, 2014; (ii) the exclusion of fees and expenses associated with the strategic review and disposition of the Partnership’s Midstream Business from the calculation of Consolidated EBITDA (as defined in the Credit Agreement); (iii) deferring the redetermination of the Upstream Borrowing Base until June 1, 2014; and (iv) the option for the Partnership, at its election, to expand the multiplier for the Midstream Borrowing Base from 3.75x to 4.00x. The Partnership exercised this option to expand the multiplier for the Midstream Borrowing Base on March 31, 2014.

The following table presents the debt covenant levels specified in our revolving credit facility as of March 31, 2014:

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Quarter Ended	Total Leverage Ratio (a)	Senior Secured Leverage Ratio (a)	Interest Coverage Ratio (b)	Current Ratio (b)
March 31, 2014	5.85	3.40	2.50	1.0
June 30, 2014	5.00	3.05	2.50	1.0
September 30, 2014	4.75	2.95	2.50	1.0
Thereafter	4.50	N/A	2.50	1.0

_____________________

(a) Amount represents the maximum ratio for the period presented.

(b) Amount represents the minimum ratio for the period presented.

The following table presents the Partnership's actual covenant ratios as of March 31, 2014:

Interest coverage ratio	3.1
Total leverage ratio	5.4
Senior secured leverage ratio	3.06
Current ratio	1.1

As of March 31, 2014, the Partnership was in compliance with the financial covenants under the revolving credit facility. The Partnership expects to remain in compliance with its financial covenants under the Credit Agreement throughout 2014 assuming the Midstream Business Contribution to Regency closes prior to July 1, 2014. The Midstream Business Contribution will substantially improve the Partnership’s liquidity and debt ratios through the elimination of significant debt currently outstanding under its revolving credit facility and the proposed assumption of all of its senior unsecured notes via an exchange offer conducted by Regency. Should the Midstream Business Contribution closing date extend beyond the second quarter of 2014, the Partnership may need to seek additional amendments to its Credit Agreement from the lender group.

The Partnership received unitholder approval of the Midstream Business Contribution on April 29, 2014, however, the completion of the Midstream Business Contribution remains subject to regulatory approval. On February 27, 2014, the Partnership and Regency received a Request for Additional Information and Documentary Material ("Second Request") from the Federal Trade Commission ("FTC") in connection with the Midstream Business Contribution. On April 30, the Partnership and Regency certified substantial compliance with the Second Request and entered into a timing agreement with the FTC pursuant to which the Partnership and Regency agreed not to close the transaction prior to June 30, 2014, unless the FTC completes its investigation earlier. At this time, the Partnership can provide no assurance that the Midstream Business Contribution will be completed within its anticipated time frame, or at all. If the Midstream Business Contribution is not consummated by July 31, 2014, each party has the right to terminate the transaction without penalty. Should the Midstream Business Contribution not be consummated, the Partnership intends to explore alternative means to reduce its leverage ratios to comply with the financial covenants, which may include asset sales or purchases, equity financings, the separation of its upstream and midstream businesses or other alternatives.

NOTE 8. MEMBERS’ EQUITY

At March 31, 2014 and December 31, 2013, there were 156,644,153 and 156,644,153 unrestricted common units outstanding, respectively. In addition, there were 2,754,383 and 2,743,807 unvested restricted common units outstanding at March 31, 2014 and December 31, 2013, 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, 2014, no units were issued under this program.

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The table below summarizes the distributions paid or payable and declared for the three months endedMarch 31, 2014. 

Quarter Ended	Distribution per Common Unit		Record Date*	Payment Date
December 31, 2013+*	$	0.1500	February 7, 2014	February 14, 2014
March 31, 2014**	$	—	N/A	N/A

_____________________________

+ 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.

** No distribution was declared or paid for this period as the distribution was suspended for this period in advance of the closing the Midstream Business Contribution.

NOTE 9. RELATED PARTY TRANSACTIONS

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

		Three Months Ended March 31,
		2014		2013
Affiliates of Natural Gas Partners:	($ in thousands)
Natural gas purchases from affiliates		$	1,142	$	123

	March 31, 2014		December 31, 2013
Affiliates of Natural Gas Partners:	($ in thousands)
Payable (related to natural gas purchases)	$	—	$	18

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 a portion of the Partnership's obligations under it's 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.

For accounting purposes, the Partnership has not designated any of its interest rate derivative instruments as hedges; instead it marks these derivative contracts to fair value (see Note 11).  Changes in fair values of the interest rate derivative instruments are recorded as an adjustment to the mark-to-market gains (losses) on risk management transactions within other income (expense).

The following table sets forth certain information regarding the Partnership's interest rate swaps as of March 31, 2014:

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.  Historically, the Partnership has hedged a substantial portion of its expected

13

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

production in an attempt 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 attempt to 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. Historically, the Partnership has hedged its expected future commodity volumes either with derivatives of the same commodity ("direct hedges") or with derivatives of another commodity which the Partnership expects will correlate well with the underlying commodity ("proxy hedges").  For example, 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 hedges, 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. In recent quarters, the correlation of price changes in crude oil and NGLs has weakened relative to longer-term averages as NGL prices have fallen while crude index prices have risen. This dynamic has negatively impacted our hedging objectives.

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.

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

Commodity derivatives, as of March 31, 2014, that will mature during the years ended December 31, 2014, 2015 and 2016:

Underlying	Type	Notional Volumes (units) (a)	Floor Strike Price ($/unit)(b)		Cap Strike Price ($/unit)(b)
Portion of Contracts Maturing in 2014
Natural Gas	Swap (Pay Floating/Receive Fixed)	12,600,000	$	4.38
Crude Oil	Costless Collar	180,000	$	90.00	$	106.00
Crude Oil	Swap (Pay Floating/Receive Fixed)	1,650,000	$	96.51
Crude Oil	Swap (Pay Fixed/Receive Floating)	218,676	92.54
Propane	Swap (Pay Floating/Receive Fixed)	12,852,000	1.09
IsoButane	Swap (Pay Floating/Receive Fixed)	1,701,000	1.31
Normal Butane	Swap (Pay Floating/Receive Fixed)	3,099,600	1.30
Contracts Maturing in 2015
Natural Gas	Swap (Pay Floating/Receive Fixed)	12,000,000	$	4.10
Crude Oil	Costless Collar	480,000	$	90.00	$	97.55
Crude Oil	Swap (Pay Floating/Receive Fixed)	1,110,000	$	88.70
Contracts Maturing in 2016
Natural Gas	Swap (Pay Floating/Receive Fixed)	9,480,000	$	4.25
Crude Oil	Swap (Pay Floating/Receive Fixed)	1,416,000	$	84.60

_______________________

(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 intended to capitalize on favorable price differentials between various receipt and delivery locations. The Partnership's natural gas marketing and trading 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.

15

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

Type	Notional Volumes (MMbtu)
Portion of Contracts Maturing in 2014
Index Swap - Purchases	1,950,000
Index Swap - Sales	600,000
Swap (Pay Fixed/ Receive Floating) - Purchases	750,000
Swap (Pay Floating/ Receive Fixed) - Sales	3,525,000
Forward purchase contract - index	9,315,450
Forward sales contract - index	16,300,200
Forward purchase contract - fixed price	3,747,000
Forward sales contract - fixed price	1,575,000
Basis Swaps - Purchases	8,155,000
Basis Swaps - Sales	3,650,000
Portion of Contracts Maturing in 2015 and beyond
Basis Swaps - Purchases	13,280,000
Basis Swaps - Sales	13,280,000

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

16

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Fair Value of Interest Rate and Commodity Derivatives

The following tables set forth the fair values of interest rate and commodity derivative instruments not designated as hedging instruments and their location within the unaudited condensed consolidated balance sheet as of March 31, 2014 and December 31, 2013:

	As of March 31, 2014
	Derivative Assets				Derivative Liabilities
	Balance Sheet Classification	Fair Value			Balance Sheet Classification	Fair Value
	($ in thousands)
Interest rate derivatives - liabilities	Current assets	$	—		Current liabilities	$	(6,310	)
Interest rate derivatives - liabilities	Long-term assets	—			Long-term liabilities	(1,368		)
Commodity derivatives - assets	Current assets	7,863			Current liabilities	1,657
Commodity derivatives - assets	Long-term assets	2,361			Long-term liabilities	1,322
Commodity derivatives - liabilities	Current assets	(2,123		)	Current liabilities	(10,681		)
Commodity derivatives - liabilities	Long-term assets	(910		)	Long-term liabilities	(832		)
Total derivatives		$	7,191			$	(16,212	)
	As of December 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	$	(6,210	)
Interest rate derivatives - liabilities	Long-term assets	—			Long-term liabilities	(2,885		)
Commodity derivatives - assets	Current assets	11,268			Current liabilities	1,730
Commodity derivatives - assets	Long-term assets	6,259			Long-term liabilities	1,488
Commodity derivatives - liabilities	Current assets	(2,106		)	Current liabilities	(6,543		)
Commodity derivatives - liabilities	Long-term assets	(798		)	Long-term liabilities	(2,451		)
Total derivatives		$	14,623			$	(14,871	)

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,
		2014			2013
		($ in thousands)
Interest rate derivatives	Interest rate risk management losses, net	$	(290	)	$	(156	)
Commodity derivatives	Commodity risk management losses, net	(14,944		)	(17,908		)
Commodity derivatives - trading	Natural gas, natural gas liquids, oil, condensate and sulfur sales	(987		)	(1,150		)
	Total	$	(16,221	)	$	(19,214	)

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).

