UNITED STATES


SECURITIES AND EXCHANGE COMMISSION


Washington, D.C. 20549







FORM 10-Q





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




For the quarterly period ended March 31, 2010




OR




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




Commission File No. 001-33016







EAGLE ROCK ENERGY PARTNERS, L.P.


(Exact Name of Registrant as Specified in Its Charter)








Delaware
68-0629883(State or Other Jurisdiction of

Incorporation or Organization)
(I.R.S. Employer

Identification Number)




1415 Louisiana Street, Suite 2700


Houston, Texas 77002


(Address of principal executive offices, including zip code)




(281) 408-1200


(Registrant’s telephone number, including area code)







Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No   ̈




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   ̈    No   ̈




Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):





Large accelerated filer   ̈
Accelerated filer  xNon-accelerated filer   ̈
Smaller Reporting Company   ̈(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   ̈    No  x




The issuer had 55,926,989 common units outstanding as of May 3, 2010.














EAGLE ROCK ENERGY PARTNERS, L.P.




TABLE OF CONTENTS










PagePART I. FINANCIAL INFORMATIONItem 1.
Financial StatementsUnaudited Condensed Consolidated Balance Sheets as of March 31, 2010 and December 31, 2009
2Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2010 and 2009
3Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2010 and 2009
5Unaudited Condensed Consolidated Statements of Members’ Equity for the three months ended March 31, 2010 and 2009
6Notes to the Unaudited Condensed Consolidated Financial Statements
7Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
26Item 3.
Quantitative and Qualitative Disclosures About Market Risk
41Item 4.
Controls and Procedures
41PART II. OTHER INFORMATIONItem 1.
Legal Proceedings
42Item 1A.
Risk Factors
42Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
42Item 3.
Defaults Upon Senior Securities
42Item 4.
Reserved
42Item 5.
Other Information
43Item 6.
Exhibits
43























1
 Table of Contents







PART I. FINANCIAL INFORMATION




Item 1.
Financial Statements.





EAGLE ROCK ENERGY PARTNERS, L.P.


UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS


($ in thousands)





March 31,


December 31,2010


2009ASSETSCURRENT ASSETS:Cash and cash equivalents

$
149


$
2,732Accounts receivable(1)


88,935



91,164Risk management assets


6,349



2,479Prepayments and other current assets


3,513



2,790Total current assets


98,946



99,165PROPERTY, PLANT AND EQUIPMENT — Net


1,260,745



1,275,881INTANGIBLE ASSETS — Net


127,157



132,343DEFERRED TAX ASSET


2,159



1,562RISK MANAGEMENT ASSETS


7,566



3,410OTHER ASSETS


22,648



21,967TOTAL

$
1,519,221


$
1,534,328LIABILITIES AND MEMBERS’ EQUITYCURRENT LIABILITIES:Accounts payable

$
78,089


$
78,096Due to affiliate


12,883



12,910Accrued liabilities


8,046



11,110Taxes payable


2,412



2,416Risk management liabilities


51,940



51,650Total current liabilities


153,370



156,182LONG-TERM DEBT


737,383



754,383ASSET RETIREMENT OBLIGATIONS


20,126



19,829DEFERRED TAX LIABILITY


41,192



40,246RISK MANAGEMENT LIABILITIES


31,795



32,715OTHER LONG TERM LIABILITIES


575



575COMMITMENTS AND CONTINGENCIES (Note 12)MEMBERS’ EQUITY:Common Unitholders(2)


487,039



484,282Subordinated Unitholders(3)


53,640



52,058General Partner(4)


(5,899
)


(5,942
)Total members’ equity


534,780



530,398TOTAL

$
1,519,221


$
1,534,328





(1)
Net of allowable for bad debt of $5,005 as of March 31, 2010 and $4,818 as of December 31, 2009.


(2)
54,203,471 units were issued and outstanding as of March 31, 2010 and December 31, 2009.  These amounts do not include unvested restricted common units granted under the Partnership’s long-term incentive plan of 1,379,961 and 1,371,019 as of March 31, 2010 and December 31, 2009, respectively.


(3)
20,691,495 units were issued and outstanding as of March 31, 2010 and December 31, 2009.


(4)
844,551 units were issued and outstanding as of March 31, 2010 and December 31, 2009.




See notes to unaudited condensed consolidated financial statements.





2
 Table of Contents







EAGLE ROCK ENERGY PARTNERS, L.P.


UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


($ in thousands)





Three MonthsEnded March 31,2010


2009REVENUE:Natural gas, natural gas liquids, oil, condensate and sulfur sales

$
199,296


$
158,490Gathering, compression, processing and treating fees


12,833



11,667Minerals and royalty income


5,649



3,239Commodity risk management gains


10,795



26,256Other revenue


36



42Total revenue


228,609



199,694COSTS AND EXPENSES:Cost of natural gas and natural gas liquids


144,278



133,217Operations and maintenance


19,235



18,641Taxes other than income


3,999



2,978General and administrative


13,088



12,538Impairment


-



242Depreciation, depletion and amortization


29,435



30,063Total costs and expenses


210,035



197,679OPERATING  INCOME


18,574



2,015OTHER INCOME (EXPENSE):Interest income


2



32Other income


268



560Interest expense, net


(4,145
)


(7,539
)Interest rate risk management losses


(9,712
)


(383
)Other expense


(269
)


(267
)Total other income (expense)


(13,856
)


(7,597
)INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES


4,718



(5,582
)INCOME TAX (BENEFIT) PROVISION


765



(2,730
)INCOME (LOSS) FROM CONTINUING OPERATIONS


3,953



(2,852
)DISCONTINUED OPERATIONS


28



307NET INCOME (LOSS)

$
3,981


$
(2,545
)





See notes to unaudited condensed consolidated financial statements.








