EAGLE ROCK ENERGY PARTNERS L P - FORM 10-Q

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EX-32.2 - EXHIBIT 32.2 (Q3 2014) - EAGLE ROCK ENERGY PARTNERS L P	exhibit322q32014.htm
EX-31.2 - EXHIBIT 31.2 (Q3 2014) - EAGLE ROCK ENERGY PARTNERS L P	exhibit312q32014.htm
EX-10.2 - EXHIBIT 10.2 (Q3 2014) - EAGLE ROCK ENERGY PARTNERS L P	exhibit102q32014.htm
EX-32.1 - EXHIBIT 32.1 (Q3 2014) - EAGLE ROCK ENERGY PARTNERS L P	exhibit321q32014.htm
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EX-31.1 - EXHIBIT 31.1 (Q3 2014) - EAGLE ROCK ENERGY PARTNERS L P	exhibit311q32014.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q



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

For the quarterly period ended September 30, 2014



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 160,122,819 common units outstanding as of October 27, 2014.

TABLE OF CONTENTS



		Page
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements	2
	Unaudited Condensed Consolidated Balance Sheets as of September 30, 2014 and December 31, 2013	2
	Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2014 and 2013	3
	Unaudited Condensed Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2014 and 2013	4
	Unaudited Condensed Consolidated Statement of Members' Equity for the nine months ended September 30, 2014	4
	Unaudited Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 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	37
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	51
Item 4.	Controls and Procedures	52
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	53
Item 1A.	Risk Factors	53
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	53
Item 3.	Defaults Upon Senior Securities	54
Item 4.	Mine Safety Disclosures	54
Item 5.	Other Information	54
Item 6.	Exhibits	54

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except unit amounts)



	September 30, 2014			December 31, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	593		$	76
Short-term investments	268,980			—
Accounts receivable (a)	33,648			17,250
Risk management assets	5,180			5,559
Prepayments and other current assets	11,029			6,123
Assets held for sale	—			1,259,382
Total current assets	319,430			1,288,390
PROPERTY, PLANT AND EQUIPMENT — Net	852,127			824,451
INTANGIBLE ASSETS — Net	3,121			3,268
DEFERRED TAX ASSET	2,224			1,438
RISK MANAGEMENT ASSETS	2,067			3,871
OTHER ASSETS	4,793			6,132
TOTAL	$	1,183,762		$	2,127,550

LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	44,086		$	50,158
Accrued liabilities	9,737			23,162
Taxes payable	2,019			149
Risk management liabilities	4,069			8,360
Liabilities held for sale	—			637,738
Total current liabilities	59,911			719,567
LONG-TERM DEBT	276,425			757,480
ASSET RETIREMENT OBLIGATIONS	46,784			37,306
DEFERRED TAX LIABILITY	32,721			34,097
RISK MANAGEMENT LIABILITIES	(2,781		)	2,826
OTHER LONG TERM LIABILITIES	4,943			2,395
COMMITMENTS AND CONTINGENCIES (Note 12)
MEMBERS' EQUITY (b)	765,759			573,879
TOTAL	$	1,183,762		$	2,127,550

________________________


(a)	Net of allowance for bad debt of $787 as of September 30, 2014 and $931 as of December 31, 2013.


(b)	157,406,536 and 156,644,153 common units were issued and outstanding as of September 30, 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 2,763,083 and 2,743,807 as of September 30, 2014 and December 31, 2013, respectively.

See accompanying notes to unaudited condensed consolidated financial statements.

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EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit amounts)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
REVENUE:
Natural gas, natural gas liquids, oil, condensate and sulfur	$	53,626		$	53,318		$	160,677		$	149,375
Commodity risk management gains (losses), net	27,967			(10,878		)	(147		)	(376		)
Other revenue	(369		)	45			(59		)	618
Total revenue	81,224			42,485			160,471			149,617
COSTS AND EXPENSES:
Operations and maintenance	10,707			8,773			33,112			30,052
Taxes other than income	3,184			3,731			10,571			9,730
General and administrative	12,235			13,515			37,530			40,166
Impairment	17,305			61,389			17,305			63,228
Depreciation, depletion and amortization	22,259			22,471			62,964			65,827
Total costs and expenses	65,690			109,879			161,482			209,003
OPERATING INCOME (LOSS)	15,534			(67,394		)	(1,011		)	(59,386		)
OTHER INCOME (EXPENSE):
Interest expense, net	(3,188		)	(4,647		)	(12,890		)	(14,211		)
Interest rate risk management losses, net	(81		)	(459		)	(942		)	(766		)
Other income (expense), net	4,080			3			4,083			(32		)
Total other income (expense)	811			(5,103		)	(9,749		)	(15,009		)
INCOME (LOSS) BEFORE INCOME TAXES	16,345			(72,497		)	(10,760		)	(74,395		)
INCOME TAX BENEFIT	(886		)	(2,155		)	(2,636		)	(4,260		)
INCOME (LOSS) FROM CONTINUING OPERATIONS	17,231			(70,342		)	(8,124		)	(70,135		)
DISCONTINUED OPERATIONS, NET OF TAX	249,057			(21,223		)	212,808			(38,912		)
NET INCOME (LOSS)	$	266,288		$	(91,565	)	$	204,684		(109,047		)



NET INCOME (LOSS) PER COMMON UNIT—BASIC AND DILUTED:
Income (Loss) from Continuing Operations
Common units - Basic	$	0.11	$	(0.45	)	$	(0.05	)	$	(0.47	)
Common units - Diluted	$	0.11	$	(0.45	)	$	(0.05	)	$	(0.47	)
Discontinued Operations
Common units - Basic	$	1.56	$	(0.14	)	$	1.34		$	(0.26	)
Common units - Diluted	$	1.56	$	(0.14	)	$	1.34		$	(0.26	)
Net Income (Loss)
Common units - Basic	$	1.67	$	(0.59	)	$	1.29		$	(0.73	)
Common units - Diluted	$	1.67	$	(0.59	)	$	1.29		$	(0.73	)
Weighted Average Units Outstanding
Common units - Basic	157,375		156,079			156,995			152,618
Common units - Diluted	158,400		156,079			157,624			152,618

See accompanying notes to unaudited condensed consolidated financial statements.

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EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)



	Three Months Ended September 30,					Nine Months Ended September 30,
	2014		2013			2014		2013
Net income (loss)	$	266,288	$	(91,565	)	$	204,684	$	(109,047	)
Other comprehensive income:
Gain on short-term investments	3,381		—			3,381		—
COMPREHENSIVE INCOME (LOSS)	$	269,669	$	(91,565	)	$	208,065	$	(109,047	)

See accompanying notes to unaudited condensed consolidated financial statements.

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF MEMBERS’ EQUITY

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2014

(In thousands, except unit amounts)



	Number of Common Units		Common Units			Accumulated Other Comprehensive Income	Total
BALANCE — December 31, 2013	156,644,153		$	573,879		—	$	573,879
Net income	—		204,684				204,684
Gain on short-term investments	—		—			3,381	3,381
Distributions	—		(23,801		)	—	(23,801		)
Vesting of restricted units	1,035,691		—			—	—
Repurchase of common units	(273,308	)	(1,171		)	—	(1,171		)
Equity based compensation	—		8,787			—	8,787
BALANCE — September 30, 2014	157,406,536		$	762,378		3,381	$	765,759

See accompanying notes to unaudited condensed consolidated financial statements.

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EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)



	Nine Months Ended September 30,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	204,684		$	(109,047	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Discontinued operations	(212,808		)	38,912
Depreciation, depletion and amortization	62,964			65,827
Impairment	17,305			63,228
Amortization of debt issuance costs	1,878			1,557
Loss from risk management activities, net	1,089			1,142
Derivative settlements	(4,047		)	5,979
Equity-based compensation	6,990			7,749
Loss on sale of assets	—			—
Other operating income	—			—
Other	(68		)	(426		)
Changes in assets and liabilities—net of acquisitions:
Accounts receivable	(16,398		)	11,715
Prepayments and other current assets	(4,906		)	2,392
Accounts payable	(7,414		)	(3,852		)
Accrued liabilities	(2,402		)	14,860
Other assets	(88		)	204
Other current liabilities	718			(1,621		)
Net cash provided by operating activities	47,497			98,619
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(106,664		)	(117,283		)
Net cash used in investing activities	(106,664		)	(117,283		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	416,700			463,700
Repayment of long-term debt	(897,800		)	(418,200		)
Payment of debt issuance costs	(410		)	—
Proceeds from derivative contracts	(5,163		)	1,052
Common unit issued in equity offerings	—			102,388
Issuance costs for equity offerings	—			(4,490		)
Repurchase of common units	(1,171		)	(1,000		)
Distributions to members and affiliates	(23,801		)	(102,079		)
Net cash (used in) provided by financing activities	(511,645		)	41,371
CASH FLOWS FROM DISCONTINUED OPERATIONS:
Operating activities	31,070			53,575
Investing activities	540,259			(76,231		)
Net cash provided by (used in) discontinued operations	571,329			(22,656		)
NET INCREASE IN CASH AND CASH EQUIVALENTS	517			51
CASH AND CASH EQUIVALENTS—Beginning of period	76			25
CASH AND CASH EQUIVALENTS—End of period	$	593		76

NONCASH INVESTING AND FINANCING ACTIVITIES:
Units received in divestiture	$	265,599		$	—
Investments in property, plant and equipment, not paid	$	10,811		$	18,759
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid—net of amounts capitalized	$	40,394		$	37,449
Cash paid for taxes	$	—		$	59

See accompanying notes to unaudited condensed consolidated financial statements.

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. ORGANIZATION AND DESCRIPTION OF BUSINESS

Description of Business—Eagle Rock Energy Partners, L.P. ("Eagle Rock Energy" or the "Partnership") is a growth-oriented master limited partnership engaged in (a) the exploitation, development, and production of oil and natural gas properties and (b) ancillary gathering, compressing, treating, processing and marketing services with respect to its production of natural gas, natural gas liquids, condensate and crude oil (collectively, the "Upstream Business"). The Partnership's assets, located primarily in South Alabama (where it also operates the associated gathering and processing assets), Texas, Oklahoma, Mississippi and Arkansas, are characterized by long-lived, high-working interest properties with extensive production histories and development opportunities.

On July 1, 2014, the Partnership contributed its business of third-party 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 (collectively, the “Midstream Business”) to Regency Energy Partners LP ("Regency") (such contribution, the "Midstream Business Contribution"). The consideration received by the Partnership for the Midstream Business Contribution included: (i) $576.2 million of cash; (ii) 8,245,859 Regency common units (valued at approximately $265.6 million based on the closing price of Regency common units on June 30, 2014) and (iii) the exchange of $498.9 million face amount of the Partnership's outstanding unsecured senior notes ("Senior Notes") for an equivalent amount of Regency unsecured senior notes. $51.1 million of the Partnership's Senior Notes did not exchange and remain outstanding under an amended indenture with substantially all of the restrictive covenants and certain events of default eliminated.

Accordingly, prior periods have been retrospectively adjusted to reflect the Midstream Business's assets and liabilities as held for sale and operations as discontinued (see Note 16) in the financial statements included in this report. As a result of this transaction, the Partnership now will only report as one segment.

The general partner of Eagle Rock Energy is Eagle Rock Energy GP, L.P., and the general partner of Eagle Rock Energy GP, L.P. is Eagle Rock Energy G&P, LLC, both of which are wholly-owned subsidiaries of the Partnership.