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

Level 1 – Quoted prices are available in active markets for identical assets and liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the market place throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

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

As of March 31, 2014, 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, 2014 and December 31, 2013: 

	As of March 31, 2014
	Level 1		Level 2			Level 3		Netting (a)			Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	4,920		$	—	$	(2,282	)	$	2,638
Natural gas derivatives	—		7,786			—		(3,233		)	4,553
NGL derivatives	—		497			—		(497		)	—
Total	$	—	$	13,203		$	—	$	(6,012	)	$	7,191
Liabilities:
Crude oil derivatives	$	—	$	(5,553	)	$	—	$	2,282		$	(3,271	)
Natural gas derivatives	—		(8,712		)	—		3,233			(5,479		)
NGL derivatives	—		(281		)	—		497			216
Interest rate swaps	—		(7,678		)	—		—			(7,678		)
Total	$	—	$	(22,224	)	$	—	$	6,012		$	(16,212	)

____________________________

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

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	As of December 31, 2013
	Level 1		Level 2			Level 3		Netting (a)			Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	9,804		$	—	$	(2,003	)	$	7,801
Natural gas derivatives	—		10,899			—		(4,077		)	6,822
NGL derivatives	—		42			—		(42		)	—
Total	$	—	$	20,745		$	—	$	(6,122	)	$	14,623
Liabilities:
Crude oil derivatives	$	—	$	(3,930	)	$	—	$	2,003		$	(1,927	)
Natural gas derivatives	—		(6,847		)	—		4,077			(2,770		)
NGL derivatives	—		(1,121		)	—		42			(1,079		)
Interest rate swaps	—		(9,095		)	—		—			(9,095		)
Total	$	—	$	(20,993	)	$	—	$	6,122		$	(14,871	)

____________________________

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

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

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

For periods in which impairment charges have been incurred, the Partnership is required to write down the value of the impaired asset to its fair value. See Note 4 and 6 for a further discussion of the impairment charges recorded during the three months endedMarch 31, 2014. The following table discloses the fair value of the Partnership's assets measured at fair value on a nonrecurring basis during the three months ended March 31, 2014:

	Three Months Ended March 31,
	2014		Level 1		Level 2		Level 3		Total Losses
	($ in thousands)
Plant assets	$	52	$	—	$	—	$	52	$	132
Pipeline assets	$	746	$	—	$	—	$	746	$	1,904
Rights-of-way	$	24	$	—	$	—	$	24	$	61

The Partnership calculated the fair value of the impaired assets using a discounted cash flow analysis to determine the excess of the asset's carrying value over its fair value. Significant inputs to the valuation of fair value of the plant, pipeline and intangible assets includes estimates of (i) future cash flows, including revenue, expenses and capital expenditures, (ii) timing of cash flows, (iii) forward commodity prices, adjusted for estimate location differentials and (iv) a discount rate reflective of our cost of capital.

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

As of March 31, 2014, the outstanding debt associated with the Credit Agreement bore interest at a floating rate; as such, the Partnership believes that the carrying value of this debt approximates its fair value. The outstanding debt associated with the Senior Notes bears interest at a fixed rate; based on the market price of the Senior Notes as of March 31, 2014 and December 31, 2013, the Partnership estimates that the fair value of the Senior Notes was $597.4 million and $599.5 million, respectively. 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.

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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, 2014 or December 31, 2013 related to legal matters, and current lawsuits are not expected to have a material adverse effect on the Partnership's 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.

In March and April 2014, alleged unitholders of the Partnership filed three class action lawsuits in the United States District Court for the Southern District of Texas on behalf of the Partnership's public unitholders. The lawsuits name the Partnership, its Board of Directors, Regency Energy Partners, L.P. (“Regency”), and Regal Midstream LLC as defendants. One of the lawsuits also names the Partnership's general partner and its general partner’s general partner as defendants. Plaintiffs in each lawsuit allege a variety of causes of action challenging Regency’s acquisition of the Partnership's midstream assets, including alleged breaches of fiduciary or contractual duties, alleged aiding and abetting these alleged breaches of duty, and alleged violations of the Securities Exchange Act of 1934. The lawsuits allege that the Partnership (i) sold its midstream assets for inadequate value, (ii) engaged in an unfair sales process, (iii) agreed to contractual terms (the no-solicitation, fiduciary out, superior proposal, and termination fee provisions and the voting and support agreement) that would dissuade other potential acquirors from seeking to purchase the midstream assets, and (iv) failed to disclose material information in its definitive proxy statement concerning the analysis of our financial advisors, potential conflicts of the advisors (and directors), management’s financial projections, strategic alternatives, other potential acquirors, the bases for certain actions, and the background of the transaction. Based on these allegations, the plaintiffs seek in each case to enjoin the Partnership from proceeding with or consummating the sale of its midstream assets. To the extent that the sale is consummated before injunctive relief is granted, the plaintiffs seek to have the sale rescinded. The plaintiffs also seek monetary damages and attorneys’ fees. The Partnership believe that the lawsuits are without merit.

The Partnership is the defendant in a lawsuit filed by a plaintiff who is alleging an entitlement to participate in various wells drilled by the Partnership in a defined area of land. The Partnership is disputing this claim, and believes the lawsuit is without merit. Because it is early in the course of proceedings, the Partnership believes that an estimate of the reasonably possible loss, or range of possible losses, if any, associated with this lawsuit cannot be made at this point.

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

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, 2014 and December 31, 2013, the Partnership had accrued approximately $3.1 million and $3.2 million for environmental matters, respectively.

20

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 2013 and does not anticipate doing so in 2014. 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 $2.9 million and $2.1 million for the three months endedMarch 31, 2014 and 2013, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term.

21

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 and Other 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 natural gas marketing and trading;

(iv)    Upstream Segment: crude oil, condensate, natural gas, NGLs and sulfur production from operated and non-operated wells; and

(v)    Corporate and Other Segment: risk management, intersegment eliminations and other corporate activities such as general and administrative expenses.

The Partnership's 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, 2014	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	$	159,835	$	46,473		$	104,422		$	310,730		$	52,288	$	(14,944	)	(a)	$	348,074
Intersegment sales	72,959		17,861			(93,772		)	(2,952		)	2,948		4				—
Cost of natural gas and natural gas liquids	189,904		55,069			—			244,973			—		—				244,973
Intersegment cost of natural gas, oil and condensate	63		—			681			744			—		(744		)		—
Operating costs and other expenses	20,317		4,724			8			25,049			15,289		21,391				61,729
Depreciation, depletion and amortization	15,626		4,334			119			20,079			19,725		704				40,508
Impairment	—		2,097			—			2,097			—		—				2,097
Operating income (loss)	$	6,884	$	(1,890	)	$	9,842		$	14,836		$	20,222	$	(36,291	)		$	(1,233	)
Capital Expenditures	$	8,363	$	1,851		$	3		$	10,217		$	39,258	$	1,577			$	51,052
Segment Assets	$	949,909	$	244,014		$	73,398		$	1,267,321		$	872,604	$	15,393		(b)	$	2,155,318

22

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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)	$	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

______________________________

(a) Represents results of the Partnership's commodity risk management activity, excluding activity associated with its natural gas marketing and trading activities.

(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, 2014 was 4.9% compared to 3.3% for the three months endedMarch 31, 2013. Due to the fact that the effective rate is a ratio of total tax expense to pre-tax book net income, the change in tax benefit is due primarily to book and tax temporary differences for the three months endedMarch 31, 2014 as compared to the three months endedMarch 31, 2013.

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, 2014, a total of 903,218 common units remained available for issuance. Grants under the LTIP are made at the discretion of the board and to date have only been made in the form of restricted units. 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.

Grants of restricted units eligible to receive distributions are valued at the market price as of the date issued, while grants of restricted units not eligible to receive distributions are valued at the market price as of the date issued less the present value of the expected distribution stream over the vesting period using the risk-free interest rate. 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.

23

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

A summary of the changes in outstanding restricted common units for the three months endedMarch 31, 2014 is provided below:

	Number of Restricted Units		Weighted Average Fair Value
Outstanding at December 31, 2013	2,743,807		$	9.37
Granted	50,500		$	5.52
Forfeited	(39,924	)	$	9.85
Outstanding at March 31, 2014	2,754,383		$	9.30

For the three months endedMarch 31, 2014 and 2013, non-cash compensation expense of approximately $3.3 million and $2.6 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, 2014, unrecognized compensation costs related to the outstanding restricted units under the LTIP totaled approximately $14.1 million. The remaining expense is to be recognized over a weighted average of 1.50.

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 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, with the exception of net losses. Net losses are allocated to just the common units.