3
 Table of Contents







EAGLE ROCK ENERGY PARTNERS, L.P.


UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (continued)


(In thousands, except per unit amounts)














Three MonthsEnded March 31,2010


2009NET INCOME (LOSS) PER COMMON UNIT — BASIC:Basic and diluted:Income (loss) from continuing operations per unitCommon units

$
0.06


$
(0.03
)Subordinated units

$
0.03


$
(0.06
)General partner units

$
0.06


$
(0.03
)Discontinued operations per unitCommon units

$
-


$
-Subordinated units

$
-


$
-General partner units

$
-


$
-Net income (loss) per unitCommon units

$
0.06


$
(0.03
)Subordinated units

$
0.03


$
(0.06
)General partner units

$
0.06


$
(0.03
)Weighted average number of basic outstanding (units in thousands)Common units


54,203



53,044Subordinated units


20,691



20,691General partner units


845



845Weighted average number diluted outstanding (units in thousands)Common units


54,420



53,044Subordinated units


20,691



20,691General partner units


845



845











See notes to unaudited condensed consolidated financial statements.








4
 Table of Contents







EAGLE ROCK ENERGY PARTNERS, L.P.


UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


($ in thousands)








Three Months Ended March 31,2010


2009CASH FLOWS FROM OPERATING ACTIVITIES:Net (loss) income

$
3,981


$
(2,545
)Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:Depreciation, depletion and amortization


29,435



30,063Impairment


-



242Amortization of debt issuance costs


269



267Equity in earnings of unconsolidated affiliates


(181
)


(505
)Distribution from unconsolidated affiliates—return on investment


338



51Reclassing financing derivative settlements


(305
)


(4,317
)Equity-based compensation


1,808



2,231Gain on sale of assets


(19
)


-Other


689



(2,507
)Changes in assets and liabilities—net of acquisitions:Accounts receivable


2,229



26,912Prepayments and other current assets


(723
)


(2,337
)Risk management activities


(8,656
)


(12,475
)Accounts payable


264



(42,843
)Due to affiliates


(27
)


7,197Accrued liabilities


(3,064
)


(5,458
)Other assets


(1,618
)


1,407Other current liabilities


(47
)


-Net cash provided by (used in) operating activities


24,373



(4,617
)CASH FLOWS FROM INVESTING ACTIVITIES:Additions to property, plant and equipment


(8,258
)


(13,087
)Investment in partnerships


(128
)


(341
)Proceeds from sale of asset


33



-Purchase of intangible assets


(580
)


(718
)Net cash used in investing activities


(8,933
)


(14,146
)CASH FLOWS FROM FINANCING ACTIVITIES:Proceeds from long-term debt


18,000



109,000Repayment of long-term debt


(35,000
)


(71,000
)Proceeds from derivative contracts


305



4,317Distributions to members and affiliates


(1,328
)


(31,639
)Net cash (used in) provided by financing activities


(18,023
)


10,678NET DECREASE IN CASH AND CASH EQUIVALENTS


(2,583
)


(8,085
)CASH AND CASH EQUIVALENTS—Beginning of period


2,732



17,916CASH AND CASH EQUIVALENTS—End of period

$
149


$
9,831Interest paid—net of amounts capitalized

$
4,254


$
10,828Cash paid for taxes

$
419


$
114Investments in property, plant and equipment, not yet paid

$
3,972


$
4,063Deferred transaction fees, not yet paid

$
594


$
-







See notes to unaudited condensed consolidated financial statements.





5
 Table of Contents





EAGLE ROCK ENERGY PARTNERS, L.P.


UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY





FOR THE THREE MONTH PERIOD ENDED MARCH 31, 2009


($ in thousands, except unit amounts)








General Partner


Number of Common Units


Common Units


Number of Subordinated Units


Subordinated Units


TotalBALANCE — January 1, 2009

$
(3,714
)


53,043,767


$
625,590



20,691,495


$
105,839


$
727,715Net loss


(29
)


-



(1,810
)


-



(706
)


(2,545
)Distributions


(316
)


-



(22,785
)


-



(8,538
)


(31,639
)Equity based compensation


22



-



1,607



-



602



2,231BALANCE — March 31, 2009

$
(4,037
)


53,043,767


$
602,602



20,691,495


$
97,197


$
695,762











FOR THE THREE MONTH PERIOD ENDED MARCH 31, 2010


($ in thousands, except unit amounts)











General Partner


Number of Common Units


Common Units


Number of Subordinated Units


Subordinated Units


TotalBALANCE — January 1, 2010

$
(5,942
)


54,203,471


$
484,282



20,691,495


$
52,058


$
530,398Net income


44



-



2,849



-



1,088



3,981Distributions


(21
)


-



(1,386
)


-



-



(1,407
)Equity based compensation


20



-



1,294



-



494



1,808BALANCE — March 31, 2010

$
(5,899
)


54,203,471


$
487,039



20,691,495


$
53,640


$
534,780










See notes to unaudited condensed consolidated financial statements.