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Principles of Consolidation—The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements presented in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2013 (the "2013 10-K") and the Partnership's Form 8-K filed on September 17, 2014, which retrospectively adjusted the consolidated financial statements and related notes included in the 2013 10-K for the discontinued operations of the Partnership's Midstream Business. In the opinion of management, the accompanying unaudited condensed consolidated financial statements contain all appropriate adjustments, all of which are normally recurring adjustments unless otherwise noted, considered necessary to present fairly the financial position of the Partnership and its consolidated subsidiaries and the results of operations and cash flows for the respective periods. Operating results for the three and nine months ended September 30, 2014 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2014.

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 the 2013 10-K and its Form 8-K filed on September 17, 2014. 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

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

Short-term Investments— A portion of the consideration received for the Midstream Business Contribution included Regency common units, as further described in Note 1. These common units have a readily determinable fair value, are being classified as available-for-sale equity securities and are recorded as short-term investments on the unaudited condensed consolidated balance sheets. Unrealized gains and losses associated with increases and decreases in the fair value of these securities are included in other comprehensive income until such time that the gains and losses become realized and then will be included in the condensed consolidated statements of operations. Distributions received from Regency as a result of holding these common units are recorded as other income on the unaudited condensed consolidated statements of income. For the three and nine months ended September 30, 2014, the Partnership received and recorded distributions from Regency of $4.0 million, which have been recorded as part of Other Income (Expense) within the unaudited condensed consolidated statement of operations.

Inventory—Inventory is stated at the lower of cost or market, with cost being determined using the average cost method. At December 31, 2013, the Partnership had $1.0 million of crude oil finished goods inventory, which is recorded as part of assets held for sale 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, the Partnership reviews its proved properties at the field level when management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a negative revision or unfavorable projection of future oil and natural gas reserves and/or forward prices that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels.

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 Note 4 for further discussion on impairment charges.

Revenue Recognition—Revenues associated with sales of natural gas, NGLs, crude oil, condensate and sulfur are recognized when title passes to the customer, which is when the risk of ownership passes to the customer and physical delivery occurs.

Revenues for the Partnership's Midstream Business included the sale of natural gas, NGLs, crude oil, condensate, sulfur and helium and from the compression, gathering, processing, treating and transportation of natural gas. Revenues associated with transportation and processing fees were recognized in the period when the services are provided. These revenues have been classified as discontinued operations within the unaudited condensed consolidated statements of operations.

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Natural gas revenues produced from the Partnership's natural gas interests are 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. Imbalances are reflected as adjustments to reported natural gas reserves and future cash flows. The Partnership had long-term imbalance payables totaling $0.3 million as of September 30, 2014 and December 31, 2013.

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. As of December 31, 2013, the Partnership had imbalance receivables totaling $0.7 million and imbalance payables totaling $1.6 million. All transportation and exchange imbalance receivables and imbalance payables have been classified as assets and liabilities held for sale, respectively, within the unaudited condensed consolidated balance sheet. 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, and have been classified as discontinued operations within the unaudited condensed consolidated statements of operations.

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. The Partnership uses financial instruments such as swaps, collars and other derivatives to mitigate the risks to cash flows resulting from changes in commodity prices and interest rates. The Partnership recognizes these financial instruments on its unaudited condensed consolidated balance sheet at the instrument's fair value with changes in fair value reflected in the unaudited condensed consolidated statement of operations, as the Partnership has not designated any of these derivative instruments as hedges. The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as a financing activity in the unaudited condensed consolidated statement of cash flows. See Note 10 for a description of the Partnership's risk management activities.

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

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 decided to early adopt this guidance in relation to its transaction to contribute its Midstream Business to Regency (see Notes 1 and 16).

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

On May 28, 2014, the FASB issued new guidance related to revenue from contracts with customers. This new guidance outlines a single comprehensive model for entities to use and supersedes most current revenue recognition guidance, including industry-specific guidance. This guidance is effective for annual reporting periods (including interim reporting periods within those periods) beginning after December 15, 2016. Early application of the guidance is not permitted. The Partnership is currently evaluating the potential impact, if any, of the adoption of this new guidance on its financial statements.

On August 27, 2014, the FASB issued new guidance on determining how to perform going concern assessments and when to disclose going concern uncertainties in the financial statements. The new guidance requires management to perform interim and annual assessments of an entity's ability to continue as a going concern within one year after the date the financial statements are issued. An entity must provide certain disclosures if conditions or events raise substantial doubt about the entity's ability to continue as a going concern. This guidance is effective for annual periods ending after December 15, 2016, 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:



	September 30, 2014			December 31, 2013
	($ in thousands)
Equipment and machinery	$	101		$	101
Vehicles and transportation equipment	212			212
Office equipment, furniture, and fixtures	3,020			1,391
Computer equipment	13,212			12,247
Proved properties	1,248,274			1,156,895
Unproved properties	7,914			10,022
Construction in progress	1,304			6,636
	1,274,037			1,187,504
Less: accumulated depreciation, depletion and amortization	(421,910		)	(363,053		)
Net property, plant and equipment	$	852,127		$	824,451

Amounts in the table above do not include the property, plant and equipment related to the Partnership's Midstream Business, as these amounts have been classified as assets held for sale within the unaudited condensed consolidated balance sheet for December 31, 2013 and were sold on July 1, 2014 (see Note 16).

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	($ in thousands)
Depreciation	$	665	$	415	$	2,251	$	1,418
Depletion	$	20,736	$	22,004	$	59,742	$	64,274

Impairment expense:
Proved properties (a)	$	17,305	$	61,389	$	17,305	$	63,228

________________________________

(a)

During the three and nine months ended September 30, 2014, the Partnership incurred impairment charges related to certain proved properties in our East Texas and Permian regions due to lower commodity prices, higher operating costs and lower well performance. During the three and nine months ended September 30, 2013, the Partnership incurred impairment charges related to certain proved properties, primarily in the Permian region, due to lower commodity prices, higher operating costs and lower reserve forecasts.

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The table above does not include amounts related to the Partnership's Midstream Business as these amounts have been classified as part of discontinued operations within the unaudited condensed consolidated statement of operations (see Note 16).

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 increases in current abandonment costs, 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)	$	48,564		$	38,991
Additional liabilities	29			955
Liabilities settled	(1,218		)	(1,334		)
Revision to liabilities	(105		)	6,773
Accretion expense	2,428			2,238
Asset retirement obligations—September 30 (a)	$	49,698		$	47,623

_____________________________________


(a)	As of September 30, 2014 and December 31, 2013, $2.9 million and $11.3 million, respectively, were included within accrued liabilities in the unaudited condensed consolidated balance sheets.

Amounts in the table above do not include the balances or the activity related to asset retirement obligations related to the Partnership's Midstream Business, as these amount have been classified as liabilities held for sale within the unaudited condensed consolidated balance sheet for December 31, 2013 and were sold on July 1, 2014 and discontinued operations within the unaudited condensed consolidated statement of operations (see Note 16).

During the nine months ended September 30, 2014 and 2013, the Partnership made decrease revisions of $0.1 million and increase revisions of $6.8 million, respectively, to 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, which the Partnership amortizes over the estimated useful life of 20 years.

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Intangible assets consisted of the following:



	September 30, 2014			December 31, 2013
	($ in thousands)
Rights-of-way and easements—at cost	$	3,920		$	3,920
Less: accumulated amortization	(799		)	(652		)
Net intangible assets	$	3,121		$	3,268

Amounts in the table above do not include the intangible assets related to the Partnership's Midstream Business, as these amounts have been classified as assets held for sale within the unaudited condensed consolidated balance sheet for December 31, 2013 and were sold on July 1, 2014 (see Note 16).

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	($ in thousands)
Amortization	$	49	$	49	$	147	$	147

Estimated future amortization expense related to the intangible assets at September 30, 2014, is as follows (in thousands):



Year ending December 31,
2014	$	49
2015	$	196
2016	$	196
2017	$	196
2018	$	196
Thereafter	$	2,288

NOTE 7. LONG-TERM DEBT

Long-term debt consisted of the following:



	September 30, 2014			December 31, 2013
	($ in thousands)
Revolving credit facility:	$	225,700		$	706,800
Senior notes:
8.375% Senior Notes due 2019	51,120			51,120
Unamortized bond discount	(395		)	(440		)
Total Senior Notes	50,725			50,680
Total long-term debt	$	276,425		$	757,480

Amounts in the table above do not include the portion of the Senior Notes that were exchanged for Regency unsecured senior notes upon the completion of the Midstream Business Contribution on July 1, 2014 (see Note 1). These Senior Notes have been classified as part of liabilities held for sale within the unaudited condensed consolidated balance sheet for December 31, 2013 and were sold on July 1, 2014.

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

On July 1, 2014, the Partnership used the cash received from Regency for the Midstream Business Contribution (see Note 1) to paydown $570.4 million outstanding under its Credit Agreement.

The Partnership currently pays an annual fee of 0.45% on the unused commitment under our Amended and Restated Credit Agreement (as amended, the “Credit Agreement”) with a syndicate of banks led by Wells Fargo, N.A. as administrative agent, and Bank of America, N.A. and Royal Bank of Scotland plc as co-syndication agents. As of September 30, 2014, the Partnership had approximately $104.3 million of availability under the Credit Agreement, based on its commitments of $330 million and before considering covenant limitations.

On February 26, 2014, the Partnership and its lender group amended the Credit Agreement to allow for greater liquidity under the Credit Agreement and for greater covenant flexibility for the first quarter of 2014. Specifically, the amendment provided 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 (as defined in the Credit Agreement) until June 1, 2014; and (iv) the option for the Partnership, at its election, to expand the multiplier for the Midstream Borrowing Base (as defined in the Credit Agreement) from 3.75x to 4.00x. The Partnership exercised this option to expand the multiplier for the Midstream Borrowing Base on March 31, 2014.

On May 28, 2014 the Partnership and its lender group further amended the Credit Agreement to allow for greater liquidity and certain covenant relief through the second quarter of 2014. The amendment, among other items, provided for an increase in the midstream component of the Credit Agreement's total borrowing base and provided for an increase in the Total Leverage Ratio and Senior Secured Leverage Ratio (as defined in the Credit Agreement) for the quarter ended June 30, 2014. The amendment also provided that (i) effective June 1, 2014, the upstream component of the borrowing base of the Credit Agreement to decrease from $380 million to $330 million as part of the Partnership's regular semi-annual redetermination by its commercial lenders, (ii) the next borrowing base redetermination will be September 1, 2014, which was postponed to coincide with the amendment signed on October 10, 2014 (see below), and (iii) that such reduction would automatically reduce aggregate commitments of the lenders under the Credit Agreement, with further automatic reductions in such aggregate commitments in amounts equal to, and upon, any future reductions in the borrowing base.

On October 10, 2014, the Partnership entered into the Fifth Amendment (the "Fifth Amendment") to its Amended and Restated Credit Agreement (as amended, the "Credit Agreement"). The Fifth Amendment, among other items, provided for current commitments totaling $320 million, with the ability to increase commitments up to a total aggregate amount of $1.2 billion. The Fifth Amendment coincided with the semi-annual borrowing base redetermination by the Partnership's commercial lenders, and the next redetermination will be in April 2015. The amendment extended the maturity to October 2019. In addition, as a result of the completion of the Midstream Business contribution, the Partnership's borrowing base under the Credit Agreement is now strictly based on the value of its oil and natural gas properties and its commodity derivative contracts, which was formerly referred to as the upstream component of the borrowing base.