As of March 31, 2014 and 2013, 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 majority of the restricted 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. Restricted units granted in 2013 to certain senior executives and members of the board of directors are not eligible to receive the distributions declared by the Partnership and therefore do not meet the definition of participating securities.

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

		Three Months Ended March 31,
		2014	2013
	(in thousands)
Weighted average units outstanding during period:
Common units - Basic and diluted		156,644	146,171

Due to the distribution being suspended until after the closing of the Midstream Business Contribution (see Notes 1 and 18) and the Partnership generating a net loss during the period, earnings per unit for the three months ended March 31, 2014 was only calculated for the common units as the net loss was only allocated to the common units.

24

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the Partnership's basic and diluted income per unit for the three months ended March 31, 2014:
	Total			Common Units			Restricted Common Units*
	($ in thousands, except for per unit amounts)
Net loss	$	(18,563	)
Distributions **	—			$	—		$	—
Assumed net loss after distribution to be allocated	(18,563		)	(18,563		)	—
Net loss to be allocated	$	(18,563	)	$	(18,563	)	$	—
Basic and diluted loss per unit				$	(0.12	)

_____________________________

* Restricted common units granted under the LTIP that contain non-forfeitable rights to the distributions declared by the Partnership.

** No distribution was declared or paid for this period as the distribution was suspended for this period in advance of the closing the Midstream Business Contribution.

The following table presents the Partnership's basic and diluted income per unit for the three months ended March 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		)	—
Net loss to be allocated	$	(33,514	)	$	(34,102	)	$	588
Basic and diluted loss per unit				$	(0.23	)

25

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 17. SUBSIDIARY GUARANTORS

The Partnership has issued registered debt securities guaranteed by its subsidiaries.  As of March 31, 2014, 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.

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, 2014 and December 31, 2013, and unaudited condensed consolidating statements of operations for the three months endedMarch 31, 2014 and 2013, and unaudited condensed consolidating statements of cash flows for the three months endedMarch 31, 2014 and 2013, 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.

26

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Balance Sheet

March 31, 2014

	Parent Issuer		Co-Issuer		Subsidiary Guarantors		Non-Guarantor Investments		Consolidating Entries			Total
	($ in thousands)
ASSETS:
Accounts receivable – related parties	$	663,758	$	—	$	—	$	—	$	(663,758	)	$	—
Other current assets	8,290		1		181,525		—		—			189,816
Total property, plant and equipment, net	2,601		—		1,836,324		—		—			1,838,925
Investment in subsidiaries	1,151,844		—		—		894		(1,152,738		)	—
Total other long-term assets	16,193		—		110,384		—		—			126,577
Total assets	$	1,842,686	$	1	$	2,128,233	$	894	$	(1,816,496	)	$	2,155,318
LIABILITIES AND EQUITY:
Accounts payable – related parties	$	—	$	—	$	663,758	$	—	$	(663,758	)	$	—
Other current liabilities	31,281		—		229,188		—		—			260,469
Other long-term liabilities	7,125		—		83,444		—		—			90,569
Long-term debt	1,269,433		—		—		—		—			1,269,433
Equity	534,847		1		1,151,843		894		(1,152,738		)	534,847
Total liabilities and equity	$	1,842,686	$	1	$	2,128,233	$	894	$	(1,816,496	)	$	2,155,318

Unaudited Condensed Consolidating Balance Sheet

December 31, 2013

	Parent Issuer		Co-Issuer		Subsidiary Guarantors		Non-Guarantor Investments		Consolidating Entries			Total
	($ in thousands)
ASSETS:
Accounts receivable – related parties	$	691,588	$	—	$	—	$	—	$	(691,588	)	$	—
Other current assets	5,868		1		157,515		—		—			163,384
Total property, plant and equipment, net	2,318		—		1,826,450		—		—			1,828,768
Investment in subsidiaries	1,133,217		—		—		908		(1,134,125		)	—
Total other long-term assets	19,833		—		115,565		—		—			135,398
Total assets	$	1,852,824	$	1	$	2,099,530	$	908	$	(1,825,713	)	$	2,127,550
LIABILITIES AND EQUITY:
Accounts payable – related parties	$	—	$	—	$	691,588	$	—	$	(691,588	)	$	—
Other current liabilities	17,390		—		193,876		—		—			211,266
Other long-term liabilities	9,493		—		80,850		—		—			90,343
Long-term debt	1,252,062		—		—		—		—			1,252,062
Equity	573,879		1		1,133,216		908		(1,134,125		)	573,879
Total liabilities and equity	$	1,852,824	$	1	$	2,099,530	$	908	$	(1,825,713	)	$	2,127,550

27

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

For the Three Months EndedMarch 31, 2014

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	(13,520	)	$	—	$	361,594		$	—		$	—		$	348,074
Cost of natural gas and natural gas liquids	—			—		244,973			—			—			244,973
Operations and maintenance	—			—		34,671			—			—			34,671
Taxes other than income	—			—		5,667			—			—			5,667
General and administrative	6,411			—		14,980			—			—			21,391
Depreciation, depletion and amortization	53			—		40,455			—			—			40,508
Impairment	—			—		2,097			—			—			2,097
(Loss) income from operations	(19,984		)	—		18,751			—			—			(1,233		)
Interest expense, net	(17,985		)	—		(1		)	—			—			(17,986		)
Other non-operating income	2,221			—		2,301			—			(4,522		)	—
Other non-operating expense	(1,716		)	—		(3,096		)	(7		)	4,522			(297		)
(Loss) income before income taxes	(37,464		)	—		17,955			(7		)	—			(19,516		)
Income tax benefit	(267		)	—		(686		)	—			—			(953		)
Equity in earnings of subsidiaries	18,634			—		—			—			(18,634		)	—
Net (loss) income	$	(18,563	)	$	—	$	18,641		$	(7	)	$	(18,634	)	$	(18,563	)

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 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	)

28

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Cash Flows

For the Three Months EndedMarch 31, 2014

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments		Consolidating Entries		Total
	($ in thousands)
Net cash flows provided by operating activities	$	13,139		$	—	$	55,398		$	16	$	—	$	68,553
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(336		)	—		(53,602		)	—		—		(53,938		)
Purchase of intangible assets	—			—		(554		)	—		—		(554		)
Net cash flows used in investing activities	(336		)	—		(54,156		)	—		—		(54,492		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	144,250			—		—			—		—		144,250
Repayment of long-term debt	(127,050		)	—		—			—		—		(127,050		)
Proceed from senior notes	(205		)	—		—			—		—		(205		)
Proceeds from derivative contracts	(1,708		)	—		—			—		—		(1,708		)
Distributions to members and affiliates	(23,801		)	—		—			—		—		(23,801		)
Net cash flows used in financing activities	(8,514		)	—		—			—		—		(8,514		)
Net increase (decrease) in cash and cash equivalents	4,289			—		1,242			16		—		5,547
Cash and cash equivalents at beginning of period	1,237			1		(1,389		)	227		—		76
Cash and cash equivalents at end of period	$	5,526		$	1	$	(147	)	$	243	$	—	$	5,623

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 (decrease) increase in cash and cash equivalents	(1,670		)	—		1,696			9		—		35
Cash and cash equivalents at beginning of period	1,670			1		(1,832		)	186		—		25
Cash and cash equivalents at end of period	$	—		$	1	$	(136	)	$	195	$	—	$	60

29

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 18. SUBSEQUENT EVENTS

Contribution of Midstream Business to Regency

On April 29, 2014, the Partnership conducted a special meeting of its common unitholders in which the unitholders approved the transaction to contribute the Midstream Business to Regency. The transaction remains subject to regulatory approval. On February 27, 2014, the Partnership and Regency received a Request for Additional Information and Documentary Materials ("Second Request") from the FTC in connection with the Midstream Business Contribution. On April 30, 2014, the Partnership and Regency certified their substantial compliance with the FTC's Second Request, and Eagle Rock and Regency have agreed with the FTC not to close the proposed transaction before June 30, 2014, unless the FTC first closes its investigation.

As the sale of the Midstream Business at March 31, 2014 remained conditioned upon, among other things, the approval of the Partnership's common unitholders (see above) and the expiration or termination of all applicable waiting periods under the Hart-Scott-Rodino Antitrust Improvement Act of 1976, as amended, the Partnership has not classified the assets of its Midstream Business as assets-held-for-sale or the operations as discontinued.

If the Partnership had met the criteria for assets-held-for-sale as of March 31, 2014, it would have presented the following (in thousands):

Assets-Held-For-Sale:
Property, plant and equipment, net	$	993,973
Accounts receivable	136,966
Intangible assets, net	100,930
Other assets	17,103
Total assets-held-for-sale	$	1,248,972
Liabilities-held-for-sale
Long-term debt	$	545,433
Accounts payable	151,181
Other liabilities	19,123
Total liabilities-held-for-sale	$	715,737

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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, 2013 and in "Part II. Item 1A. Risk Factors." These factors include but are not limited to:

• Risks related to the Midstream Business Contribution;

• 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;

• 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;

• 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; and

• Impact of cyber-security threats and related disruptions.

31

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, 2013 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, 2013.