6
 Table of Contents








EAGLE ROCK ENERGY PARTNERS, L.P.


NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS







NOTE 1. ORGANIZATION AND DESCRIPTION OF BUSINESS




Basis of Presentation and Principles of Consolidation—The accompanying financial statements include assets, liabilities and the results of operations of Eagle Rock Energy Partners, L.P. (“Eagle Rock Energy” or the “Partnership”). The general partner of Eagle Rock Energy is Eagle Rock Energy GP, L.P. The general partner of Eagle Rock Energy GP, L.P. is Eagle Rock Energy G&P, LLC. a wholly-owned subsidiary of Eagle Rock Holdings, L.P. (“Holdings”). 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, 2009. That report contains a more comprehensive summary of the Partnership’s major accounting policies. In the opinion of management, the accompanying unaudited condensed consolidated financial statements contain all appropriate adjustments, all of which are normally recurring adjustments unless otherwise noted, considered necessary to present fairly the financial position of the Partnership and its consolidated subsidiaries and the results of operations and cash flows for the respective periods. Operating results for the three month period ended March 31, 2010 are not necessarily indicative of the results that may be expected for the year ending December 31, 2010.





Description of Business— The Partnership is a domestic focused growth-oriented limited partnership engaged in the business of (i) gathering, compressing, treating, processing and transporting and selling natural gas; fractionating and transporting natural gas liquids (“NGLs”); and marketing natural gas, condensate and NGLs, which collectively the Partnership calls its “Midstream Business;” (ii) acquiring, developing and producing hydrocarbons in oil and natural gas properties, which the Partnership calls its “Upstream Business;” and (iii) acquiring and managing fee mineral and royalty interests, either through direct ownership or through investment in other partnerships in properties in multiple producing trends across the United States, which the Partnership calls its “Minerals Business.”  See Note 13 for a further description of the Partnership’s three businesses and the seven reportable segments in which it reports.




NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES




The accompanying condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. All intercompany accounts and transactions are eliminated in the consolidated financial statements.




The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates and such differences could be material.




The Partnership has provided a discussion of significant accounting policies in its annual report on Form 10-K for the year ended December 31, 2009. Certain items from that discussion are repeated or updated below as necessary to assist in understanding these financial statements.




Oil and Natural Gas Accounting Policies





The Partnership utilizes the successful efforts method of accounting for its oil and natural gas properties. Leasehold costs are capitalized when incurred. Costs incurred to drill and complete development wells, including dry holes, are capitalized. Unproved properties are assessed periodically within specific geographic areas and, if necessary, impairments are charged to expense. Geological and geophysical expenses and delay rentals are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if the well is determined to be unsuccessful. The Partnership carries the costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well as long as the Partnership is making sufficient progress towards assessing the reserves and the economic and operating viability of the project.




Depletion of producing oil and natural gas properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for acquisition costs using all proved reserves. Authoritative guidance requires that acquisition costs of proved properties be amortized on the basis of all proved reserves, (developed and undeveloped) and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves.





Upon sale or retirement of complete fields of depreciable or depleted property, the book value thereof, less proceeds or salvage value, is charged or credited to income.




Impairment of Oil and Natural Gas Properties





The Partnership reviews its proved properties at the field level when management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future oil and natural gas reserves that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels. If the carrying amount of an asset exceeds the sum of the undiscounted estimated future net cash flows, the Partnership recognizes impairment expense equal to the difference between the carrying value and the fair value of the asset, which is estimated to be the expected present value of discounted future net cash flows from proved reserves utilizing the Partnership’s estimated weighted average cost of capital.  The Partnership recorded impairment charges of $0.2 million in its Upstream Segment as a result of a continued decline in natural gas prices during the three months ended March 31, 2009.  No impairment charges were incurred during the three months ended March 31, 2010.  The Partnership cannot predict the amount of additional impairment charges that may be recorded in the future.





Unproved leasehold costs are reviewed periodically and a loss is recognized to the extent, if any, that the cost of the property has been impaired. Unproved properties that are individually insignificant are amortized. Unproved properties that are individually significant are assessed for impairment on a property-by-property basis. If considered impaired, costs are charged to expense when such impairment is deemed to have occurred.




Other Significant Accounting Policies




Transportation and Exchange Imbalances—In the course of transporting natural gas and natural gas liquids for others, the Partnership’s Midstream Business may receive for redelivery different quantities of natural gas or natural gas liquids than the quantities actually delivered. These transactions result in transportation and exchange imbalance receivables or payables which, if not subject to cash-out provisions, are recovered or repaid through the receipt or delivery of natural gas or natural gas liquids in future periods. Imbalance receivables are included in accounts receivable; imbalance payables are included in accounts payable on the unaudited condensed consolidated balance sheets and marked-to-market using current market prices in effect for the reporting period of the outstanding imbalances. For the Midstream Business, as of March 31, 2010, the Partnership had imbalance receivables totaling $0.4 million and imbalance payables totaling $2.9 million, respectively. For the Midstream Business, as of December 31, 2009, the Partnership had imbalance receivables totaling $0.3 million and imbalance payables totaling $2.9 million, respectively. 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 and natural gas liquids sold.




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




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




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




•
NGL transportation from which we generate revenues from transportation fees; and




•
royalties, overriding royalties and lease bonuses.