Per agreement with the Partnership's commercial lenders, the revised covenant structure specified in the Amended Credit Agreement (see above) was applied as of September 30, 2014. The following table presents the revised debt covenant levels specified in the Amended Credit Agreement:



Quarter Ended	Total Leverage Ratio (a)	Current Ratio (b)
September 30, 2014 and Thereafter until Maturity (October 2019)	4.0	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 September 30, 2014:



Total leverage ratio	2.34
Current ratio	7.32

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The calculation of the ratios above includes the amounts classified in the unaudited condensed consolidated financial statements as held for sale and as discontinued operations.

As of September 30, 2014, the Partnership was in compliance with the financial covenants under the Amended Credit Agreement. In addition, the Partnership was in compliance with the financial covenants under the Credit Agreement, prior to the amendment entered into on October 10, 2014 in effect as of September 30, 2014.

$51.1 million of the Partnership's Senior Notes did not exchange as part of the transaction with Regency and remain outstanding (See Note 1) under an amended indenture with substantially all of the restrictive covenants and certain events of default eliminated.

NOTE 8. MEMBERS’ EQUITY

At September 30, 2014 and December 31, 2013, there were 157,406,536 and 156,644,153 unrestricted common units outstanding, respectively. In addition, there were 2,763,083 and 2,743,807 unvested restricted common units outstanding at September 30, 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 nine months ended September 30, 2014, no units were issued under this program. The last time units were issues under this program was during the three month period ended June 30, 2013.

The table below summarizes the distributions paid or payable and declared for the quarters listed below:



Quarter Ended	Distribution per Common Unit		Record Date*	Payment Date
December 31, 2013+	$	0.15	February 7, 2014	February 14, 2014
March 31, 2014**	$	—	N/A	N/A
June 30, 2014**	$	—	N/A	N/A
September 30, 2014+	$	0.07	November 7, 2014	November 14, 2014

_____________________________


+	The units eligible for the distribution exclude certain restricted units under the LTIP.


*	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.

NOTE 9. RELATED PARTY TRANSACTIONS

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Affiliates of Natural Gas Partners:	($ in thousands)
Natural gas purchases from affiliates	$	—	$	670	$	2,091	$	1,212



	September 30, 2014		December 31, 2013
Affiliates of Natural Gas Partners:	($ in thousands)
Payable (related to natural gas purchases)	$	—	$	18

The transactions above were all related to the Partnership's Midstream Business and have been classified as part of discontinued operations within the unaudited condensed consolidated statement of operations and liabilities held for sale within the unaudited condensed consolidated balance sheet (see Note 16).

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 10. RISK MANAGEMENT ACTIVITIES

Interest Rate Swap Derivative Instruments

To reduce interest expense variability, the Partnership has entered into interest rate swaps that effectively convert 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 September 30, 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 Credit Agreement. 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 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 Credit Agreement. 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 is derived from the proved reserves estimates, adjusted for certain expenses and revenue deductions that are a function of volume and price. 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 has often hedged the changes in future NGL prices using crude oil hedges because NGL prices historically had been highly correlated to crude oil prices and hedging NGLs directly was less attractive due to the relative illiquidity in the NGL forward market. Likewise, the Partnership has used natural gas hedges to hedge a portion of its expected future ethane production because forward prices for ethane are more often heavily discounted from its current prices than natural gas, ethane prices have been correlated to natural gas prices in the past, and 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 which has reduced the effectiveness of some of our hedges in reducing the impact of price fluctuations. At this time, our practice is to not add new proxy hedges to our portfolio and to seek opportunities to convert our existing ones to direct product hedges.

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 Credit Agreement, 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 September 30, 2014, that will mature during the years ended December 31, 2014 through 2019:



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)	2,940,000	$	4.51
Crude Oil	Swap (Pay Floating/Receive Fixed)	312,000	$	96.14
Crude Oil	Swap (Pay Fixed/Receive Floating)	49,785	$	92.53
Propane	Swap (Pay Floating/Receive Fixed)	2,394,000	$	1.06
IsoButane	Swap (Pay Floating/Receive Fixed)	567,000	$	1.31
Normal Butane	Swap (Pay Floating/Receive Fixed)	1,033,200	$	1.30
Contracts Maturing in 2015
Natural Gas	Swap (Pay Floating/Receive Fixed)	10,800,000	$	4.07
Crude Oil	Costless Collar	480,000	$	90.00	$	97.55
Crude Oil	Swap (Pay Floating/Receive Fixed)	630,000	$	89.78
Contracts Maturing in 2016
Natural Gas	Swap (Pay Floating/Receive Fixed)	9,480,000	$	4.25
Crude Oil	Swap (Pay Floating/Receive Fixed)	936,000	$	84.66
Contracts Maturing in 2017
Crude Oil	Swap (Pay Floating/Receive Fixed)	444,000	$	89.24
Contracts Maturing in 2018
Crude Oil	Swap (Pay Floating/Receive Fixed)	396,000	$	88.78
Contracts Maturing in 2019
Crude Oil	Swap (Pay Floating/Receive Fixed)	348,000	$	88.39

_______________________


(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

Prior to the consummation of the Midstream Business Contribution, as described in Note 1, the Partnership's Midstream Business conducted natural gas marketing and trading activities intended to capitalize on favorable price differentials between various receipt and delivery locations. This business was contributed to Regency as part of the Midstream Business Contribution completed on July 1, 2014. The operations related to this business are included within discontinued operations (see Note 16).

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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 September 30, 2014 and December 31, 2013:



	As of September 30, 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	$	(4,874	)
Commodity derivatives - assets	Current assets	5,679			Current liabilities	951
Commodity derivatives - assets	Long-term assets	3,320			Long-term liabilities	2,781
Commodity derivatives - liabilities	Current assets	(496		)	Current liabilities	(146		)
Commodity derivatives - liabilities	Long-term assets	(1,253		)	Long-term liabilities	—
Total derivatives		$	7,250			$	(1,288	)

	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	6,841			Current liabilities	1,043
Commodity derivatives - assets	Long-term assets	4,669			Long-term liabilities	202
Commodity derivatives - assets	Assets held-for-sale	6,017			Liabilities held-for-sale	1,973
Commodity derivatives - liabilities	Current assets	(1,282		)	Current liabilities	(3,193		)
Commodity derivatives - liabilities	Long-term assets	(798		)	Long-term liabilities	(143		)
Commodity derivatives - liabilities	Assets held-for-sale	(824		)	Liabilities held-for-sale	(5,658		)
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 September 30,						Nine Months Ended September 30,
		2014			2013			2014			2013
		($ in thousands)
Interest rate derivatives	Interest rate risk management losses, net	$	(81	)	$	(459	)	$	(942	)	$	(766	)
Commodity derivatives	Commodity risk management gains (losses), net	27,967			(10,878		)	(147		)	(376		)
Commodity derivatives	Discontinued operations	—			(15,956		)	(15,879		)	(13,873		)
Commodity derivatives - trading	Discontinued operations	—			(214		)	(2,404		)	(230		)
	Total	$	27,886		$	(27,507	)	$	(19,372	)	$	(15,245	)

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

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

valuation technique. The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).

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

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

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

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

As of September 30, 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. In addition, the Partnership recorded its investments in equity securities at fair value, and classified the inputs as Level 1.

The following tables disclose the fair value of the Partnership's derivative instruments and equity investments as of September 30, 2014 and December 31, 2013:



	As of September 30, 2014
	Level 1		Level 2			Level 3		Netting (a)			Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	8,555		$	—	$	(4,725	)	$	3,830
Natural gas derivatives	—		4,115			—		(690		)	3,425
NGL derivatives	—		61			—		(66		)	(5		)
Equity investments	268,980		—			—		—			268,980
Total	$	268,980	$	12,731		$	—	$	(5,481	)	$	276,230

Liabilities:
Crude oil derivatives	$	—	$	(1,270	)	$	—	$	4,725		$	3,455
Natural gas derivatives	—		(559		)	—		690			131
NGL derivatives	—		(66		)	—		66			—
Interest rate swaps	—		(4,874		)	—		—			(4,874		)
Total	$	—	$	(6,769	)	$	—	$	5,481		$	(1,288	)

____________________________


(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	$	—	$	6,151		$	—	$	(1,716	)	$	4,435
Natural gas derivatives	—		6,562			—		(1,567		)	4,995
NGL derivatives	—		42			—		(42		)	—
Total	$	—	$	12,755		$	—	$	(3,325	)	$	9,430

Liabilities:
Crude oil derivatives	$	—	$	(1,792	)	$	—	$	1,716		$	(76	)
Natural gas derivatives	—		(2,503		)	—		1,567			(936		)
NGL derivatives	—		(1,121		)	—		42			(1,079		)
Interest rate swaps	—		(9,095		)	—		—			(9,095		)
Total	$	—	$	(14,511	)	$	—	$	3,325		$	(11,186	)

____________________________


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

Gains and losses, from continuing operations, 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, from continuing operations, 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 Notes 4 and 6 for a further discussion of the impairment charges recorded during the three and nine months ended September 30, 2014. The following table discloses the fair value of the Partnership's assets measured at fair value on a nonrecurring basis during the nine months ended September 30, 2014:



	Nine Months Ended September 30,
	2014		Level 1		Level 2		Level 3		Total Losses
	($ in thousands)
Proved properties	$	12,376	$	—	$	—	$	12,376	$	17,305
Plant assets	$	52	$	—	$	—	$	52	$	132
Pipeline assets	$	746	$	—	$	—	$	746	$	1,904
Rights-of-way	$	24	$	—	$	—	$	24	$	61

The plant, pipeline and rights-of-way assets and related impairment losses included in the table above are all attributable to the Partnership's Midstream Business and have been classified as discontinued operations within the unaudited condensed consolidated statement of operations, respectively (see Note 16).

The Partnership calculated the fair value of the impaired assets using a discounted cash flow analysis to determine the excess of the asset's carrying value over its fair value. Significant inputs to the valuation of fair value of the proved properties, 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.

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EAGLE ROCK ENERGY PARTNERS, L.P.

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As of September 30, 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 bore interest at a fixed rate; based on the market price of the Senior Notes as of September 30, 2014 and December 31, 2013, the Partnership estimates that the fair value of the Senior Notes was $52.2 million and $55.7 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.

NOTE 12. COMMITMENTS AND CONTINGENCIES

Litigation—The Partnership and its operating subsidiaries are subject to lawsuits which arise from time to time in the ordinary course of business. The Partnership had no accruals as of September 30, 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. Lawsuits the Partnership and/or its operating subsidiaries were subject to relating to its midstream business were assumed by Regency on July 1, 2014 as part of the Midstream Business Contribution.

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, 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 alleged a variety of causes of action challenging the Midstream Business Contribution, 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 "Exchange Act"). 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 to have the sale rescinded, monetary damages and attorneys’ fees.

In August 2014, the court consolidated the lawsuits into an action styled In re Eagle Rock Energy Partners, L.P. Securities Litigation, No. 4:14-cv-00521 and appointed a lead plaintiff and co-lead counsel. The lead plaintiff has a deadline of November 3, 2014 to file a consolidated amended complaint.

We cannot predict the outcome of this lawsuit, or the amount of time and expense that will be required to resolve it. The Partnership, however, intends to defend vigorously against the claims asserted.

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; 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

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results of operations, financial position or cash flows. At September 30, 2014 and December 31, 2013, the Partnership had accrued approximately $2.6 million and $2.5 million for environmental matters, respectively. As of July 1, 2014, in connection with the Midstream Business Contribution, Regency agreed to indemnify the Partnership for losses arising from the Midstream Business, including potential losses associated with these laws and regulations, and the Partnership agreed to use commercially reasonable efforts to mitigate such losses. Environmental accruals related to the Partnership's Midstream Business have been classified as liabilities held for sale within the unaudited condensed consolidated balance sheet (see Note 16).