We are a domestically-focused, growth-oriented, publicly-traded Delaware limited partnership engaged in the following two businesses:

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

• 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.

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, 2014, our Upstream Business had operating income of $20.2 million, compared to operating income of $12.3 million during the three months endedMarch 31, 2013.  

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, 2014, our Midstream Business had operating income of $14.8 million, compared to an operating loss of $7.6 million during the three months endedMarch 31, 2013.  

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, 2014, our Corporate and Other Segment had an operating loss of $36.3 million, compared to an operating loss of $37.3 million during the three months endedMarch 31, 2013.  Results reflected a net loss on our commodity derivatives of $14.9 million during the three months endedMarch 31, 2014, compared to a net loss on our commodity derivatives of $17.9 million during the three months endedMarch 31, 2013 .  See "—Results of Operations — Corporate and Other Segment" for a further discussion of the impact of our commodity derivatives.

Recent Developments

On December 23, 2013, we announced that we had entered into a definitive agreement to contribute our Midstream Business to Regency for total consideration of up to $1.325 billion, consisting of $200 million of newly issued Regency common units (8,245,859 common units, calculated by taking the volume-weighted average price of a single Regency common unit for the ten trading days immediately preceding the announcement date) and a combination of cash and assumed debt, subject to certain closing conditions. As part of the transaction, Regency is conducting an offer to exchange our $550 million of outstanding senior unsecured notes into an equivalent amount of Regency senior unsecured notes with the same tenor, coupon and a comparable covenant package. The cash portion of the purchase price will be reduced by the amount of notes exchanged subject to a 10% adjustment factor, such that if all $550 million of bonds are exchanged, the total consideration will equal $1.27 billion ($1.325 billion less $55 million) consisting of $200 million in Regency units, $550 million of assumed debt and $520 million of cash proceeds.

The Midstream Business Contribution was approved by our common unitholders on April 29, 2014. As of that date, all significant closing conditions for the transaction had been satisfied other than the approval from the Federal Trade Commissions ("FTC") anti-trust review. On February 27, 2014, we and Regency received a Request for Additional Information and Documentary Materials ("Second Request") from the FTC in connection with the Midstream Business Contribution. On

32

April 30, 2014, we and Regency certified our substantial compliance with the FTC's Second Request and entered into a timing agreement with the FTC agreeing to extend the FTC's review period until June 30, 2014, unless the FTC completes its investigation earlier.

Impairment

During the three months endedMarch 31, 2014, we recorded an impairment charge of $2.1 million in our East Texas and Other Segment due to the loss of two customers on our North System. We did not recorded any impairment charges in Midstream Business during the three months endedMarch 31, 2013 nor did we incur any impairment charges in our Upstream Business during the three months endedMarch 31, 2014 and 2013.

Pursuant to accounting principles generally accepted in the United States of America ("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.

33

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, 2014and 2013.

		Three Months Ended March 31,
		2014			2013
	($ in thousands)
Revenues:
Natural gas, natural gas liquids, oil, condensate, sulfur and helium sales		$	340,465		$	254,200
Gathering, compression, processing and treating fees		22,397			20,942
Commodity risk management gains (losses), net		(14,944		)	(17,908		)
Other revenue		156			497
Total revenue		348,074			257,731
Cost of natural gas, natural gas liquids, condensate and helium		244,973			179,988
Costs and expenses:
Operations and maintenance		34,671			32,219
Taxes other than income		5,667			3,866
General and administrative		21,391			18,847
Impairment		2,097			—
Depreciation, depletion and amortization		40,508			40,237
Total costs and expenses		104,334			95,169
Operating loss		(1,233		)	(17,426		)
Other income (expense):
Interest expense, net		(17,986		)	(17,084		)
Interest rate risk management losses, net		(290		)	(156		)
Other expense, net		(7		)	(8		)
Total other expense		(18,283		)	(17,248		)
Loss before income taxes		(19,516		)	(34,674		)
Income tax benefit		(953		)	(1,160		)
Net loss		$	(18,563	)	$	(33,514	)
Adjusted EBITDA(a)		$	57,589		$	53,617

________________________

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

34

Upstream Segment

		Three Months Ended March 31,
		2014		2013
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Oil and condensate		$	27,134	$	12,313
Intersegment sales - condensate		—		11,286
Natural gas		11,651		8,181
Intersegment sales - natural gas		2,948		1,814
NGLs		11,466		10,276
Sulfur		1,885		2,935
Other		152		497
Total revenue		55,236		47,302
Operating Costs and expenses:
Operations and maintenance		15,289		14,116
Depletion, depreciation and amortization		19,725		20,929
Total operating costs and expenses		35,014		35,045
Operating income		$	20,222	$	12,257
Capital expenditures		$	39,258	$	34,050
Realized average prices:
Oil and condensate (per Bbl)		$	85.56	$	84.56
Natural gas (per Mcf)		$	4.95	$	3.19
NGLs (per Bbl)		$	41.90	$	35.45
Sulfur (per Long ton)		$	77.05	$	110.34
Production volumes:
Oil and condensate (Bbl)		317,126		279,069
Natural gas (Mcf)		2,952,149		3,129,052
NGLs (Bbl)		273,673		289,866
Total (Mcfe)		6,496,943		6,542,662
Sulfur (Long ton)		24,461		26,598

Revenues. For the three months endedMarch 31, 2014, Upstream Segment revenues increased by $7.9 million, as compared to the three months endedMarch 31, 2013.  The increase in revenues for the three months endedMarch 31, 2014 compared to the three months endedMarch 31, 2013 was due to to higher realized oil, NGL and natural gas prices and higher oil volumes, partially offset by lower natural gas, NGL and sulfur volumes and lower sulfur prices.

Production volumes during the three months endedMarch 31, 2014 were negatively impacted by cold weather. We estimate that the lost revenues were approximately $1.5 million, excluding the impact of severance tax, as a result of the severe winter weather. Volumes returned to normal production in the latter part of the quarter.

On February 7, 2013, we suspended operations at our Flomaton treating facility in Escambia County, Alabama due to the failure of certain plant equipment and inlet volumes that were insufficient to operate the facility's sulfur recovery unit. To increase inlet volumes of the field to operate the treating facility we attempted to restore production from two wells connected to the facility, but these operations were unsuccessful. We resumed facility operations on April 18, 2013, after repairing the equipment and increasing inlet volumes by diverting production from a nearby operated well; however, on May 24, 2013, we again suspended operations due to equipment failure at the treating facility. On July 31, 2013, we received approval from the required percentage of owners of the Big Escambia Creek and Flomaton plants to resume operations by re-routing gas from the Flomaton facility to our Big Escambia Creek facility for treating and processing, while continuing to stabilize and sell the

35

Flomaton field condensate at the Flomaton facility. We have currently spent $2.9 million on the project to re-route full well stream gas from the Flomaton facility to our Big Escambia Creek facility for treating and processing. We anticipate this project being completed by the end of the second quarter 2014.

Operating Expenses. Operating expenses, including severance and ad valorem taxes, increased $1.2 million for the three months endedMarch 31, 2014, as compared to the three months endedMarch 31, 2013.  The increase was primarily due to higher severance tax due to higher sales value, a 2013 severance tax credit, weather related costs, and higher lease operating costs due to additional wells partially offset by lower workover costs.

Depletion, Depreciation and Amortization. Depletion, depreciation and amortization expense decreased by $1.2 million for the three months endedMarch 31, 2014, as compared to the same period in the prior year.  The decrease for the three months endedMarch 31, 2014 was primarily a result of the impairment charges recorded during 2013.

Capital Expenditures.  Capital expenditures increased by $5.2 million for the three months endedMarch 31, 2014, as compared to the three months endedMarch 31, 2013, primarily due to increased drilling activity.

During the three months endedMarch 31, 2014, we drilled and completed 4 gross (3.9 net) operated wells in the Mid-Continent region. Additionally, during the three months ended March 31, 2014, we conducted 5 gross (4.2 net) capital workovers and one gross (0.1 net) recompletion across our operations.

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Midstream Business (Three Segments)

Texas Panhandle Segment

		Three Months Ended March 31,
		2014			2013
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Natural gas, natural gas liquids, condensate and helium sales		$	145,868		$	106,394
Intersegment sales - natural gas and condensate		72,959			49,135
Gathering, compression, processing and treating fees		13,963			12,521
Other revenue		4			—
Total revenue		232,794			168,050
Cost of natural gas, natural gas liquids, condensate and helium (a)		189,904			132,226
Intersegment cost of sales - natural gas		63			19
Operating costs and expenses:
Operations and maintenance		20,317			17,134
Depreciation and amortization		15,626			13,845
Total operating costs and expenses		35,943			30,979
Operating income		$	6,884		$	4,826
Capital expenditures		$	8,363		$	18,303
Realized prices (b):
Condensate (per Bbl)		$	83.15		$	80.34
Natural gas (per MMbtu)		$	5.31		$	3.27
NGLs (per Bbl)		$	44.20		$	35.53
Production volumes:
Gathering volumes (Mcf/d)(c)		376,784			342,346
NGLs (net equity Bbls)		263,340			64,551
Condensate (net equity Bbls)		288,360			275,692
Natural gas (MMbtu/d)(c)		(613		)	3,379

_______________________

(a) Includes the cost of gathering, compression, processing and treating fees of $0.7 million and $0.3 million, respectively, for the three months endedMarch 31, 2014and 2013.