Revenues associated with sales of natural gas, NGLs, crude oil and condensate are recognized when title passes to the customer, which is when the risk of ownership passes to the customer and physical delivery occurs. Revenues associated with transportation and processing fees are recognized when the service is provided.





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 Table of Contents


For gathering and processing services, Eagle Rock Energy either receives fees or commodities from natural gas producers depending on the type of contract. Under the percentage-of-proceeds contract type, Eagle Rock Energy is paid for its services by keeping a percentage of the NGLs produced and a percentage of the residue gas resulting from processing the natural gas. Commodities received are in turn sold and recognized as revenue in accordance with the criteria outlined above. Under the keep-whole contract type, Eagle Rock Energy purchases wellhead natural gas to return to the producer and sells processed natural gas and NGLs to third parties.





Transportation, compression and processing-related revenues are recognized in the period when the service is provided and include the Partnership’s fee-based service revenue for services such as transportation, compression and processing.





The Partnership’s Upstream Segment recognizes revenues based on actual volumes of crude oil and natural gas sold to purchasers. The volumes of natural gas sold may differ from the volumes to which the Partnership is entitled based on its interests in the properties. Differences between volumes sold and volumes based on entitlements create natural gas imbalances. Material imbalances are reflected as adjustments to reported natural gas reserves and future cash flows.  As of March 31, 2010, the Partnership’s Upstream Segment had an imbalance receivable balance of $2.6 million and an imbalance payable balance of $0.9 million.  As of December 31, 2009, the Partnership’s Upstream Segment had an imbalance receivable balance of $1.9 million and an imbalance payable balance of $0.5 million.





A significant portion of the Partnership’s sale and purchase arrangements are accounted for on a gross basis in the consolidated statements of operations as natural gas sales and costs of natural gas, respectively. These transactions are contractual arrangements which establish the terms of the purchase of natural gas at a specified location and the sale of natural gas at a different location at the same or at another specified date. These arrangements are detailed either jointly, in a single contract, or separately in individual contracts which are entered into concurrently or in contemplation of one another with a single or multiple counterparties. Both transactions require physical delivery of the natural gas and the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk and counterparty nonperformance risk. Under authoritative guidance, purchase and sale agreements with the same counterparty are required to be recorded on a net basis.  For the three months ended March 31, 2010 and 2009, the Partnership did not enter into any purchase and sale agreements with the same counterparty.




Derivatives—The Partnership recognizes all derivatives as either assets or liabilities in the statement of financial position and measures those instruments at fair value. The Partnership uses financial instruments such as put and call options, swaps and other derivatives to mitigate the risks to cash flows resulting from changes in commodity prices and interest rates. Because the Partnership has not designated any of these derivatives as hedges, the Partnership recognizes any changes in fair value in the unaudited condensed consolidated statements of operations. 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 statements of cash flows. See Note 11 for a description of the Partnership’s risk management activities.




NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS





The Financial Accounting Standards Board (the “FASB”) has codified a single source of U.S. Generally Accepted Accounting Principles (U.S. GAAP), the Accounting Standards Codification.Unless needed to clarify a point to readers, the Partnership will refrain from citing specific section references when discussing application of accounting principles or addressing new or pending accounting rule changes.





In June 2009, the FASB issued authoritative guidance which reflects the FASB’s response to issues entities have encountered when applying previous guidance.  In addition, this guidance addresses concerns expressed by the Securities and Exchange Commission (“SEC”), members of the United States Congress, and financial statement users about the accounting and disclosures required in the wake of the subprime mortgage crisis and the deterioration in the global credit markets.  In addition, because this guidance eliminates the exemption from consolidation for qualified special-purpose entities (“QSPEs”) a transferor will need to evaluate all existing QSPEs to determine whether they must be consolidated.   The guidance is effective for financial asset transfers occurring after the beginning of an entity’s first fiscal year that begins after November 15, 2009.  Early adoption of the guidance was prohibited.   This guidance was effective for the Partnership as of January 1, 2010 and did not have a material impact on its consolidated financial statements.





In June 2009, the FASB issued authoritative guidance, which amends the consolidation guidance applicable to variable interest entities (VIEs). The amendments will significantly affect the overall consolidation analysis.  While the FASB’s discussions leading up to the issuance of this guidance focused extensively on structured finance entities, the amendments to the consolidation guidance affect all entities and enterprises, as well as qualifying special-purpose entities (QSPEs) that were excluded from previous guidance.  Accordingly, an enterprise will need to carefully reconsider its previous conclusions, including (1) whether an entity is a VIE, (2) whether the enterprise is the VIE’s primary beneficiary, and (3) what type of financial statement disclosures are required.  This guidance is effective as of the beginning of the first fiscal year that begins after November 15, 2009, and early adoption was prohibited.  This guidance was effective for the Partnership as of January 1, 2010 and did not have a material impact on its consolidated financial statements.





In September 2009, the FASB issued a consensus which revises the standards for recognizing revenue on arrangements with multiple deliverables.  Before evaluating how to recognize revenue for transactions with multiple revenue generating activities, an entity should identify all the deliverables in the arrangement and, if there are multiple deliverables, evaluate each deliverable to determine the unit of accounting and whether it should be treated separately or in combination.  The consensus removes certain thresholds for separation, provides criteria for allocation of revenue amongst deliverables and expands disclosure requirements.  The standards will be effective June 1, 2010, for fiscal year 2011, unless the Partnership elects to early adopt the standards.   The Partnership has not determined if it will early adopt the standards.