Retained Revenue Interest—Certain of the Partnership's assets 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 $0.4 million and $2.0 million for the three and nine months ended September 30, 2014, respectively, and $0.8 million and $1.7 million for the three and nine months ended September 30, 2013, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term.

NOTE 13. INCOME TAXES

Provision for Income Taxes -The Partnership is a limited partnership for federal and state income tax purposes, in which income tax liabilities and/or benefits of the Partnership are passed through to its unitholders. In the State of Texas, limited partnerships are directly subject to the Texas margin tax, which liability is not passed through to Partnership unitholders. In addition, certain of the Partnership's subsidiaries are Subchapter C-corporations subject to federal and state income taxes. During the three and nine months ended September 30, 2014, the Partnership recognized an income tax benefit of $0.9 million and $2.6 million, respectively and $2.2 million and $4.3 million during the three and nine months ended September 30, 2013, respectively. The change in the Partnership's tax benefit from period to period is primarily due to changes in income generated by the Partnership's taxable entities.

NOTE 14. EQUITY-BASED COMPENSATION

Eagle Rock Energy G&P, LLC 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 14,500,000 common units to be granted either as options, restricted units or phantom units, of which, as of September 30, 2014, a total of 6,269,084 common units remained available for issuance (which calculation reserves the maximum common units (i.e., 200%) that may potentially be earned and vested in respect of the outstanding performance units). Grants under the LTIP are made at the discretion of the board and as of September 30, 2014 have been made in the form of restricted units and performance units (i.e., phantom units subject to performance conditions). 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. With respect to the performance units (as described below), distributions declared and paid will be grossed-up by an additional number of performance units as determined in the performance unit agreement. No options have been issued to date.

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Restricted Units

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 grants of restricted units eligible to receive distributions are distributed to the awardees.

A summary of the changes in outstanding restricted common units for the nine months ended September 30, 2014 is provided below:



	Number of Restricted Units		Weighted Average Fair Value
Outstanding at December 31, 2013	2,743,807		$	9.37
Granted	1,858,333		$	4.47
Vested	(1,035,691	)	$	9.56
Forfeited	(803,366	)	$	8.42
Outstanding at September 30, 2014	2,763,083		$	6.28

Performance Units

On August 19, 2014, the Board of Directors of Eagle Rock Energy G&P, LLC, upon the recommendation of its compensation committee, approved a grant of 715,263 target performance unit awards to the Partnership's executive officers subject to performance and service-based vesting conditions pursuant to the LTIP. Performance units are described in the LTIP as phantom units subject to restrictions that lapse based on the performance of the Partnership, as measured by total unitholder return in comparison to a peer group of upstream master limited partnerships and a continued service requirement that spans a three-year period.

The performance units represent hypothetical common units of the Partnership and therefore do not carry any of the rights and privileges (including voting privileges) associated with actual common units. Performance units settle in common units rather than cash. The fair value of the performance units is estimated using a Monte Carlo simulation at the grant date. The Partnership recognizes compensation expense for the performance unit grants over the three-year vesting period.

The amount to vest each year for the three-year vesting period will be determined on each vesting date based on a two-step approach. The right to receive units with respect to the performance units depends first on the level of total unitholder return attained by the Partnership over the applicable performance period (generally July 1, 2014 through June 30, 2016), as measured against the Partnership's peer group. The number of units that may be earned will either by 0% for performance at anything less than the 50th percentile of the peer group, or in the range of 70% to 200% for performance from the 50th percentile to the 100th percentile of the peer group over the performance period. Second, the right to receive actual common units with respect to the earned performance units depends on the satisfaction of a continued service requirement, which is generally continued service through June 30, 2016 for two-thirds of the performance units and through June 30, 2017 for the remaining one-third of the performance units.

In the event the Partnership pays any distributions in respect of its outstanding units, the target performance units and any earned performance units will be grossed-up to reflect such distribution by an additional number of target performance units or earned performance units, as applicable. Any target performance units that do not become earned performance units shall terminate, expire and otherwise be forfeited by the named executive officer on the last day of the performance periods. Any earned performance units that vest (based on fulfillment of the continued service requirement) shall be converted into actual common units. Any earned performance units that do not vest (based on fulfillment of the continued service requirement) shall terminate, expire and otherwise be forfeited by the named executive officer.

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A summary of the changes in outstanding performance units for the nine months ended September 30, 2014 is provided below:



	Number of Performance Units		Weighted Average Fair Value
Outstanding at December 31, 2013	—		$	—
Granted	715,263		$	3.63
Forfeited	(67,475	)	$	3.59
Outstanding at September 30, 2014	647,788		$	3.63

Equity Based Compensation

For the three and nine months ended September 30, 2014, non-cash compensation expense of approximately $2.9 million and $7.0 million, respectively, and for the three and nine months ended September 30, 2013, $3.0 million and $7.7 million , respectively, was recorded related to the granted restricted units and performance units as general and administrative expense on the unaudited condensed consolidated statements of operations.

As of September 30, 2014, unrecognized compensation costs related to the outstanding restricted units and performance units under the LTIP totaled approximately $14.6 million. The remaining expense is to be recognized over a weighted average of 2.09 years.

In connection with the vesting of certain restricted units during the three months ended September 30, 2014, the Partnership cancelled 0.3 million of the newly-vested common units in satisfaction of $1.2 million of employee tax liability paid by the Partnership. Pursuant to the terms of the LTIP, these cancelled units are available for future grants under the LTIP.

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NOTE 15. 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 September 30, 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 14, 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 September 30,		Nine Months Ended September 30,
	2014	2013	2014	2013
	(in thousands)
Weighted average units outstanding during period:
Common units - Basic and diluted	157,375	156,079	156,995	152,618
Effect of Dilutive Securities:
Restricted Units (non-participating securities)	63	—	35	—
Restricted Units (participating securities)	962	—	594	—
Common units - Diluted	158,400	156,079	157,624	152,618

For the three and nine months ended September 30, 2014 and the three months ended September 30, 2013, the Partnership determined that it is more dilutive to apply the two-class method versus the treasury stock method in calculating dilutive earnings per unit. Thus, the unvested restricted common units are included in the computation of the diluted weighted average common units outstanding calculation, but the denominator in the computation of diluted earnings per unit only includes the basic weighted average common units and restricted units (non-participating securities) outstanding.

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The following table presents the Partnership's basic and diluted income per unit for the three months ended September 30, 2014:



	Total		Common Units		Restricted Common Units*
	($ in thousands, except for per unit amounts)
Income from continuing operations	$	17,231
Distributions	11,183		$	11,018	$	165
Assumed income from continuing operations after distribution to be allocated	6,048		5,967		81
Assumed allocation of income from continuing operations	17,231		16,985		246
Discontinued operations	249,057		245,701		3,356
Assumed net income to be allocated	$	266,288	$	262,686	$	3,602

Basic income from continuing operations per unit			$	0.11
Basic discontinued operations per unit			$	1.56
Basic and diluted income per unit			$	1.67

Diluted income from continuing operations per unit			$	0.11
Diluted discontinued operations per unit			$	1.56
Diluted income per unit			$	1.67

_____________________________


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

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The following table presents the Partnership's basic and diluted income per unit for the three months ended September 30, 2013:



	Total			Common Units			Restricted Common Units
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(70,342	)
Distributions	23,832			$	23,412		$	420
Assumed loss from continuing operations after distribution to be allocated	(94,174		)	(94,174		)	—
Assumed allocation of loss from continuing operations	(70,342		)	(70,762		)	420
Discontinued operations	(21,223		)	(21,223		)	—
Assumed net loss to be allocated	$	(91,565	)	$	(91,985	)	$	420

Basic loss from continuing operations per unit				$	(0.45	)
Basic discontinued operations per unit				$	(0.14	)
Basic and diluted loss per unit				$	(0.59	)

Diluted loss from continuing operations per unit				$	(0.45	)
Diluted discontinued operations per unit				$	(0.14	)
Diluted loss per unit				$	(0.59	)

The following table presents the Partnership's basic and diluted income per unit for the nine months ended September 30, 2014:

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	Total			Common Units			Restricted Common Units*
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(8,124	)
Distributions	11,183			$	11,018		$	165
Assumed loss from continuing operations after distribution to be allocated	(19,307		)	(19,307		)	—
Assumed allocation of loss from continuing operations	(8,124		)	(8,289		)	165
Discontinued operations, net of tax	212,808			210,199			2,609
Assumed net loss to be allocated	$	204,684		$	201,910		$	2,774

Basic loss from continuing operations per unit				$	(0.05	)
Basic discontinued operations per unit				$	1.34
Basic and diluted loss per unit				$	1.29

Diluted loss from continuing operations per unit				$	(0.05	)
Diluted discontinued operations per unit				$	1.34
Diluted loss per unit				$	1.29

_____________________________


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

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The following table presents the Partnership's basic and diluted income per unit for the nine months ended September 30, 2013:



	Total			Common Units			Restricted Common Units
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(70,135	)
Distributions	93,492			$	91,855		$	1,637
Assumed loss from continuing operations after distribution to be allocated	(163,627		)	(163,627		)	—
Assumed allocation of loss from continuing operations	(70,135		)	(71,772		)	1,637
Discontinued operations, net of tax	(38,912		)	(38,912		)	—
Assumed net loss to be allocated	$	(109,047	)	$	(110,684	)	$	1,637

Basic income from continuing operations per unit				$	(0.47	)
Basic discontinued operations per unit				$	(0.26	)
Basic and diluted loss per unit				$	(0.73	)

Diluted income from continuing operations per unit				$	(0.47	)
Diluted discontinued operations per unit				$	(0.26	)
Diluted income per unit				$	(0.73	)

NOTE 16. DIVESTITURE RELATED ACTIVITIES

As discussed in Note 1, the Partnership completed the contribution of its Midstream Business to Regency and met the criteria to retrospectively adjust the prior periods to reflect the Midstream Business' assets and liabilities as held for sale and met the criteria for classifying the operations of the Midstream Business for the three and nine months ended September 30, 2014 and 2013 as discontinued.

The following is the reconciliation of the major classes of assets and liabilities classified as held for sale.



	September 30, 2014		December 31, 2013
Assets held for sale
Accounts Receivable	$	—	$	128,713
Property, plant and equipment	—		1,004,317
Intangible assets	—		102,352
Other current assets	—		5,663
Other long-term assets	—		18,337
Total assets held for sale	$	—	$	1,259,382

Liabilities held for sale
Long-term debt	$	—	$	494,582
Accounts payable and accrued liabilities	—		119,966
Other current liabilities	—		9,471
Other long-term liabilities	—		13,719
Total liabilities held for sale	$	—	$	637,738

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following is the reconciliation of the major classes of line items classified as discontinued operations.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Class of statement of operations line item of discontinued operations:
Revenue	$	4,493		$	258,748		$	552,574		$	729,498
Cost of natural gas, natural gas liquids, condensate and helium	2,846			213,509			447,519			579,257
Operations, maintenance and taxes other than income	27			26,396			50,154			75,385
General and administrative	4,055			7,022			18,044			18,614
Depreciation, amortization and impairment	—			20,170			41,936			58,208
Interest expense	—			(12,828		)	(27,350		)	(36,957		)
Other income (expense)	—			76			(68		)	216
Operating income (loss) from discontinued operations before taxes	(2,435		)	(21,101		)	(32,497		)	(38,707		)
Gain or loss on sale of assets	249,856			—			243,637			—
Income tax expense (benefit)	(1,636		)	122			(1,668		)	205
Discontinued operations	$	249,057		$	(21,223	)	$	212,808		$	(38,912	)

Allocation of interest expense

Per accounting guidance provided by the FASB related to discontinued operations, interest on debt that is to be assumed by the buyer and interest on debt that is required to be repaid as a result of a disposal transaction should be allocated to discontinued operations. Per the Partnership's Credit Agreement, as a result of the contribution of the Midstream Business, the Partnership is required to pay down outstanding debt to the amount of the upstream portion of the borrowing base. Thus, interest expense in the table above includes the interest expense related to the portion of the Partnership's unsecured Senior Notes exchanged for Regency unsecured senior notes on July 1, 2014 (see Note 1) and interest related to the difference between the total amount outstanding under the Credit Agreement and the upstream portion of the borrowing base.