(b) Excludes the impact of adjustments related to prior periods, including true-ups of estimates.

(c) 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, Condensate and Helium. For the three months endedMarch 31, 2014, revenues minus cost of natural gas, NGLs, condensate and helium for our Texas Panhandle Segment operations totaled $42.8 million, compared to $35.8 million for the three months endedMarch 31, 2013. The increase for the three months endedMarch 31, 2014 was primarily due to increased realized commodity prices and increased volumes. Severe winter weather negatively impacted our results for the three months endedMarch 31, 2014 and the same period in the prior year by $2.4 million and $2.8 million, respectively. In addition, our results for the three months endedMarch 31, 2013 were negatively impacted by adjustments related to amounts recorded during the three months ended December 31, 2012. During the three months endedMarch 31, 2013, we received new information from BP, the operator of the assets acquired in the Panhandle Acquisition during the three months ended December 31, 2012, that the cost of natural gas, NGLs and condensate on the assets was higher than previously communicated.

Operating Expenses. Operating expenses, including taxes other than income, for the three months endedMarch 31, 2014, increased by $3.2 million, as compared to the three months endedMarch 31, 2013. The increase was primarily driven by by adjustments related to amounts recorded during the three months ended December 31, 2012. During the three months endedMarch 31, 2013, we received new information from BP that the costs of operating the plants and gathering systems,

37

acquired as part of the Panhandle acquisition, during the three months ended December 31, 2012 were lower than previously communicated. Excluding these adjustments, operating expenses increased primarily due to higher chemical and utility costs and increased ad valorem taxes due to the addition of our new Woodall and Wheeler plants.

Depreciation and Amortization. Depreciation and amortization expenses for the three months endedMarch 31, 2014 increased $1.8 million, from the three months endedMarch 31, 2013. The increase was due to increased depreciation expense primarily associated with the new Wheeler Plant and other capital projects placed into service during the period.

Capital Expenditures. Capital expenditures for the three months endedMarch 31, 2014, decreased by $9.9 million, compared to the three months endedMarch 31, 2013. The decrease was primarily attributable to costs associated with the construction of our Wheeler Plant and the integration of the Panhandle Acquisition during the three months endedMarch 31, 2013, partially offset by increased spending on new well connections during the three months endedMarch 31, 2014.

East Texas and Other Midstream Segment

		Three Months Ended March 31,
		2014			2013
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Natural gas, natural gas liquids and condensate sales		$	38,081		$	27,388
Intersegment sales - natural gas		17,861			8,538
Gathering, compression, processing and treating fees (a)		8,392			8,358
Total revenue		64,334			44,284
Cost of natural gas, natural gas liquids, condensate and helium		55,069			33,234
Operating costs and expenses:
Operations and maintenance		4,724			4,829
Impairment		2,097			—
Depreciation and amortization		4,334			5,002
Total operating costs and expenses		11,155			9,831
Operating (loss) income		$	(1,890	)	$	1,219
Capital expenditures		$	1,851		$	1,776
Realized prices (b):
Condensate (per Bbl)		$	97.53		$	94.25
Natural gas (per MMbtu)		$	4.84		$	3.36
NGLs (per Bbl)		$	39.21		$	29.98
Production volumes:
Gathering volumes (Mcf/d)(c)		204,701			200,700
NGLs (net equity Bbls)		16,200			53,204
Condensate (net equity Bbls)		11,610			5,226
Natural gas (MMbtu/d)(c)		(459		)	344

_________________________

(a) Includes the cost of gathering, compression, processing and treating fees of $0.8 million and $0.5 million, for the three months endedMarch 31, 2014 and 2013, respectively.

(b) Excludes the impact of adjustments related to prior periods, including true-ups of estimates.

(c) 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, 2014, revenues minus cost of natural gas and NGLs for our East Texas and Other Midstream Segment was $9.3 million, compared to $11.1 million for the three months endedMarch 31, 2013. During the three months endedMarch 31, 2014 and 2013, we recorded

38

revenues associated with indemnity payments of $1.0 million and $2.1 million, respectively. We receive indemnity 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 indemnity payments, revenues minus cost of natural gas, NGLs and condensate for the three months endedMarch 31, 2014 and 2013, would have been $8.3 million and $9.0 million. The decrease, excluding indemnity payments, for the three months endedMarch 31, 2014 compared to the three months endedMarch 31, 2013, is primarily due to a adjustments of prior period amounts due to the receipt of new information, partially offset by increase commodity prices.

Our NGL equity volumes were lower in part due to our decision to reject ethane during the three months endedMarch 31, 2014. Our election to reject ethane is an economic decision based on our contract portfolio and the price spread between ethane and natural gas.  This decision also has a positive impact on our natural gas volumes as the ethane remains unprocessed and sold as natural gas.

Operating Expenses. Operating expenses for the three months endedMarch 31, 2014 decreased $0.1 million, compared to the three months endedMarch 31, 2013. The decrease in the three months endedMarch 31, 2014 compared to 2013 was primarily due to lower maintenance and environmental costs.

Impairment. We recorded impairment charges of $2.1 million during the three months endedMarch 31, 2014 on our North System due to the loss of two customers. We did not incur any impairment charges during the three months endedMarch 31, 2013.

Depreciation and Amortization. Depreciation and amortization expenses for the three months endedMarch 31, 2014 decreased $0.7 million, compared to the three months endedMarch 31, 2013. The decrease was primarily the result of a reduction in amortization expense due to the completion of the amortization of certain intangible assets.

Capital Expenditures. Capital expenditures for the three months endedMarch 31, 2014 increased $0.1 million, compared to the three months endedMarch 31, 2013. The increase for the three months endedMarch 31, 2014 was due to costs associated with system upgrades at our Brookeland Plant, partially offset by lower well connection costs.

Marketing and Trading Segment

		Three Months Ended March 31,
		2014			2013
	($ in thousands)
Revenues:
Natural gas, oil and condensate sales (a)		$	104,380		$	86,713
Intersegment sales - natural gas and condensate		(93,772		)	(59,468		)
Gathering, compression, processing and treating fees		42			63
Total revenue		10,650			27,308
Cost of oil and condensate		—			14,528
Intersegment cost of condensate		681			11,093
Operating costs and expenses:
Operations and maintenance		8			6
Depreciation and amortization		119			84
Total operating costs and expenses		127			90
Operating income		$	9,842		$	1,597
Capital Expenditures		$	3		$	154

_________________________

(a) Includes gains of $0.1 million and losses of $0.3 million, for the three months endedMarch 31, 2014 and 2013, respectively, as a result of marking derivative contracts to market and losses of $1.1 million for the three months endedMarch 31, 2014, compared to losses of $0.9 million for the three months endedMarch 31, 2013 from derivative contracts that settled during the period.

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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 the Texas Panhandle and Oklahoma. 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 our natural gas 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 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, 2014 and 2013, revenues minus cost of oil and condensate totaled $10.0 million and $1.7 million, respectively. The increase of $8.3 million during three months endedMarch 31, 2014 was primarily due to higher volatility and greater geographic basis spreads in natural gas prices in the first quarter of 2014, which enabled the Partnership to capitalize on its transportation agreements and physical product positions to generate higher margins. Volatility in the natural gas markets has subsided in the second quarter.

Corporate and Other Segment

		Three Months Ended March 31,
		2014			2013
	($ in thousands)
Revenues:
Commodity risk management losses, net		$	(14,944	)	$	(17,908	)
Intersegment elimination - Sales of natural gas and condensate		4			(11,305		)
Total revenue		(14,940		)	(29,213		)
Intersegment elimination - Cost of natural gas and condensate		(744		)	(11,112		)
General and administrative		21,391			18,847
Depreciation and amortization		704			377
Operating loss		(36,291		)	(37,325		)
Other expense:
Interest expense, net		(17,986		)	(17,084		)
Interest rate risk management losses, net		(290		)	(156		)
Other expense, net		(7		)	(8		)
Total other expense		(18,283		)	(17,248		)
Loss before income taxes		(54,574		)	(54,573		)
Income tax benefit		(953		)	(1,160		)
Segment loss		$	(53,621	)	$	(53,413	)

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

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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, 2014, losses in our commodity derivative portfolio decreased by $3.0 million as compared to the three months endedMarch 31, 2013. During the three months endedMarch 31, 2014, losses in our mark-to-market commodity derivative portfolio increased by $17.6 million as compared to the three months endedMarch 31, 2013, primarily due to increases in the natural gas, NGL and crude oil forward curves. Our gains from derivative contracts that settled during the three months endedMarch 31, 2014 decreased by $14.6 million, compared to the three months endedMarch 31, 2013. The decrease was due to higher natural gas and crude oil index prices, partially offset by lower NGL index prices, in relation to the strike prices of our settled contracts, as compared to the same period in the prior year. In addition, the decrease in realized gains is due to the higher level of direct NGL product contracts that settled during the three months endedMarch 31, 2013, as compared to the same period in 2014.