In January 2010, the FASB issued additional guidance on fair value disclosures. The new guidance clarifies two existing disclosure requirements and requires new disclosures such as: (1) a “gross” presentation of activities (purchases, sales, and settlements) within the Level 3 rollforward reconciliation, which will replace the “net” presentation format; and (2) detailed disclosures about the transfers in and out of Level 1 and 2 measurements. This guidance is effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 rollforward information, which is required for annual reporting periods beginning after December 15, 2010, and for interim reporting periods within those years. The Partnership adopted the fair value disclosures guidance on January 1, 2010, except for the gross presentation of the Level 3 rollforward information which is not required to be adopted by the Partnership until January 1, 2011 (see Notes 10 and 11).




NOTE 4. ACQUISITIONS




2008 Acquisitions





Update on Millennium Acquisition.   On October 1, 2008, the Partnership completed the acquisition of 100% of the outstanding units of Millennium Midstream Partners, L.P. (“MMP”).   MMP is in the natural gas gathering and processing business, with assets located in East, Central and West Texas and South Louisiana.  With respect to the South Louisiana assets acquired in the acquisition, the Yscloskey and North Terrebonne facilities were flooded with three to four feet of water as a result of the storm surges caused by Hurricanes Ike and/or Gustav.  The North Terrebonne facility came back on-line in November 2008 and the Yscloskey facility came back on-line in January 2009.  The former owners of MMP provided the Partnership indemnity coverage for Hurricanes Gustav and Ike to the extent losses are not covered by insurance and established an escrow account of 1,818,182 common units and $0.6 million in cash available for the Partnership to recover against for this purpose.  As of December 31, 2009, the escrow account held 391,304 common units.  During the three months ended March 31, 2010, the Partnership recovered an additional 3,759 common units.  On April 1, 2010, the Partnership released 330,604 units out of escrow to the former owners of MMP and recovered the remaining 56,941 units held in escrow.  As of April 1, 2010, the Partnership had an additional claim for $0.2 million cash out of escrow.





8
 Table of Contents


NOTE 5. FIXED ASSETS AND ASSET RETIREMENT OBLIGATIONS




Fixed assets consisted of the following:







March 31,


December 31,2010


2009($ in thousands)Land

$
1,559


$
1,559Plant


243,971



242,223Gathering and pipeline


677,157



675,474Equipment and machinery


23,119



22,527Vehicles and transportation equipment


4,232



4,232Office equipment, furniture, and fixtures


1,279



1,248Computer equipment


7,419



6,912Corporate


126



126Linefill


4,269



4,269Proved properties


519,752



512,545Unproved properties


69,779



72,174Construction in progress


14,528



15,5131,567,190



1,558,802Less: accumulated depreciation, depletion and amortization


(306,445
)


(282,921
)Net property, plant and equipment

$
1,260,745


$
1,275,881




Depreciation expense for the three months ended March 31, 2010 and 2009 was approximately $13.6 million and $13.2 million, respectively. Depletion expense for the three months ended March 31, 2010 and 2009 was approximately $10.0 million and $11.1 million, respectively.  The Partnership recorded impairment charges of $0.2 million in its Upstream Segment as a result of a continued decline in natural gas prices during the three months ended March 31, 2009.  The Partnership did not incur any impairment charges related to its Upstream Segment’s oil and natural gas properties during the three months ended March 31, 2010.   The Partnership capitalizes interest costs on major projects during extended construction time periods. Such interest costs are allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. During the three months ended March 31, 2010 and 2009, the Partnership capitalized interest costs of less $0.1 million and $0.1 million, respectively.




Asset Retirement Obligations—The Partnership recognizes asset retirement obligations for its oil and natural gas working interests associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. The Partnership records the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The Partnership recognizes asset retirement obligations for its midstream assets in accordance with the term “conditional asset retirement obligation,” which refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional upon a future event that may or may not be within the Partnership’s control. Although uncertainty about the timing and/or method of settlement may exist and may be conditional upon a future event, the obligation to perform the asset retirement activity is unconditional. Accordingly, the Partnership is required to recognize a liability for the fair value of a conditional asset retirement obligation upon initial recognition if the fair value of the liability can be reasonably estimated. As of March 31, 2010 and December 31, 2009, the Partnership had $1.0 million restricted in an escrow account for purposes of settling associated asset retirement obligations in the State of Alabama.





A reconciliation of our liability for asset retirement obligations is as follows:





2010


2009($ in thousands)Asset retirement obligations -- January 1

$
19,829


$
19,872Liabilities settled


(43
)


-Accretion expense


340



279Asset retirement obligations -- March 31

$
20,126


$
20,151








9
 Table of Contents





NOTE 6. INTANGIBLE ASSETS




Intangible Assets—Intangible assets consist of rights-of-way and easements and acquired customer contracts, which the Partnership amortizes over the term of the agreement or estimated useful life. Amortization expense was approximately $5.8 million for both the three months ended March 31, 2010 and 2009. Estimated aggregate amortization expense for 2010 and each of the four succeeding years is as follows: 2010—$22.4 million; 2011—$11.6 million; 2012—$11.6 million; 2013—$11.6 million; and 2014—$7.1 million. Intangible assets consisted of the following:












March 31,


December 31,2010


2009($ in thousands)Rights-of-way and easements—at cost

$
86,823


$
86,243Less: accumulated amortization


(16,857
)


(15,600
)Contracts


123,959



123,959Less: accumulated amortization


(66,768
)


(62,259
)Net intangible assets

$
127,157


$
132,343




The amortization period for our rights-of-way and easements is 20 years. The amortization period for contracts range from 5 to 20 years and are approximately 10 years on average as of March 31, 2010.