Restructuring activities

In connection with the contribution of the Midstream Business to Regency, the Partnership accrued one-time employee termination benefits and lease payments of the partial abandonment of an operating lease of $4.0 million and $0.6 million during the nine months ended September 30, 2014. The accruals are recorded as part of accrued liabilities within the unaudited condensed consolidated balance sheet, while the expenses are recorded as part of discontinued operations within the unaudited condensed consolidated statement of operations. The following table summarizes activity related to liabilities associated with the Partnership's restructuring activities during the nine months ended September 30, 2014.



	Employee Related Costs			Facility and Other Costs			Total

Balance at December 31, 2013	$	—		$	—		$	—
Additions	3,975			563			4,538
Payments and other adjustments	(2,564		)	(36		)	(2,600		)
Balance at September 30, 2014	$	1,411		$	527		$	1,938

In addition, in connection with the contribution of the Midstream Business, the Partnership incurred expenses of $1.6 million during the three months ended September 30, 2014 to write-off certain software licenses used by the Midstream Business that were not acquired by Regency.

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NOTE 17. SUBSIDIARY GUARANTORS

The Partnership has issued registered debt securities guaranteed by its subsidiaries. As of September 30, 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 the Partnership's 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 the Partnership;


•	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 the Partnership designates 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 the Securities and Exchange Commission (the "SEC") Regulation S-X, the Partnership has prepared Unaudited Condensed Consolidating Financial Statements as supplemental information. The following unaudited condensed consolidating balance sheets at September 30, 2014 and December 31, 2013, and unaudited condensed consolidating statements of operations for the three and nine months ended September 30, 2014 and 2013, and unaudited condensed consolidating statements of cash flows for the nine months ended September 30, 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. Pursuant to the Midstream Business Contribution, all of the subsidiaries of the Partnership's Midstream Business were contributed to Regency on July 1, 2014 and released from their guarantees under the indenture and Credit Agreement. In addition, as discussed in Note 7, the indenture governing the registered debt securities was amended to remove substantially all of the restrictive covenants and certain events of default

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Balance Sheet

September 30, 2014



	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments		Consolidating Entries			Total
	($ in thousands)
ASSETS:
Accounts receivable – related parties	$	835,076		$	—	$	—		$	—	$	(835,076	)	$	—
Other current assets	278,418			1		41,011			—		—			319,430
Total property, plant and equipment, net	1,473			—		850,654			—		—			852,127
Investment in subsidiaries	(35,441		)	—		—			—		35,441			—
Total other long-term assets	6,860			—		5,345			—		—			12,205
Total assets	$	1,086,386		$	1	$	897,010		$	—	$	(799,635	)	$	1,183,762
LIABILITIES AND EQUITY:
Accounts payable – related parties	$	—		$	—	$	835,076		$	—	$	(835,076	)	$	—
Other current liabilities	45,024			—		14,888			—		—			59,912
Other long-term liabilities	(822		)	—		82,488			—		—			81,666
Long-term debt	276,425			—		—			—		—			276,425
Equity	765,759			1		(35,442		)	—		35,441			765,759
Total liabilities and equity	$	1,086,386		$	1	$	897,010		$	—	$	(799,635	)	$	1,183,762

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	)	$	—
Assets held for sale	7,333		—		1,252,049		—		—			1,259,382
Other current assets	6,927		1		22,080		—		—			29,008
Total property, plant and equipment, net	2,318		—		822,133		—		—			824,451
Investment in subsidiaries	1,133,217		—		—		908		(1,134,125		)	—
Total other long-term assets	11,441		—		3,268		—		—			14,709
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	)	$	—
Liabilities held for sale	500,110		—		137,628		—		—			637,738
Other current liabilities	15,688		—		66,141		—		—			81,829
Other long-term liabilities	5,667		—		70,957		—		—			76,624
Long-term debt	757,480		—		—		—		—			757,480
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

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

For the Three Months Ended September 30, 2014




	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments		Consolidating Entries			Total
	($ in thousands)
Total revenues	$	27,951		$	—	$	53,273		$	—	$	—		$	81,224
Operations and maintenance	—			—		10,707			—		—			10,707
Taxes other than income	—			—		3,184			—		—			3,184
General and administrative	2,956			—		9,279			—		—			12,235
Depreciation, depletion and amortization	149			—		22,110			—		—			22,259
Impairment	—			—		17,305			—		—			17,305
Income (loss) from operations	24,846			—		(9,312		)	—		—			15,534
Interest expense, net	(3,188		)	—		—			—		—			(3,188		)
Other non-operating income	2,177			—		2,292			—		(4,469		)	—
Other non-operating expense	2,542			—		(3,012		)	—		4,469			3,999
Income (loss) before income taxes	26,377			—		(10,032		)	—		—			16,345
Income tax benefit	(1,962		)	—		1,076			—		—			(886		)
Equity in earnings of subsidiaries	(333,798		)	—		—			—		333,798			—
Income (loss) from continuing operations	(305,459		)	—		(11,108		)	—		333,798			17,231
Discontinued operations, net of tax	571,747			—		(322,690		)	—		—			249,057
Net income (loss)	$	266,288		$	—	$	(333,798	)	$	—	$	333,798		$	266,288

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

For the Three Months Ended September 30, 2013




	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	(10,878	)	$	—	$	53,363		$	—		$	—		$	42,485
Operations and maintenance	—			—		8,773			—			—			8,773
Taxes other than income	—			—		3,731			—			—			3,731
General and administrative	3,199			—		10,316			—			—			13,515
Depreciation, depletion and amortization	52			—		22,419			—			—			22,471
Impairment	—			—		61,389			—			—			61,389
Income from operations	(14,129		)	—		(53,265		)	—			—			(67,394		)
Interest expense, net	(4,647		)	—		—			—			—			(4,647		)
Other non-operating income	2,268			—		2,325			—			(4,593		)	—
Other non-operating expense	(1,909		)	—		(3,140		)	—			4,593			(456		)
Loss before income taxes	(18,417		)	—		(54,080		)	—			—			(72,497		)
Income tax provision (benefit)	33			—		(2,188		)	—			—			(2,155		)
Equity in earnings of subsidiaries	(49,424		)	—		—			—			49,424			—
Loss from continuing operations	(67,874		)	—		(51,892		)	—			49,424			(70,342		)
Discontinued operations, net of tax	(23,691		)	—		2,469			(1		)	—			(21,223		)
Net loss	$	(91,565	)	$	—	$	(49,423	)	$	(1	)	$	49,424		$	(91,565	)

Unaudited Condensed Consolidating Statement of Operations

For the Nine Months Ended September 30, 2014



	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	(163	)	$	—	$	160,634		$	—		$	—		$	160,471
Operations and maintenance	3			—		33,109			—			—			33,112
Taxes other than income	—			—		10,571			—			—			10,571
General and administrative	7,917			—		29,613			—			—			37,530
Depreciation, depletion and amortization	497			—		62,467			—			—			62,964
Impairment	—			—		17,305			—			—			17,305
(Loss) income from operations	(8,580		)	—		7,569			—			—			(1,011		)
Interest expense, net	(12,888		)	—		(2		)	—			—			(12,890		)
Other non-operating income	6,561			—		6,884			—			(13,445		)	—
Other non-operating expense	(1,161		)	—		(9,143		)	—			13,445			3,141
(Loss) income before income taxes	(16,068		)	—		5,308			—			—			(10,760		)
Income tax benefit	(2,147		)	—		(489		)	—			—			(2,636		)
Equity in earnings of subsidiaries	(305,787		)	—		—			—			305,787			—
Income (loss) from continuing operations	(319,708		)	—		5,797			—			305,787			(8,124		)
Discontinued operations, net of tax	524,392			—		(311,575		)	(9		)	—			212,808
Net income (loss)	$	204,684		$	—	$	(305,778	)	$	(9	)	$	305,787		$	204,684

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

For the Nine Months Ended September 30, 2013



	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	(376	)	$	—	$	149,993		$	—		$	—		$	149,617
Operations and maintenance	—			—		30,052			—			—			30,052
Taxes other than income	—			—		9,730			—			—			9,730
General and administrative	9,878			—		30,288			—			—			40,166
Depreciation, depletion and amortization	398			—		65,429			—			—			65,827
Impairment	—			—		63,228			—			—			63,228
Loss from operations	(10,652		)	—		(48,734		)	—			—			(59,386		)
Interest expense, net	(13,378		)	—		(833		)	—			—			(14,211		)
Other non-operating income	6,787			—		6,984			—			(13,771		)	—
Other non-operating expense	(5,127		)	—		(9,442		)	—			13,771			(798		)
Loss before income taxes	(22,370		)	—		(52,025		)	—			—			(74,395		)
Income tax benefit	(640		)	—		(3,620		)	—			—			(4,260		)
Equity in earnings of subsidiaries	(50,331		)	—		—			—			50,331			—
Loss from continuing operations	(72,061		)	—		(48,405		)	—			50,331			(70,135		)
Discontinued operations, net of tax	(36,986		)	—		(1,919		)	(7		)	—			(38,912		)
Net loss	$	(109,047	)	$	—	$	(50,324	)	$	(7	)	$	50,331		$	(109,047	)

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Cash Flows

For the Nine Months Ended September 30, 2014



	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments		Consolidating Entries		Total
	($ in thousands)
Net cash flows (used in) provided by operating activities	$	(23,181	)	$	—	$	70,678		$	—	$	—	$	47,497
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	348			—		(107,012		)	—		—		(106,664		)
Net cash flows used in investing activities	348			—		(107,012		)	—		—		(106,664		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	416,700			—		—			—		—		416,700
Repayment of long-term debt	(897,800		)	—		—			—		—		(897,800		)
Payment of debt issuance cost	(410		)	—		—			—		—		(410		)
Proceeds from derivative contracts	(5,163		)	—		—			—		—		(5,163		)
Repurchase of common units	(1,171		)	—		—			—		—		(1,171		)
Distributions to members and affiliates	(23,801		)	—		—			—		—		(23,801		)
Net cash flows used in financing activities	(511,645		)	—		—			—		—		(511,645		)
Net cash flows used in discontinued operations	536,883			—		34,424			22		—		571,329
Net increase (decrease) in cash and cash equivalents	2,405			—		(1,910		)	22		—		517
Cash and cash equivalents at beginning of period	1,237			1		(1,389		)	227		—		76
Cash and cash equivalents at end of period	$	3,642		$	1	$	(3,299	)	$	249	$	—	$	593

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Cash Flows

For the Nine Months Ended September 30, 2013



	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments		Consolidating Entries		Total
	($ in thousands)
Net cash flows (used in) provided by operating activities	$	(18,936	)	$	—	$	117,555		$	—	$	—	$	98,619
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(987		)	—		(116,296		)	—		—		(117,283		)
Net cash flows used in investing activities	(987		)	—		(116,296		)	—		—		(117,283		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	463,700			—		—			—		—		463,700
Repayment of long-term debt	(418,200		)	—		—			—		—		(418,200		)
Proceeds from derivative contracts	1,052			—		—			—		—		1,052
Common unit issued in equity offerings	102,388			—		—			—		—		102,388
Issuance costs for equity offerings	(4,490		)	—		—			—		—		(4,490		)
Repurchase of common units	(1,000		)	—		—			—		—		(1,000		)
Distributions to members and affiliates	(102,079		)	—		—			—		—		(102,079		)
Net cash flows provided by financing activities	41,371			—		—			—		—		41,371
Net cash flows used in discontinued operations	(18,744		)	—		(3,944		)	32		—		(22,656		)
Net (decrease) increase in cash and cash equivalents	2,704			—		(2,685		)	32		—		51
Cash and cash equivalents at beginning of period	1,670			1		(1,832		)	186		—		25
Cash and cash equivalents at end of period	$	4,374		$	1	$	(4,517	)	$	218	$	—	$	76

NOTE 18. SUBSEQUENT EVENTS

Amendment to Credit Facility

On October 10, 2014, the Partnership entered into the Fifth Amendment to its Amended and Restated Credit Agreement as further described in Note 7.