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, 2014 and 2013, 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, 2014, our Upstream Segment sold natural gas to our Panhandle Segment.

General and Administrative Expenses. General and administrative expenses increased by $2.5 million for the three months endedMarch 31, 2014, as compared to the same period in 2013. This increase was primarily due to $2.7 million of professional fees incurred during the three months endedMarch 31, 2014 related to potential contribution of our Midstream Business to Regency.

We do not allocate our general and administrative expenses to our operational segments.

Total Other Expense.  Total other expense primarily consists of gains and losses from our interest rate swaps and interest expense related to our senior secured credit facility and our senior unsecured notes. During the three months endedMarch 31, 2014, our interest rate risk management losses increased by $0.1 million, as compared to the three months endedMarch 31, 2013. For the three months endedMarch 31, 2014, we recognized unrealized gains of $1.4 million, as compared to unrealized gains of $1.5 million during the same periods in 2013. These unrealized mark-to-market gains did not have any impact on cash activities for the period, and are excluded by definition from our calculation of Adjusted EBITDA.

Interest expense increased by $0.9 million during the three months endedMarch 31, 2014, as compared to the three months endedMarch 31, 2013.  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.  The increase in interest expense is primarily due to increased borrowings on our revolving credit facility.

Income Tax (Benefit) Provision. Income tax provision for 2014 and 2013 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.

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Adjusted EBITDA

Adjusted EBITDA, as defined under "—Liquidity and Capital Resources — Non-GAAP Financial Measures," increased by $4.0 million from $53.6 million for the three months endedMarch 31, 2013 to $57.6 million for the three months endedMarch 31, 2014. The following table presents the changes in operations, by segment, impacting Adjusted EBITDA:

	Three Months Ended March 31,
	2014			2013			Change
Revenues minus cost of natural gas and NGLs - Midstream (a)	$	61,919		$	48,795		$	13,124
Revenues - Upstream (b)	55,230			47,302			7,928
Intercompany elimination revenues minus cost of natural gas and condensate	748			(193		)	941
Commodity derivative settlements - Corporate and Other	(4,611		)	9,998			(14,609		)
Total incremental revenues minus cost of natural gas and NGLs	113,286			105,902			7,384
Operating expenses - Midstream	25,049			21,969			3,080
Operating expenses - Upstream	15,289			14,116			1,173
General and administrative expenses (c)	15,359			16,200			(841		)
Adjusted EBITDA	$	57,589		$	53,617		$	3,972

_________________________

(a) Excludes mark-to-market gains/losses from the Marketing and Trading Segment.

(b) Excludes the impact of imbalances

(c) Excludes non-cash compensation charges related to our long-term incentive program and other non-recurring charges incurred during the three months endedMarch 31, 2014 related to the potential contribution of our Midstream Business to Regency.

LIQUIDITY AND CAPITAL RESOURCES

Historically, our sources of liquidity have included cash generated from operations, issuances of equity and debt securities, asset sales 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.

Assuming the successful completion of the Midstream Business Contribution, 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 following the completion of the Midstream Business Contribution will entail pursuing attractive upstream acquisitions and organic drilling opportunities. At such time, we may utilize any of various available financing sources, including proceeds from consummation of the Midstream Business Contribution, proceeds from the issuance of equity or debt securities, or borrowings from our senior secured revolving credit facility to fund all or a portion of our potential acquisitions and organic growth expenditures. 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. On April 23, 2014, we announced a temporary suspension in our distribution to preserve liquidity as a result of the delay in the expected closing of the Midstream Business Contribution. Until the Midstream Business Contribution is consummated, or should the Midstream Business Contribution not be consummated, we anticipate that our liquidity will continue to be constrained, notwithstanding the suspension in our distribution, and we would expect this to limit or prevent our ability to pursue growth opportunities. In such scenario, we would explore alternative means to enhance our liquidity, which could include asset sales, equity financings, the separation of our upstream and midstream businesses or other alternatives.

At March 31, 2014, our liquidity was limited by our amount of debt outstanding and by our debt ratios relative to the covenant levels specified in our revolving credit facility, as discussed further below. We expect the Midstream Business Contribution to significantly reduce our leverage and improve our liquidity. For a discussion of risks surrounding the Midstream Business Contribution, please review the section entitled "Risk Factors" beginning on page 56. We intend to use the net proceeds from the Midstream Business Contribution to reduce debt outstanding under the revolving credit facility. In addition, as part of the consideration for the Midstream Business Contribution, Regency is conducting an exchange offer for the full $550 million face value of our outstanding senior unsecured notes. If less than all the senior unsecured notes are tendered for exchange in the exchange offer, Regency has agreed to pay us a dollar amount equal to 110% of the difference between

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$550 million and the face value of the notes tendered. In this scenario, any of our senior unsecured notes that are not tendered for exchange would remain outstanding, and we would use the additional cash proceeds from Regency to repay borrowings under our credit facility or retain excess cash to pursue acquisitions. Our annual interest expense would initially be higher under this scenario than if all of our senior unsecured notes were exchanged, but we would receive more cash from Regency. On April 2, 2014, Regency, pursuant to the contribution agreement, launched their exchange offer. Any notes subscribed to be exchanged under this offering are contingent upon the closing of the contribution of the Midstream Business to Regency.

The Midstream Business Contribution was approved by our common unitholders on April 29, 2014, but remains subject to Federal Trade Commission approval. As a result, we can provide no assurance that the Midstream Business Contribution will be completed within our anticipated time frame, or at all. If the Midstream Business Contribution is not consummated, we will continue to be constrained in the near-term by limited liquidity and greater risk that our debt ratios may exceed the covenant levels in our revolving credit facility. In this event we will seek to fund our liquidity needs and reduce our debt levels through some combination of reduced spending, equity financings and asset sales.

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. As of March 31, 2014, a total of 1,521,086 units had been issued under this program for net proceeds of approximately $12.9 million. No sales were made under the program during the three months endedMarch 31, 2014.

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. With respect to maintenance capital expenditures intended to maintain the Partnership's natural gas, NGL, crude or sulfur production, we estimate these amounts based on current projections and expectations, and do not undertake to adjust any historical amounts based on the actual impact of such expenditures on production. As a result, the included amount of maintenance capital expenditures could fail to maintain production if actual performance does not meet our projections and expectations, including, without limitation, on account of: (i) unanticipated mechanical issues; (ii) unanticipated delays; (iii) poorer than expected production performance of our new wells and recompletions; and/or (iv) unanticipated loss of, or higher than anticipated decline in, existing 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 2014 capital budget anticipates that we will spend, assuming that we hold the Midstream Business for the full year, approximately $189 million in total, of which we expect approximately $74 million to be categorized as maintenance capital expenditures and $115 million to be categorized as growth capital expenditures. The allocation by business of our 2014 capital budget is as follows; approximately $130 million ($75 million of growth and $55 million of maintenance) relates to upstream capital expenditures, approximately $56 million ($39 million of growth and $17 million of maintenance) relates to midstream capital expenditures (assuming that we hold the Midstream Business for the full year) and approximately $3 million ($1 million of growth and $2 million of maintenance) relates to corporate capital expenditures. As discussed above, our liquidity is currently limited, and we expect it will continue to be limited until the Midstream Business Contribution is completed. Accordingly, we may reduce our expected capital expenditures due to liquidity constraints during the period in advance of closing the Midstream Business Contribution, and for the remainder of 2014 in the event the Midstream Business Contribution is not consummated, unless we are able to enhance our liquidity through other alternatives such as asset sales or equity financings.

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Our capital expenditures were approximately $51.1 million for the three months endedMarch 31, 2014, of which $18.5 million were related to maintenance capital expenditures and $32.5 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 through March 31, 2014 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 through March 31, 2014 is approximately $21.0 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 2015 at a cost of approximately $11.6 million net to our interest. We expect the facility will require further upgrades to repair or replace the sulfur recovery unit itself as early as 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.

In connection with making the distribution decision for the quarter ended March 31, 2014, the Board of Directors decided to suspend the quarterly distribution in order to preserve liquidity in advance of closing the contribution of the Midstream Business to Regency. As previously announced, we had received a request for additional information and documents on February 27, 2014 from the FTC in connection with contribution of the Midstream Business to Regency, which has extended our original time frame for closing the transaction and created a need to preserve greater liquidity in the interim to keep compliant with restrictive covenants and borrowing limitations in our senior secured revolving credit facility while funding certain growth capital expenditures and other financial obligations. We expect to recommend resuming the quarterly distribution following the closing of the Midstream Business Contribution, at which point we expect our total debt balance and liquidity position to be substantially improved. For a discussion of risks surrounding the Midstream Business Contribution, please review the section entitled "Risk Factors" beginning on page 56.