NOTE 7. LONG-TERM DEBT




As of March 31, 2010 and December 31, 2009, the Partnership had $737.4 million and $754.4 million outstanding, respectively, under its revolving credit facility.




As of March 31, 2010, the Partnership was in compliance with the financial covenants under its revolving credit facility.  The Partnership’s ability to comply with the financial covenants throughout 2010 is uncertain and will depend upon the Partnership’s ability to reduce debt, enhance its commodity hedge portfolio or otherwise increase its liquidity, or increase its Adjusted EBITDA due to a rebound in commodity prices and a related increase in drilling activity by the producers supplying its Midstream facilities’ volumes.  The Partnership’s strategy to remain in compliance includes (i) the liquidity enhancements as discussed in Note 9 under Recapitalization and Related Transactions, (ii) asset sales, and/or (iii) enhancements to its hedging portfolio (including through hedge reset transactions).  Based on its strategy, the Partnership believes that it will remain in compliance with its financial covenants through 2010.





Based upon the above mentioned ratios and conditions as calculated as of March 31, 2010, the Partnership has approximately $60.9 million of unused capacity under the revolving credit facility as of March 31, 2010 on which the Partnership pays a 0.3% commitment fee per year.





On March 8, 2010, the Partnership entered into the Second Amendment to its revolving credit facility (the “Credit Facility Amendment”), dated as of December 13, 2007, with Wachovia Bank, N.A., Bank of America, N.A., HSH NordBank AG, New York Branch, The Royal Bank of Scotland, PLC, BNP Paribas and the other lenders party thereto.





Prior to execution of the Credit Facility Amendment, the Partnership had concluded that it would require a waiver from its lender group in order to exercise the GP Acquisition Option under the Recapitalization and Related Transactions discussed in Note 9 without triggering a “Change in Control” event and potential event of default under its revolving credit facility.  The Credit Facility Amendment, however, modifies the definition of “Change in Control” in such a way that the exercise of the GP Acquisition Option would not trigger a “Change in Control” event and potential default provided the Partnership receives unitholder approval of the Recapitalization and Related Transactions prior to July 31, 2010.  In light of the Credit Facility Amendment, the Conflicts Committee of Eagle Rock’s Board of Directors currently intends to cause the Partnership to exercise the GP Acquisition Option as soon as practicable after the required unitholder approvals of the Recapitalization and Related Transactions.    The Credit Facility Amendment will take effect upon the Partnership providing written notice to its lender group that the required unitholder approvals have been obtained prior to July 31, 2010.




In addition to modifying the definition of “Change in Control,” the Credit Facility Amendment also:


·
Reduces the maximum permitted Senior Secured Leverage Ratio (as such term is defined in the revolving credit facility) from 4.25 under the current revolving credit facility to 3.75 as amended (and from 4.75 to 4.25 for specified periods following certain permitted acquisitions);





·
Obligates the Partnership to use $100 million of the proceeds from the Minerals Business sale to make a mandatory prepayment towards its outstanding borrowings under the revolving credit facility; and





·
Reduces, upon such mandatory prepayment, the Partnership’s borrowing capacity under the revolving credit facility by the $100 million amount of such mandatory prepayment; however, the Partnership’s availability under its revolving credit facility will not be impacted because it is calculated based on its outstanding debt and compliance with financial covenants





On April 19, 2010, the Partnership announced that the borrowing base under its revolving credit facility, which relates to its Upstream Business, was set at $130 million by its commercial lenders as part of the Partnership’s regularly scheduled semi-annual borrowing base redetermination.  The redetermined borrowing base is effective April 1, 2010, with no additional fees or increase in interest rate spread incurred.




NOTE 8. MEMBERS’ EQUITY




At March 31, 2010, there were 54,203,471 common units (exclusive of restricted unvested common units and common units held in escrow related to the Millennium Acquisition), 20,691,495 subordinated units (all of which are owned by Holdings) and 844,551 general partner units outstanding. In addition, there were 1,379,961 unvested restricted common units outstanding.





Subordinated units represent limited partner interests in the Partnership, and holders of subordinated units exercise the rights and privileges available to unitholders under the limited partnership agreement. Subordinated units, during the subordination period, will generally receive quarterly cash distributions only when the common units have received a minimum quarterly distribution of $0.3625 per unit and any outstanding arrearages on the common units have been paid. Subordinated units will convert into common units on a one-for-one basis when the subordination period ends.  The subordination period will end on the first day of any quarter beginning after March 31, 2010 in respect of which, among other things, the Partnership has earned and paid at least $1.45 (the minimum quarterly distribution on an annualized basis) on each outstanding limited partner unit and general partner unit for each of the three consecutive, non-overlapping four quarter periods immediately preceding such date and any outstanding arrearages on the common units have been paid.  Alternatively, the subordination period will end on the first business day after the Partnership earned and paid at least $0.5438 per quarter (150% of the minimum quarter distribution, or $2.175 on an annualized basis) on each outstanding limited partner unit and general partner unit for any four consecutive quarters ending on or after September 30, 2007 and there are no outstanding arrearages on the common units.  In addition, the subordination period will end upon the removal of the Partnership’s general partner other than for cause if the units held by the Partnership’s general partner and its affiliates are not voted in favor of such removal, at which point all outstanding common unit arrearages would be extinguished.  For each of the three months ended March 31, 2009, June 30, 2009, September 30, 2009, December 31, 2009 and March 31, 2010, the Partnership did not pay the full minimum quarterly distribution amount.  The first quarter 2010 Common Unit Arrearage is $0.3375 per common unit.  The Cumulative Common Unit Arrearage is expected to increase to $1.6875 per common unit with the payment of the first quarter 2010 distribution on May 14, 2010.  Both Common Unit Arrearage and Cumulative Common Unit Arrearage are terms defined in Eagle Rock Energy’s partnership agreement.