Common Unit Repurchase Program

On October 27, 2014, the Partnership announced that the Board of Directors authorized a common unit repurchase program of up to $100 million. The program is authorized to commence following the filing of this Quarterly Report on Form 10-Q for the period ending September 30, 2014 and will conclude by March 31, 2016. The repurchase program does not obligate the Partnership to acquire any, or any specific number of, units and may be discontinued at any time. The Partnership intends to cancel any units it repurchases under the repurchase program.

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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 (the "2013 10-K") and in "Part II. Item 1A. Risk Factors." These factors include but are not limited to:


•	Drilling and geological / exploration risks;


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


•	Volatility or declines (including sustained declines) in commodity prices;


•	Ability to make favorable acquisitions and integrate operations from such acquisitions;


•	Our existing indebtedness;


•	Hedging activities;


•	Ability to obtain credit and access capital markets;


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


•	Conditions in the securities and/or capital markets;


•	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;


•	Shortages of personnel and equipment;


•	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.

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OVERVIEW

The following discussion and analysis of financial condition and results of operations should be read in conjunction with our unaudited condensed consolidated financial statements, and the notes thereto, appearing elsewhere in this report, as well as the 2013 10-K filed with the SEC and our Form 8-K filed on September 17, 2014, which retrospectively adjusted Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations included in the 2013 10-K for the discontinued operations of the Partnership's Midstream Business. For a description of oil and natural gas terms, see the 2013 10-K.

Recent Developments

On July 1, 2014, we completed the contribution of our Midstream Business to Regency Energy Partners LP ("Regency"). The consideration received by us for the contribution of our Midstream Business included: (i) $576.2 million of cash; (ii) 8,245,859 Regency common units (valued at approximately $265.6 million based on the closing price of Regency common units on June 30, 2014) (the "Regency Common Units") and (iii) the exchange of $498.9 million face amount of newly-issued Regency 8.375% Senior Notes due 2019 for $498.9 million face amount of our Senior Notes. Accordingly, prior periods have been retrospectively adjusted to reflect the Midstream Business's assets and liabilities as held for sale and operations as discontinued (see Note 16) in the financial statements included in this report.

We used the cash received from Regency for the Midstream Business Contribution to paydown $570.4 million outstanding under the Credit Agreement. In addition, $51.1 million of our Senior Notes did not exchange in connection with the Midstream Business Contribution and remained outstanding following the contribution. However, having secured a sufficient number of consents as part of the exchange offer, we amended the indenture governing our Senior Notes to eliminate substantially all of the restrictive covenants and certain events of default pertaining to our Senior Notes. As further described below in "—Subsequent Events", in October 2014 we amended the Credit Agreement to more of a traditional reserve-based facility with revised covenants and improved fee pricing.

Results Overview

As a result of the contribution of our Midstream Business to Regency, we are now a domestically-focused, growth-oriented, publicly-traded Delaware limited partnership engaged in developing and producing oil and natural gas property interests. Our interests include 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).

Results for the three and nine months ended September 30, 2014, included the following:


•	revenues, excluding the impact of commodity risk management gains (losses) were $53.6 million and $160.7 million, respectively, for the three and nine months ended September 30, 2014, compared to $53.3 million and $149.4 million for the three and nine months ended September 30, 2013;


•	commodity risk management gains were $28.0 million for the three months ended September 30, 2014 and commodity risk management losses were $0.1 million for the nine months ended September 30, 2014, compared to commodity risk management losses of $10.9 million and $0.4 million, respectively, for the three and nine months ended September 30, 2013;


•	operating income was $15.5 million and $1.0 million, respectively, for the three and nine months ended September 30, 2014, compared to operating losses of $67.4 million and $59.4 million, respectively, for the three and nine months ended September 30, 2013;


•	average daily production was 73 MMcfe/d for the nine months ended September 30, 2014, compared to 74 MMcfe/d for the nine months ended September 30, 2013; and


•	capital expenditures were $32.4 million and $109.4 million, respectively, for the three and nine months ended September 30, 2014, compared to $34.2 million and $106.7 million, respectively, for the three and nine months ended September 30, 2013.

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Impairment

We recorded an impairment charge of $17.3 million during the three and nine months ended September 30, 2014 related to certain proved properties in our East Texas and Permian regions due to lower commodity prices, higher operating costs and lower well performance. During the three and nine months ended September 30, 2013, we recorded an impairment charge of $61.4 million and $63.2 million, respectfully, in our Upstream Business related to certain proved properties in our Permian region due to lower commodity prices and continued higher operating costs. During the nine months ended September 30, 2014, we recorded an impairment charge of $2.1 million in our Midstream Business due to the loss of two customers on our North System. This charge is included within discontinued operations. We did not record any impairment charges in Midstream Business during the three and nine months ended September 30, 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.

Subsequent Events

On October 10, 2014, we entered into the Fifth Amendment (the "Fifth Amendment" to our Amended and Restated Credit Agreement (as amended, the "Credit Agreement"). The Fifth Amendment, among other items, provided for current commitments totaling $320 million, with the ability to increase commitments up to a total aggregate amount of $1.2 billion. The Fifth Amendment coincided with the semi-annual borrowing base redetermination by our commercial lenders, and the next redetermination will be in April 2015. The amendment extended the maturity to October 2019. In addition, as a result of the completion of the Midstream Business contribution, our borrowing base under the Credit Agreement is now strictly based on the value of our oil and natural gas properties and our commodity derivative contracts, which was formerly referred to as the upstream component of the borrowing base.

On October 27, 2014, we announced that our Board of Directors authorized a common unit repurchase program of up to $100 million. The program is authorized to commence following the filing of this Quarterly Report on Form 10-Q for the period ending September 30, 2014 and will conclude by March 31, 2016. The repurchase program does not obligate us to acquire any, or any specific number of, units and may be discontinued at any time. We intend to cancel any units we repurchase under the repurchase program.

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RESULTS OF OPERATIONS

Summary of Consolidated Operating Results

Below is a table of a summary of our consolidated operating results for the three and nine months ended September 30, 2014 and 2013.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	($ in thousands)
Revenues:
Oil and condensate	$	28,993		$	30,105		$	82,620		$	78,680
Natural gas	12,139			11,062			39,637			33,786
NGLs	10,296			10,786			32,009			29,658
Sulfur	2,198			1,365			6,411			7,251
Commodity risk management gains (losses), net	27,967			(10,878		)	(147		)	(376		)
Other revenue	(369		)	45			(59		)	618
Total revenue	81,224			42,485			160,471			149,617
Costs and expenses:
Operations and maintenance	10,707			8,773			33,112			30,052
Taxes other than income	3,184			3,731			10,571			9,730
General and administrative	12,235			13,515			37,530			40,166
Impairment	17,305			61,389			17,305			63,228
Depreciation, depletion and amortization	22,259			22,471			62,964			65,827
Total costs and expenses	65,690			109,879			161,482			209,003
Operating income (loss)	15,534			(67,394		)	(1,011		)	(59,386		)
Other income (expense):
Interest expense, net	(3,188		)	(4,647		)	(12,890		)	(14,211		)
Interest rate risk management losses, net	(81		)	(459		)	(942		)	(766		)
Other income (expense), net	4,080			3			4,083			(32		)
Total other income (expense)	811			(5,103		)	(9,749		)	(15,009		)
Income (loss) before income taxes	16,345			(72,497		)	(10,760		)	(74,395		)
Income tax expense (benefit)	(886		)	(2,155		)	(2,636		)	(4,260		)
Income (loss) from continuing operations	17,231			(70,342		)	(8,124		)	(70,135		)
Discontinued operations, net of tax	249,057			(21,223		)	212,808			(38,912		)
Net (loss) income	$	266,288		$	(91,565	)	$	204,684		$	(109,047	)
Adjusted EBITDA(a)	$	35,389		$	33,215		$	86,384		$	89,852

________________________


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

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013

Realized average prices:
Oil and condensate (per Bbl)	$	85.66	$	93.74	$	86.43	$	87.95
Natural gas (per Mcf)	$	3.92	$	3.40	$	4.41	$	3.53
NGLs (per Bbl)	$	34.70	$	36.19	$	37.22	$	34.24
Sulfur (per Long ton)	$	97.55	$	50.95	$	88.36	$	90.60
Production volumes:
Oil and condensate (Bbl)	338,462		321,170		955,918		894,591
Natural gas (Mcf)	3,094,006		3,254,722		8,989,872		9,565,038
NGLs (Bbl)	296,686		298,031		859,999		866,055
Total (Mcfe)	6,904,894		6,969,928		19,885,374		20,128,914
Sulfur (Long ton)	22,534		26,788		72,549		80,028

Capital expenditures	$	32,425	$	34,205	$	109,366	$	106,663

Commodity Revenues. For the three and nine months ended September 30, 2014, commodity revenues, which excludes commodity risk management gains (losses), decreased by $0.1 million and increased by $10.6 million, respectively, as compared to the three and nine months ended September 30, 2013. The decrease in revenues for the three months ended September 30, 2014 compared to the three months ended September 30, 2013 was due to lower realized oil and NGL prices and higher oil volumes, partially offset by lower natural gas and sulfur volumes and higher natural gas and sulfur prices. The increase in revenues for the nine months ended September 30, 2014, as compared to the nine months ended September 30, 2013, was due to higher NGL and natural gas prices and higher oil volumes, offset by decreases in oil and sulfur prices and lower natural gas, NGL and sulfur volumes.

Production volumes during the three and nine months ended September 30, 2014 were negatively impacted by performance on our Alabama wells due to increases in completion times as well as declines in production on our Mid-Continent wells due to offsetting fracing on other wells and delays in completions for both operated and non-operated wells.