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, 2014, our borrowing base totaled

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approximately $815 million, and based on our outstanding borrowings and letters of credit, we had approximately $69.1 million of availability under the revolving credit facility. Due to certain large cash payments which occurred subsequent to March 31, 2014, however, our borrowings increased and our availability under the revolving credit facility was reduced to approximately $40 million by the end of April 2014. The upstream component of our borrowing base is scheduled to be re-determined by our lender group on June 1, 2014. Should this re-determination result in a reduction of the upstream borrowing base, our liquidity would be further reduced which could negatively impact our intended growth capital expenditures, and we could need to seek additional sources of liquidity such as asset sales or equity or debt offerings.

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 under the same indenture 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.

Debt Covenants

Our Credit Agreement requires us to maintain certain leverage, current and interest coverage ratios. On February 26, 2014, we entered into an amended credit agreement with our lender group which allowed for greater liquidity under the senior secured credit facility and for greater covenant flexibility for the first quarter of 2014. Specifically, the amendment provides for: (i) an increase in the Total Leverage Ratio and Senior Secured Leverage Ratio (as defined in the Credit Agreement) for the quarter ended March 31, 2014; (ii) the exclusion of fees and expenses associated with the strategic review and disposition of the Partnership’s Midstream Business from the calculation of Consolidated EBITDA (as defined in the Credit Agreement); (iii) deferring the redetermination of the Upstream Borrowing Base until June 1, 2014; and (iv) the option for us, at our election, to expand the multiplier for the Midstream Borrowing Base from 3.75x to 4.00x. On March 31, 2014, we elected to expand the multiplier for the Midstream Borrowing Base.

The following table presents the debt covenant levels specified in our revolving credit facility as of March 31, 2014:

Quarter Ended	Total Leverage Ratio	Senior Secured Leverage Ratio	Interest Coverage Ratio	Current Ratio
March 31, 2014	5.85	3.40	2.50	1.0
June 30, 2014	5.00	3.05	2.50	1.0
September 30, 2014	4.75	2.95	2.50	1.0
Thereafter	4.50	N/A	2.50	1.0

The following table presents the Partnership's actual covenant ratios as of March 31, 2014:

Interest coverage ratio	3.1
Total leverage ratio	5.4
Senior secured leverage ratio	3.06
Current ratio	1.1

As of March 31, 2014, we were in compliance with the financial covenants under the revolving credit facility, although our Target Leverage Ratio exceeded our long-term targeted levels. As discussed in previous filings, we conducted a process in 2013 in which we explored a number of alternatives to reduce our leverage ratio. That process culminated in the proposed contribution of our Midstream Business to Regency for total consideration of up to $1.325 billion. We expect the Midstream Business Contribution to substantially improve our liquidity and debt ratios through the elimination of significant

45

debt currently outstanding under our revolving credit facility and the proposed assumption of all of our senior unsecured notes via an exchange offer to be conducted by Regency. We received unitholder approval of the Midstream Business Contribution on April 29, 2014, but the completion of the transaction remains subject to regulatory approval. As a result, we can provide no assurance that the Midstream Business Contribution will be completed within our anticipated time frame, or at all. Should the Midstream Business Contribution not be consummated within the second quarter of 2014, we anticipate we may need to seek additional amendments to our Credit Agreement similar to those obtained with respect to the first quarter of 2014. Should the Midstream Business Contribution not be consummated at all, we intend to explore alternative means to reduce our leverage ratios, which may include asset sales or purchases, equity financings, the separation of our upstream and midstream businesses or other alternatives. For a discussion of risks surrounding the Midstream Business Contribution, please review the section entitled "Risk Factors" beginning on page 56. In addition, as discussed above, the upstream component of our borrowing base is scheduled to be re-determined by our lender group on June 1, 2014.

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, 2014, 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" of our Annual Report on Form 10-K for the year ended December 31, 2013.

Cash Flows

Cash Distributions

On January 28, 2014, we declared our fourth quarter 2013 cash distribution of $0.15 per unit to our common unitholders of record as of the close of business on February 7, 2014 (excluding certain restricted unit grants). The distribution was paid on February 14, 2014.

On April 23, 2014, we announced that we were temporarily suspending cash distributions to unitholders in advance of closing the Midstream Business Contribution.

Working Capital

Working capital is the amount by which current assets exceed current liabilities. As of March 31, 2014, working capital was a negative $70.7 million as compared to a positive $47.9 million as of December 31, 2013.

The net decrease in working capital of $22.8 million from December 31, 2013 to March 31, 2014, resulted primarily from the following factors:

• accounts payable increased by $32.6 million primarily as a result of higher volumes and the timing of payments of unbilled expenditures;

• risk management net working capital balance decreased by a net $7.7 million as a result of changes in the current portion of mark-to-market unrealized positions as a result of increases to the forward natural gas, oil and NGL price curves; and

• accrued liabilities increased by $12.5 million primarily reflecting accrued interest.

These decreases were partially offset primarily by the following factors:

• trade accounts receivable increased $19.9 million, primarily from higher volumes and the timing of the receipt of payments;

• prepayment and other current assets increased $4.4 million primarily due to the payment of insurance premiums; and

• cash and cash equivalents increased by $5.5 million primarily due to the timing of payments and the receipt of cash.

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Cash Flows for the Three Months Ended March 31, 2014, Compared to the Three Months Ended March 31, 2013

Cash Flow from Operating Activities. Cash flows from operating activities increased $27.7 million during the three months endedMarch 31, 2014, as compared to the three months endedMarch 31, 2013. This increase was driven by:

• Timing of cash payments and cash receipts; and

• An increase in our results of operations as a result of increased higher realized commodity prices, offset by increased operating costs.

Cash Flows from Investing Activities. Cash flows used in investing activities decreased $16.7 million during the three months endedMarch 31, 2014, as compared to the three months endedMarch 31, 2013. The decrease was due to a decline in capital expenditures during the three months endedMarch 31, 2014 of $16.2 million as compared to the same period in 2013. Capital expenditures were higher during the three months endedMarch 31, 2013 due in part to the construction of our Wheeler plant during the period. Construction of the Wheeler plant was completed in July 2013.

Cash Flows from Financing Activities. Cash flows provided by financing activities decreased $38.9 million during the three months endedMarch 31, 2014, as compared to the three months endedMarch 31, 2013. The decrease was driven by:

• Decreased in net proceeds of $92.4 million from our equity offering during the three months endedMarch 31, 2013, as compared to the same period in 2014;

• Net proceeds on our revolving credit facility were $17.2 million during the three months endedMarch 31, 2014, as compared to net payments of $30.7 million during the three months endedMarch 31, 2013; and

• Proceeds from derivative contracts decreased by $2.8 million during the three months endedMarch 31, 2014, as compared to the same period in 2013.

These decreases were partially offset by:

• Decreased distributions of $8.6 million during the three months endedMarch 31, 2014, as compared to the same period in 2013, as a result of our dropping our quarterly distribution rate to $0.15 (for the fourth quarter of 2013) compared to $0.22 (for the fourth quarter of 2012).

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" of this Form 10-Q.

Off-Balance Sheet Obligations

We had no off-balance sheet transactions or obligations as of March 31, 2014. 

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.

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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 GAAP.

We define Adjusted EBITDA as net income (loss) plus or (minus) income tax provision (benefit); interest-net, including realized interest rate risk management instruments and other expense; depreciation, depletion and amortization expense; impairment expense; other operating expense, non-recurring (which includes certain general and administrative expenses incurred in connection with the Partnership’s strategic review and Midstream Business Contribution); 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.

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 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 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 GAAP:

		Three Months Ended March 31,
		2014			2013
	($ 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		$	68,553		$	40,842
Add (deduct):
Depreciation, depletion, amortization and impairment		(42,605		)	(40,237		)
Amortization of debt issuance costs		(1,228		)	(1,036		)
Loss from risk management activities, net		(16,221		)	(19,214		)
Derivative settlements - operating		5,740			(6,406		)
Other		(3,554		)	(3,695		)
Accounts receivable and other current assets		24,307			4,551
Accounts payable and accrued liabilities		(51,136		)	(8,511		)
Other assets and liabilities		(2,419		)	192
Net loss		(18,563		)	(33,514		)
Add (deduct):
Interest expense, net		19,701			18,743
Depreciation, depletion, amortization and impairment		42,605			40,237
Income tax expense benefit		(953		)	(1,160		)
EBITDA		42,790			24,306
Add (deduct):
Loss (gain) from risk management activities, net		16,221			19,214
Total derivative settlements		(7,448		)	7,450
Restricted unit compensation expense		3,332			2,647
Non-cash mark-to-market Upstream imbalances		(6		)	—
Other (a)		2,700			—
ADJUSTED EBITDA		$	57,589		$	53,617

_______________________

(a) Includes $2.7 million of non-recurring general and administrative expenses incurred during the three month ended March 31, 2014 related to the potential contribution of our Midstream Business to Regency.

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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.

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, 2014, our commodity hedge portfolio totaled a net asset position of $(1.3) million, consisting of assets aggregating $13.2 million and liabilities aggregating $14.5 million. For additional information about our hedging activities and related fair values, see "Part I. Item 1. Financial Statements" 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 market and trade natural gas. 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-

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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, 2014, the fair value liability of these interest rate contracts totaled approximately $7.7 million. For additional information about our interest rate swaps and related fair values, see "Part I. Item 1. Financial Statements" 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, 2014, not including counterparties of our marketing and trading business, included 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. We maintain insurance policies with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, assure that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.