On February 2, 2010, the Partnership declared its fourth quarter 2009 cash distribution of $0.025 per unit to its general partner (as to its general partner units) and its common unitholders of record as of the close of business on February 8, 2010.  The distribution was paid on February 12, 2010, net of amounts retained to relieve outstanding amounts due from affiliates.





On April 27, 2010, the Partnership declared its first quarter 2010 cash distribution of $0.025 per unit to its general partner (as to its general partner units) and its common unitholders of record as of the close of business on May 7, 2010.  The distribution will be paid on May 14, 2010.





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 Table of Contents







NOTE 9. RELATED PARTY TRANSACTIONS





During the three months ended March 31, 2010 and 2009, the Partnership incurred $2.3 million and $0.1 million, respectively, in expenses with related parties, of which there was an outstanding accounts payable balance of $0.7 million as of March 31, 2010 and December 31, 2009.




Related to its investments in unconsolidated subsidiaries, during the three months ended March 31, 2010 and 2009, the Partnership recorded income of $0.2 million and $0.5 million, respectively, of which there was no outstanding accounts receivable balances as of March 31, 2010 and December 31, 2009.




During the three months ended March 31, 2010, the Partnership incurred approximately $0.7 million for services performed by Stanolind Field Services (“SFS”), which is an entity controlled by Natural Gas Partners (“NGP”).  As of March 31, 2010, there were no outstanding accounts payable balances.





As of March 31, 2010 and December 31, 2009, Eagle Rock Energy G&P, LLC had $12.9 million of outstanding checks paid on behalf of the Partnership. This amount was recorded as Due to Affiliate on the Partnership’s balance sheet in current liabilities. As the checks are drawn against Eagle Rock Energy G&P, LLC’s cash accounts, the Partnership reimburses Eagle Rock Energy G&P, LLC.





During 2009, the Partnership leased office space from Montierra Minerals & Production, L.P. (“Montierra”), which is owned by NGP and certain members of the Partnership’s senior management, including the Chief Executive Officer.  During the three months ended March 31, 2009, the Partnership made rental payments of less than $0.1 million.  In addition, the Partnership was reimbursed by Montierra for services performed by its employees on behalf of Montierra of less than $0.1 million for both the three months ended March 31, 2009.  The Partnership did not receive or provide any services to Montierra during the three months ended March 31, 2010.  As of March 31, 2010 and December 31, 2009, no amounts were due to or from Montierra.




As of March 31, 2010 and December 31, 2009, the Partnership had an outstanding receivable balance of $0.7 million due from an affiliate of NGP.




Recapitalization and Related Transactions




On December 21, 2009, the Partnership announced that it, through certain of its affiliates, had entered into definitive agreements with affiliates of NGP and Black Stone Minerals Company, L.P. (“Black Stone”) to improve its liquidity and simplify its capital structure.  The definitive agreements include:  (i) a Securities Purchase and Global Transaction Agreement, entered into between Eagle Rock Energy and NGP, including Eagle Rock Energy’s general partner entities controlled by NGP, and (ii) a Purchase and Sale Agreement (the “Minerals Business Sale Agreement”), entered into between Eagle Rock Energy and Black Stone for the sale of Eagle Rock Energy’s Minerals Business.  The Securities Purchase and Global Transaction Agreement was amended on January 12, 2010 to allow for greater flexibility in the payment of the contemplated transaction fee to Holdings, which is controlled by NGP (the Partnership refers to the amended Securities Purchase and Global Transaction Agreement as the “Global Transaction Agreement”).




The Global Transaction Agreement and Minerals Business Sale Agreement include the following key provisions, which the Partnership refers to collectively as the “Recapitalization and Related Transactions.”




•
An option in favor of the Partnership, exercisable until December 31, 2012 by the issuance of 1,000,000 newly-issued common units, to capture the value of its controlling interest through (i) acquiring the Partnership’s general partner, and such general partner’s general partner, and thereby acquiring the 844,551 general partner units outstanding, and (ii) reconstituting its board of directors to allow its common unitholders to elect the majority of its directors (the “GP Acquisition Option”);




•
The sale of the Partnership’s Minerals Business to Black Stone for total consideration of $174.5 million in cash, subject to customary adjustments;




•
The simplification of the Partnership’s capital structure through the contribution, and resulting cancellation, of the existing incentive distribution rights and the existing 20.7 million subordinated units currently held by Holdings;


•
A rights offering in which Holdings and NGP will fully participate with respect to 9.5 million common and general partner units owned or controlled by NGP as well as with respect to common units it receives as payment of the transaction fee, if any; and


•
For a period of up to five months following unitholder approval of the amended Global Transaction Agreement, NGP’s commitment to back-stop (primarily through Holdings) up to $41.6 million, at a price of $3.10 per unit, an Eagle Rock Energy equity offering to be undertaken at the sole option of the Partnership’s Conflicts Committee.