Commodity Risk Management Gains (Losses), net. During the three and nine months ended September 30, 2014, losses in our commodity derivative portfolio decreased by $38.8 million and $0.2 million, respectively, as compared to the three and nine months ended September 30, 2013. During the three and nine months ended September 30, 2014, losses in our mark-to-market commodity derivative portfolio decreased by $40.4 million and $16.3 million as compared to the three and nine months ended September 30, 2013, respectively, primarily due to increases in the natural gas, NGL and crude oil forward curves. Our gains from derivative contracts that settled during the three and nine months ended September 30, 2014 decreased by $1.6 million and $16.1 million, respectively, compared to the three and nine months ended September 30, 2013. This 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.

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.

Operating Expenses (Including Taxes Other Than Income). Operating expenses, including taxes other than income, increased $1.4 million and $3.9 million for the three and nine months ended September 30, 2014, respectively, as compared to the three and nine months ended September 30, 2013. The increase was primarily due to increased post-production costs, higher severance tax due to higher sales volume, increased plant operating expense, and higher lease operating costs due to additional wells drilled. In addition, we received a tax refund from the State of Oklahoma in 2013 for amounts paid in prior years.

General and Administrative Expenses. General and administrative expenses decreased by $1.3 million and $2.6 million for the three and nine months ended September 30, 2014, respectively, as compared to the same period in 2013. This decrease was primarily due to lower compensation and benefit expenses due to the reduction in headcount as a result of the Midstream Business Contribution and lower equity based compensation expense due to an increase made to the estimated

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forfeiture rate during the nine months ended September 30, 2014. The forfeiture rate is used to calculate the amount of equity based compensation expense.

Depletion, Depreciation and Amortization. Depletion, depreciation and amortization expense decreased by $0.2 million and $2.9 million for the three and nine months ended September 30, 2014, respectively, as compared to the same period in the prior year. The decrease for the three and nine months ended September 30, 2014 was primarily a result of the impairment charges recorded during 2013 and overall decrease in production for the three and nine months ended September 30, 2014 compared to the same periods in 2013.

Impairment. During the three and nine months ended September 30, 2014, we incurred an impairment charge of $17.3 million related to certain proved properties in our East Texas and Permian regions due to lower commodity prices, higher operating costs and lower well performance. During the three and nine months ended September 30, 2013, we recorded an impairment charge of $61.4 million and $63.2 million, respectively, related to certain proved properties in our Permian region due to lower commodity prices and continued higher operating costs.

Total Other Expense. Total other expense primarily consists of gains and losses from our interest rate swaps and interest expense related to our Credit Agreement and our Senior Notes. During the three months ended September 30, 2014, our interest rate risk management losses decreased by $0.4 million as compared to the three months ended September 30, 2013 and increased by $0.2 million during the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013. These changes are due to increases and decreases in the forward interest rate curve. 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 decreased by $1.5 million and $1.3 million during the three and nine months ended September 30, 2014, respectively, as compared to the three and nine months ended September 30, 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 decrease in interest expense is primarily due to the repayment of borrowings outstanding under the Credit Agreement.

In addition, other income for the three and nine months ended September 30, 2014 includes a $4.0 million distribution from Regency in respect of their common units that we hold.

Income Tax Expense (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.

Discontinued Operations. On July 1, 2014, we completed our Midstream Business Contribution to Regency. We have classified the assets and liabilities of our Midstream Business as held for sale and the operations as discontinued. Discontinued operations increased by $270.3 million and $251.7 million, respectively, for the three and nine months ended September 30, 2014, as compared to the three and nine months ended September 30, 2013. The increase in discontinued operations for the three and nine months ended September 30, 2014 is primarily due to the gain on sale of the Midstream Business of $249.9 million and $243.6 million, respectively. In addition, included within discontinued operations for the three and nine months ended September 30, 2014 are professional fees of $4.4 million and $10.6 million, respectively, and one-time termination benefits of $0.8 million and $4.0 million, respectively. See Note 16 to the unaudited condensed consolidated financial statements for the major line items that comprise discontinued operations.

Capital Expenditures. Capital expenditures decreased by $1.8 million for the three months ended September 30, 2014 as compared to the three months ended September 30, 2013 and increased by $2.7 million for the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013. Changes in capital expenditures are primarily due to our drilling program.

During the three months ended September 30, 2014, we drilled and completed three gross (2.14 net) operated wells and participated in four gross (1.44 net) non-operated wells in the Mid-Continent region. Additionally, during the three months ended September 30, 2014, we conducted six gross (3.21 net) workovers and one gross (1.00 net) recompletion across our operations.

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Adjusted EBITDA

Adjusted EBITDA, as defined under "—Liquidity and Capital Resources — Non-GAAP Financial Measures," from continuing operations increased by $2.2 million from $33.2 million for the three months ended September 30, 2013 to $35.4 million for the three months ended September 30, 2014. Adjusted EBITDA from continuing operations decreased by $3.5 million for the nine months ended September 30, 2014 as compared to the same period in 2013. The following table presents the changes in operations impacting Adjusted EBITDA:



	Three Months Ended September 30,							Nine Months Ended September 30,
	2014		2013		Change			2014			2013		Change

Revenues (a)	$	53,260	$	53,366	$	(106	)	$	160,614		$	149,991	$	10,623
Commodity derivative settlements	1,267		2,824		(1,557		)	(4,047		)	12,060		(16,107		)
Operating expenses	13,891		12,504		1,387			43,683			39,782		3,901
General and administrative expenses (b)	9,287		10,471		(1,184		)	30,540			32,417		(1,877		)
Distributions received from Regency	4,040		—		4,040			4,040			—		4,040
Adjusted EBITDA (c)	$	35,389	$	33,215	$	2,174		$	86,384		$	89,852	$	(3,468	)

_________________________


(a)	Excludes the impact of imbalances.


(b)	Excludes non-cash compensation charges related to our long-term incentive program.


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

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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 Credit Agreement. Our primary cash requirements have included general and administrative expenses, operating expenses, maintenance and growth capital expenditures, short-term working capital needs, interest payments on our outstanding debt, distributions to our unitholders and acquisitions of new assets or businesses.

In connection with the consummation of the Midstream Business Contribution, we were able to improve our liquidity position by paying down our borrowings under our Credit Agreement, resulting in increased borrowing availability, and exchanging $498.9 million of our Senior Notes, resulting in significantly decreased debt levels. In addition, we received 8,245,859 Regency common units (valued at approximately $269.0 million based on the closing price of Regency common units on September 30, 2014), which could be a potential source of future liquidity.

We believe that our improved liquidity position as a result of the Midstream Business Contribution and our historical sources of liquidity will be sufficient to satisfy our short-term liquidity needs and to fund our committed capital expenditures for at least the next twelve months. Our growth strategy entails pursuing attractive upstream acquisitions and organic drilling opportunities. We may utilize any of various available financing sources, including liquidity from the consummation of the Midstream Business Contribution, proceeds from the issuance of equity or debt securities, sales of Regency common units or borrowings from our Credit Agreement 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, sales of Regency common units and the timing of these offerings and sales will depend upon various factors including prevailing market conditions and our financial condition.

Equity Offerings

On May 31, 2012, we announced a program through which we may issue common units, from time to time, with an aggregate market value of up to $100 million. We are under no obligation to issue equity under the program. We intend to use the net proceeds from any sales under the program for general partnership purposes, which may include, among other things, repayment of indebtedness, acquisitions, capital expenditures and additions to working capital. As of September 30, 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 and nine months ended September 30, 2014. The last time units were issues under this program was during the three month period ended June 30, 2013.

Common Unit Repurchase Program

On October 27, 2014, we announced a common unit repurchase program of up to $100 million through which repurchases may be made from time to time at prevailing prices on the open market or in privately negotiated transactions. The program is authorized to commence following the filing of this Quarterly Report on Form 10-Q for the period ending September 30, 2014 and will conclude by March 31, 2016. The repurchase program does not obligate us to acquire any, or any specific number of, units and may be discontinued at any time. We intend to cancel any units repurchased under the repurchase program. We intend to fund the repurchase program from the proceeds of potential future sales of a portion of the Regency Common Units, which the use of these sales proceeds is expressly permitted under our Credit Agreement.

Capital Expenditures

The energy business can be capital intensive, requiring significant investment for the acquisition or development of new facilities. Due to the completion of the contribution of our Midstream Business to Regency on July, 1, 2014, we now categorize our capital expenditures as (and, as necessary, allocate the attributable portion of our capital expenditures between) either:


•	growth capital expenditures, defined as expenditures to grow our natural gas, NGL, crude or sulfur production; or


•	maintenance capital expenditures, defined as expenditures necessary to maintain our natural gas, NGL, crude or sulfur production.

With respect to maintenance capital expenditures intended to maintain our 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

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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.

We anticipate that our capital expenditures for the remainder of 2014 will be approximately $29 million, of which we expect approximately $13.8 million to be categorized as maintenance capital expenditures and $15.2 million to be categorized as growth capital expenditures.

Our capital expenditures, excluding amounts related to our Midstream Business, were approximately $32.4 million and $109.4 million for the three and nine months ended September 30, 2014, respectively, of which $14.5 million and $43.5 million were related to maintenance capital expenditures and $17.9 million and $65.9 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 September 30, 2014 had resulted in increased sulfur production and reductions in SO₂ emissions to levels within the required permitted levels.

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 2016 at a cost of approximately $11.6 million net to our interest. We expect the facility will require further upgrades to repair or replace certain sulfur recovery unit components beyond 2016.

Distribution Policy

Our distribution policy is to distribute to our unitholders, on a quarterly basis, all of our available cash, if any, 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, upon management's recommendation, decided to suspend the quarterly distribution in order to preserve liquidity in advance of closing the contribution of the Midstream Business to Regency. For the quarter ended June 30, 2014, the Board of Directors, upon management's recommendation, decided to continue the suspension of the quarterly distribution. Upon management's recommendation, the Board of Directors approved the resumption of the quarterly distribution for the quarter ended September 30, 2014.

The actual distributions we will declare will be subject to our operating performance, prevailing market conditions (including forward oil, condensate, natural gas, natural gas liquid 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.

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Revolving Credit Facility

On October 10, 2014, the we entered into the Fifth Amendment (the "Fifth Amendment") to our Amended and Restated Credit Agreement (as amended, the "Credit Agreement"). The Fifth Amendment, among other items, provided for current commitments totaling $320 million, with the ability to increase commitments up to a total aggregate amount of $1.2 billion. The Fifth Amendmentcoincided with the semi-annual borrowing base redetermination by our commercial lenders and the next redetermination will be in April 2015. The amendment extended the maturity to October 2019. In addition, as a result of the completion of the Midstream Business contribution, our borrowing base under the Credit Agreement is now strictly based on the value of our oil and natural gas properties and our commodity derivative contracts, which was formerly referred to as the upstream component of the borrowing base.

As of September 30, 2014, our borrowing base totaled approximately $330 million, and based on our outstanding borrowings and letters of credit, we had approximately $104.3 million of availability under the Credit Agreement.

Senior Unsecured Notes

On July 1, 2014, as part of the contribution of the Midstream Business to Regency, $498.9 million face amount of newly-issued Regency unsecured senior notes due 2019 were exchanged for $498.9 million face amount of our existing Senior Notes. Thus, as of July 1, 2014, only $51.1 million face amount of our unsecured senior notes remained outstanding.

Debt Covenants

Per agreement with our commercial lenders, the revised covenant structure specified in the Amended Credit Agreement was applied as of September 30, 2014. The following table presents the revised debt covenant levels specified in the Amended Credit Agreement:



Quarter Ended	Total Leverage Ratio	Current Ratio
September 30, 2014 and Thereafter until Maturity (October 2019)	4.0	1.0

The following table presents the Partnership's actual covenant ratios as of September 30, 2014:



Total leverage ratio	2.34
Current ratio	7.32

As of September 30, 2014, we were in compliance with the financial covenants under the Credit Agreement.