In March and April 2014, alleged Eagle Rock unitholders filed three class action lawsuits in the United States District Court for the Southern District of Texas on behalf of our public unitholders. The lawsuits name us, our Board of Directors, Regency Energy Partners, L.P. (“Regency”), and Regal Midstream LLC as defendants. One of the lawsuits also names our general partner and our general partner’s general partner as defendants. Plaintiffs in each lawsuit allege a variety of causes of action challenging Regency’s acquisition of our midstream assets, including alleged breaches of fiduciary or contractual duties, alleged aiding and abetting these alleged breaches of duty, and alleged violations of the Securities Exchange Act of 1934. The lawsuits allege that we (i) sold our midstream assets for inadequate value, (ii) engaged in an unfair sales process, (iii) agreed to contractual terms (the no-solicitation, fiduciary out, superior proposal, and termination fee provisions and the voting and support agreement) that would dissuade other potential acquirors from seeking to purchase the midstream assets, and (iv) failed to disclose material information in our definitive proxy statement concerning the analysis of our financial advisors, potential conflicts of the advisors (and directors), management’s financial projections, strategic alternatives, other potential acquirors, the bases for certain actions, and the background of the transaction. Based on these allegations, the plaintiffs seek in each case to enjoin us from proceeding with or consummating the sale of our midstream assets. To the extent that the sale is consummated before injunctive relief is granted, the plaintiffs seek to have the sale rescinded. The plaintiffs also seek monetary damages and attorneys’ fees. We believe that the lawsuits are without merit.

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, 2013, under the headings “Item 1. Business,” “Item 1A. Risk Factors,” “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” which risks could materially affect our business, financial condition or future results. Except for the risk factor set forth below, there have been no material changes in our risk factors from those described in our Annual Report on Form 10-K for the year ended December 31, 2013.

We are subject to litigation related to the Midstream Contribution.

We are subject to litigation related to the Midstream Contribution, see "Part II. Item 1. Legal Proceedings." It is possible that additional claims beyond those that have already been filed will be brought by the current plaintiffs or by others in an effort to enjoin the Midstream Contribution or seek monetary relief from us. We cannot predict the outcome of this lawsuit, or others, nor can we predict the amount of time and expense that will be required to resolve the lawsuit(s). An unfavorable resolution of any such litigation surrounding the Midstream Contribution could delay or prevent the consummation of the Midstream Contribution. In addition, the cost to us defending the litigation, even if resolved in our favor, could be substantial. We are seeking coverage for defendants under our Director and Officer insurance policies, to the extent costs are in excess of any applicable retention or deductible. Such litigation could also divert the attention of our management and our resources from day-to-day operations.

There can be no assurance that the Midstream Business Contribution will be completed in the anticipated time frame, or at all. The failure to complete the Midstream Business Contribution could adversely affect the price of our common units and otherwise have an adverse effect on us.

The completion of the Midstream Business Contribution is subject to the satisfaction of customary closing conditions. One of the most significant of these conditions is the need for the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the “HSR Act”). On February 7, 2014, we and

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Regency received a Request for Additional Information and Documentary Material from the Federal Trade Commission, also known as a “Second Request,” in connection with the Midstream Business Contribution. As a result, we have extended our expected time frame for closing the transaction, and there can be no assurance that we will be able to persuade the FTC to close its investigation in a timely enough fashion to satisfy the relevant closing condition in advance of July 31, 2014, the date after which Regency, subject to its own satisfaction of covenants (including its covenant related to antitrust approval), would be permitted to terminate the agreement if on or prior to such time all conditions to its obligations to consummate the transaction shall have not been satisfied.

There can be no assurance that the conditions to the completion of the Midstream Business Contribution, many of which are out of our control, will be satisfied. Among other things, we cannot be certain that the expiration or termination of the applicable waiting period under the HSR Act will occur within the required time frame.

The failure to complete the Midstream Business Contribution, including as a result of the delay associated with the Second Request, could have a material adverse effect on us. If the Midstream Business Contribution is not completed, we may not be able to find alternative means of reducing our debt and improving our liquidity position on favorable terms and in the timeframe required. This could enhance the risk that we may violate the leverage covenant ratio in our revolving credit facility and restrict our ability to access our credit facility, manage our liquidity, grow our businesses and pay distributions to our unitholders. Accordingly, if we are unable to complete the Midstream Business Contribution, we may be required to seek further amendments or waivers to our credit facility to provide for additional or extended increases in the Total Leverage Ratio and Senior Secured Leverage Ratio thereunder. If we are unable to negotiate any such required amendments or waivers, any breach of those covenants would constitute an event of default under our credit facility, which may cause the lenders to accelerate our obligation to repay outstanding borrowings thereunder. In addition, any such credit facility event of default could trigger cross-default provisions in our other indebtedness, potentially requiring us to repay such other indebtedness as well. In addition, the upcoming redetermination of the Upstream Borrowing Base on June 1, 2014 could reduce current availability under our revolving credit facility and have an adverse impact on our liquidity. Further, such a reduction in availability under our credit facility may require prepayment of previously borrowed funds thereunder, to the extent such outstanding borrowings exceed such reduced availability. Finally, if we are unable to realize the expected benefits to our outstanding debt balance and liquidity position as a result of a failure to complete the Midstream Business Contribution, we may be unable to resume our distribution in subsequent quarters.

Further, a failed transaction may result in negative publicity or a negative impression of us in the investment community and may affect our relationship with employees, vendors, creditors and other business partners. Accordingly, if the Midstream Business Contribution is not completed, the price of our common units may be adversely affected.

In the event of a failed transaction, we will still have to pay certain costs associated with the Midstream Business Contribution, which will be significant and will primarily consist of legal fees, accounting fees, financial printing and other related costs. These costs could adversely affect our operations and cash flows available for distributions to our unitholders, while not being offset by consideration for the Midstream Business Contribution.

In addition, pursuant to the Contribution Agreement, in certain specified circumstances if the Midstream Business Contribution is not consummated we may be required to pay Regency a termination fee, which would adversely affect our operations and cash flows available for distributions to our unitholders.

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	Third Amendment to the Amended and Restated Credit Agreement, effective as of February 26, 2014, among Eagle Rock Energy Partners, L.P., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the 10.1 to the registrant's Current Report on Form 8-K filed with the Commission on February 27, 2014).
10.2†	Raw Product Purchase and Sale Agreement, by and between Phillips 66 and Eagle Rock Field Services, L.P., dated December 23, 2013, (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K/A filed on February 28, 2014)
10.3***†	Eagle Rock Energy G&P, LLC 2014 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 28, 2014)
10.4***†	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/A filed on March 31, 2014)
31.1*	Certification of Periodic Financial Reports by Joseph A. Mills in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification of Periodic Financial Reports by Jeffrey P. Wood in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002
32.1**	Certification of Periodic Financial Reports by Joseph A. Mills in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002
32.2**	Certification of Periodic Financial Reports by Jeffrey P. Wood in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document

* Filed herewith.

** Furnished herewith.

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

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

54

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 2, 2014.

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 and Chief Financial Officer

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Index to Exhibits

Exhibit Number	Description
3.1	Certificate of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 of the registrant's registration statement on Form S-1 (File No. 333-134750)).
3.2	Second Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 of the registrant's current report on Form 8-K filed with the Commission on May 25, 2010).
3.3	Certificate of Limited Partnership of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.3 of the registrant's registration statement on Form S-1 (File No. 333-134750)).
3.4	Limited Partnership Agreement of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.4 of the registrant’s registration statement on Form S-1 (File No. 333-134750)).
3.5	Certificate of Formation of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 3.5 of the registrant's registration statement on Form S-1 (File No. 333-134750)).
3.6	Third Amended and Restated Limited Liability Company Agreement of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 42 of the registrant's current report on Form 8-K filed with the Commission on July 30, 2010).
3.7	Amendment No. 1 to the Second Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 4.1 of the registrant's current report on Form 8-K filed with the Commission on July 30, 2010).
10.1	Third Amendment to the Amended and Restated Credit Agreement, effective as of February 26, 2014, among Eagle Rock Energy Partners, L.P., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the 10.1 to the registrant's Current Report on Form 8-K filed with the Commission on February 27, 2014).
10.2†	Raw Product Purchase and Sale Agreement, by and between Phillips 66 and Eagle Rock Field Services, L.P., dated December 23, 2013, (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K/A filed on February 28, 2014)
10.3***†	Eagle Rock Energy G&P, LLC 2014 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 28, 2014)
10.4***†	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/A filed on March 31, 2014)
31.1*	Certification of Periodic Financial Reports by Joseph A. Mills in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification of Periodic Financial Reports by Jeffrey P. Wood in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002
32.1**	Certification of Periodic Financial Reports by Joseph A. Mills in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002
32.2**	Certification of Periodic Financial Reports by Jeffrey P. Wood in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document

* Filed herewith.

** Furnished herewith.

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

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