$51.1 million of our Senior Notes did not exchange as part of the transaction with Regency and remain outstanding under an amended indenture with substantially all of the restrictive covenants and certain events of default eliminated.

For a further discussion of the Credit Agreement and Senior Notes, see Note 7 to our consolidated financial statements included in "Part II. Item 8. Financial Statements and Supplementary Data" of the 2013 10-K.

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 common unit grants). The distribution was paid on February 14, 2014.

The quarterly cash distributions were suspended, upon recommendation of management and approval by the Board, for the quarters ended March 31, 2014 and June 30, 2014.

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On October 27, 2014, we declared our third quarter 2014 cash distribution of $0.07 per unit to our common unitholders of record as of the close of business on November 7, 2014 (excluding certain ineligible restricted common units). The distribution will be paid on November 14, 2014.

Working Capital

Working capital is the amount by which current assets exceed current liabilities. As of September 30, 2014, working capital was a positive $259.5 million as compared to a negative $52.8 million as of December 31, 2013, excluding assets and liabilities held for sale.

The net increase in working capital of $312.3 million from December 31, 2013 to September 30, 2014, resulted primarily from the following factors:


•	cash and cash equivalents increased by $0.5 million primarily due to the timing of payments and the receipt of cash;


•	short-term investments increased by $269.0 million as a result of Regency common units received as partial consideration in connection with the Midstream Business Contribution;


•	trade accounts receivable increased $16.4 million, primarily from higher volumes and the timing of the receipt of payments;


•	prepayment and other current assets increased $4.9 million primarily due to the payment of insurance premiums;


•	accounts payable decreased by $6.1 million primarily as a result of the timing of payments of unbilled expenditures;


•	risk management net working capital balance increased by a net $3.9 million as a result of changes in the current portion of mark-to-market unrealized positions as a result of decreases to the forward natural gas, oil and NGL price curves; and


•	accrued liabilities decreased by $13.4 million primarily as a result of lower interest and compensation accruals.

Cash Flows for the Nine Months Ended September 30, 2014, Compared to the Nine Months Ended September 30, 2013

Cash Flow from Operating Activities. Cash flows from operating activities decreased $51.1 million during the nine months ended September 30, 2014, as compared to the nine months ended September 30, 2013.

The decrease was driven by:


•	Timing of cash payments and cash receipts; and


•	A decrease in our results of operations due to commodity risk management losses.

Cash Flows from Investing Activities. Cash flows used in investing activities decreased $10.6 million during the nine months ended September 30, 2014, as compared to the nine months ended September 30, 2013. The decrease was due to the timing of payments for capital expenditures during the nine months ended September 30, 2014 as compared to the same period in 2013.

Cash Flows from Financing Activities. Cash flows used in financing activities increased $553.0 million during the nine months ended September 30, 2014, as compared to the nine months ended September 30, 2013.

The increase was driven by:


•	Increase in net repayments of long-term debt of $526.6 million during the nine months ended September 30, 2014, as compared to the same period in 2013; and


•	Decreased distributions of $78.3 million during the nine months ended September 30, 2014, as compared to the same period in 2013, as a result of the suspension of our quarterly distribution for the first and second quarters of 2014.

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This increase was partially offset by:


•	Proceeds from derivative contracts decreased by $6.2 million during the nine months ended September 30, 2014, as compared to the same period in 2013; and


•	Decreased net proceeds of $97.9 million from our equity offering during the nine months ended September 30, 2013, as compared to the same period in 2014.

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 September 30, 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" 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 Credit Agreement which is designed to measure the viability of us and our ability to perform under the terms of our Credit Agreement uses a variant of 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 September 30,						Nine Months Ended September 30,
	2014			2013			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	$	21,823		$	41,452		$	47,497		$	98,619
Add (deduct):
Discontinued operations	249,057			(21,223		)	212,808			(38,912		)
Depreciation, depletion, amortization and impairment	(39,564		)	(83,860		)	(80,269		)	(129,055		)
Amortization of debt issuance costs	(609		)	(591		)	(1,878		)	(1,557		)
(Loss) gain from risk management activities, net	27,886			(11,337		)	(1,089		)	(1,142		)
Derivative settlements - operating	(1,267		)	(955		)	4,047			(5,979		)
Other	(3,019		)	(1,717		)	(6,922		)	(7,323		)
Accounts receivable and other current assets	(3,424		)	(7,896		)	21,304			(14,107		)
Accounts payable and accrued liabilities	17,024			(7,186		)	9,816			(11,008		)
Other assets and liabilities	(1,619		)	1,748			(630		)	1,417
Net loss	266,288			(91,565		)	204,684			(109,047		)
Add (deduct):
Interest expense, net	4,886			6,337			18,010			19,272
Depreciation, depletion, amortization and impairment	39,564			83,860			80,269			129,055
Income tax expense benefit	(886		)	(2,155		)	(2,636		)	(4,260		)
EBITDA	309,852			(3,523		)	300,327			35,020
Add (deduct):
Loss (gain) from risk management activities, net	(27,886		)	11,337			1,089			1,142
Total derivative settlements	(471		)	1,131			(9,210		)	7,031
Restricted unit compensation expense	2,948			3,044			6,990			7,749
Non-cash mark-to-market Upstream imbalances	3			3			(4		)	(2		)
Discontinued operations	(249,057		)	21,223			(212,808		)	38,912
ADJUSTED EBITDA	$	35,389		$	33,215		$	86,384		$	89,852

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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 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. 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. At this time, our practice is to not add new proxy hedges to our portfolio and to seek opportunities to convert our existing ones to direct product hedges.

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 September 30, 2014, our commodity hedge portfolio totaled a net liability position of $10.8 million, consisting of assets aggregating $12.7 million and liabilities aggregating $1.9 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 commodity sales agreements and hedging portfolio and expect to continue to adjust our hedge position as conditions warrant.

Interest Rate Risk

We are exposed to variable interest rate risk as a result of borrowings under our Credit Agreement. To mitigate its interest rate risk, we have entered into various interest rate swaps that eliminate interest rate variability by effectively 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.

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 September 30, 2014, the fair value liability of these

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interest rate contracts totaled approximately $4.9 million. For additional information about our interest rate swaps and related fair values, see "Part I. Item 1. Financial Statements" Notes 10 and 11.

As of July 1, 2014, due to the completion of the contribution of the Midstream Business to Regency and the use of some of the consideration received from the transaction to pay down a portion of the amount outstanding under our Credit Agreement, the notional amount of our interest rate swaps was in excess of our outstanding floating rate borrowings. We may evaluate lowering the notional amount and extending the tenor of the existing swap portfolio.

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 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 September 30, 2014 included Wells Fargo Bank, National Association, Comerica Bank, 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, 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 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 the Midstream Business Contribution, 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 "Exchange Act"). 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 to have the sale rescinded, monetary damages and attorneys’ fees.


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, and the subsequent Quarterly Report on Form 10-Q for the quarter ended March 31, 2014.

We cannot control the value of the Regency common units we received as part of the consideration for the Midstream Business Contribution, and a significant reduction in the value of the common units could have a material adverse effect on our liquidity.

As part of the consideration for the Midstream Business Contribution, we received approximately 8.2 million Regency common units. These common units represent a significant source of potential liquidity for us. The value of the Regency common units, however, is based on a fluctuating market price and is thus outside of our control. In addition, the value of the Regency common units is subject to a number of risks, including those described in Regency’s Annual Report on Form 10-K for the year ended December 31, 2013 and its Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2014, as well as Regency's subsequent public filings. If the market price of the Regency common units that we hold were to decline significantly, it could have a material adverse effect on our liquidity.

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

The following table sets forth certain information with respect to repurchases of common units during the three months ended September 30, 2014:



Period	Total Number of Units Purchased		Average Price Paid Per Unit		Total Number of Units Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Units that May Yet Be Purchased Under the Plans or Programs
July 1, 2014 - July 31, 2014	(4,479	)	$	4.79	—	—
August 1, 2014 - August 31, 2014	(7,082	)	$	4.35	—	—
September 1, 2014 - September 30, 2014	(8,441	)	$	4.12	—	—
Total	(20,002	)	$	4.35	—	—

All of the units were surrendered by employees to pay tax withholding in connection with the vesting of restricted common units. As a result, we are deeming the surrenders to be "repurchases." These repurchases were not part of a publicly announced program to repurchase our common units, nor do we have a publicly announced program to repurchase our common units.

Item 3. Defaults Upon Senior Securities

None

Item 4. 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).

4.1	Third Supplemental Indenture dated as of July 1, 2014, among Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 of the registrant's current report on Form 8-K filed with the Commission on July 3, 2014).

10.1	Fifth Amendment to Amended and Restated Credit Agreement, dated as of October 10, 2014, among Eagle Rock Energy Partners, L.P., as borrower, Wells Fargo Bank, National Association, as administrative agent and swingline lender, Bank of America, N.A. and The Royal Bank of Scotland plc, as co-syndication agents and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the registrant's current report on Form 8-K filed with the Commission on October 14, 2014).

10.2*	Master Agreement by and between the Company and Roger A. Fox, dated September 16, 2014.

10.3	Amended and Restated Eagle Rock Energy Partners, L.P. Long-Term Incentive Plan dated June 24, 2014 (incorporated by reference to Exhibit 10.1 of the registrant's current report on Form 8-K filed with the Commission on August 20, 2014).

10.4	Form of Performance Unit Agreement for Officers under the Amended and Restated Eagle Rock Energy Partners Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 of the registrant's current report on Form 8-K filed with the Commission on August 20, 2014).

10.5	Form of Restricted Unit Agreement for Officers under the Amended and Restated Eagle Rock Energy Partners Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 for the registrant's current report on Form 8-K filed with the Commission on August 20, 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 Robert M. Haines 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 Robert M. Haines 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.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on October 31, 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/ ROBERT M. HAINES
	Name:		Robert M. Haines
	Title:		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).

4.1	Third Supplemental Indenture dated as of July 1, 2014, among Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 of the registrant's current report on Form 8-K filed with the Commissions on July 3, 2014).

10.1	Fifth Amendment to Amended and Restated Credit Agreement, dated as of October 10, 2014, among Eagle Rock Energy Partners, L.P., as borrower, Wells Fargo Bank, National Association, as administrative agent and swingline lender, Bank of America, N.A. and The Royal Bank of Scotland plc, as co-syndication agents and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the registrant's current report on Form 8-K filed with the Commission on October 14, 2014).

10.2*	Master Agreement by and between the Company and Roger A Fox, dated September 16, 2014.

10.3	Amended and Restated Eagle Rock Energy Partners, L.P. Long-Term Incentive Plan dated June 24, 2014 (incorporated by reference to Exhibit 10.1 of the registrant's current report on Form 8-K filed with the Commission on August 20, 2014).

10.4	Form of Performance Unit Agreement for Officers under the Amended and Restated Eagle Rock Energy Partners Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 of the registrant's current report on Form 8-K filed with the Commission on August 20, 2014).

10.5	Form of Restricted Unit Agreement for Officers under the Amended and Restated Eagle Rock Energy Partners Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 for the registrant's current report on Form 8-K filed with the Commission on August 20, 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 Robert M. Haines 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 Robert M. Haines 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.

EAGLE ROCK ENERGY PARTNERS L P - FORM 10-Q - October 31, 2014

Attached files

EAGLE ROCK ENERGY PARTNERS L P Reports