In exchange for NGP’s and Holdings’ contributions and commitments under the Global Transaction Agreement, Eagle Rock will pay Holdings, subject to a successful unitholder vote, a transaction fee of $29 million in newly-issued common units.  The units were valued at $6.0101 per unit, based on 90% of the volume-adjusted trailing 10-day average of the trading price of Eagle Rock’s common units as of April 24, 2010, resulting in a total of approximately 4.8 million units to be paid to Holdings upon completion of the Minerals Business sale.





Completion of the Recapitalization and Related Transactions is expected to occur in the second quarter of 2010, subject to customary closing conditions including approval of the Global Transaction Agreement and the transactions contemplated therein, including certain partnership agreement amendments, by a majority of the common units held by non-affiliates of NGP. The Global Transaction Agreement is conditioned upon the consummation of the transactions contemplated in the Minerals Business Sale Agreement, which is conditioned on unitholder approval of the Global Transaction Agreement and certain partnership agreement amendments.





The Partnership will hold a special meeting of its common unitholders on May 14, 2010 for unitholders of record as of the close of business on March 29, 2010 to vote on certain of the Recapitalization and Related Transactions.




See Note 12 related to lawsuit alleging certain claims related to the Recapitalization and Related Transactions.





See Note 7 for a discussion of an amendment to our revolving credit facility related to the Recapitalization and Related Transactions.




NOTE 10. FAIR VALUE OF FINANCIAL INSTRUMENTS




Effective January 1, 2008, the Partnership adopted authoritative guidance which, among other things, requires enhanced disclosures about assets and liabilities carried at fair value.




Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Partnership utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk inherent in the inputs to the valuation technique. The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).




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




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




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




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





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 Table of Contents







As of March 31, 2010, the Partnership has recorded its interest rate swaps and commodity derivative instruments (see Note 11), which includes crude, natural gas and natural gas liquids (“NGLs”) at fair value. The Partnership has classified the inputs to measure the fair value of its interest rate swaps, crude derivatives and natural gas derivatives as Level 2. Because the NGL market is considered to be less liquid and thinly traded, the Partnership has classified the inputs related to its NGL derivatives as Level 3.





The Partnership values its Level 2 and Level 3 derivatives using forward curves, volatility curves, volatility skew parameters, interest rate curves and model parameters.




The Partnership did not have any transfers of assets and liabilities between Level 1 and Level 2 of the fair value measurement hierarchy during the three months ended March 31, 2010.  If transfers were to occur, the Partnership would recognize such transfers at the beginning of the reporting period.




The following tables disclose the fair value of the Partnership’s derivative instruments as of March 31, 2010 and December 31, 2009:





As of March 31, 2010Level 1


Level 2


Level 3


Total($ in thousands)Assets:Crude oil derivatives

$
-


$
(994
)

$
-


$
(994
)Natural gas derivatives


-



16,730



-



16,730NGL derivatives


-



-



(1,821
)


(1,821
)Total

$
-


$
15,736


$
(1,821
)

$
13,915Liabilities:Crude oil derivatives

$
-


$
(48,098
)

$
-


$
(48,098
)Natural gas derivatives


-



2,437



-



2,437NGL derivatives


-



-



(5,837
)


(5,837
)Interest rate swaps


-



(32,237
)


-



(32,237
)Total

$
-


$
(77,898
)

$
(5,837
)

$
(83,735
)As of December 31, 2009Level 1


Level 2


Level 3


Total($ in thousands)Assets:Crude oil derivatives

$
-


$
3


$
-


$
3Natural gas derivatives


-



5,286



-



5,286Interest rate swaps


-



600



-



600Total

$
-


$
5,889


$
-


$
5,889Liabilities:Crude oil derivatives

$
-


$
(45,039
)

$
-


$
(45,039
)Natural gas derivatives


-



3,475



-



3,475NGL derivatives


-



-



(14,784
)


(14,784
)Interest rate swaps


-



(28,017
)


-



(28,017
)Total

$
-


$
(69,581
)

$
(14,784
)

$
(84,365
)





As of March 31, 2010, risk management current and long-term assets in the unaudited condensed consolidated balance sheet include put premium and other derivative costs, net of amortization, of $1.3 million.





The following table sets forth a reconciliation of changes in the fair value of the NGL derivatives classified as Level 3 in the fair value hierarchy during the three months ended March 31, 2010 and 2009 (in thousands):




Three MonthsEnded March 31,2010


2009Net asset (liability) balances as of January 1

$
(14,784
)

$
14,016Settlements


4,129



(3,378
)Total gains (losses) realized and unrealized


2,997



809Net liability balances as of March 31

$
(7,658
)

$
11,447





Realized and unrealized losses related to the interest rate derivatives are recorded as part of interest rate risk management gains and losses in the unaudited condensed consolidated statements of operations.  Realized and unrealized gains and losses and the amortization of put premiums and other derivative costs related to the Partnership’s commodity derivatives are recorded as a component of revenue in the unaudited condensed consolidated statements of operations.





The Partnership recognized gains of $2.7 million and $1.2 million in the three months ended March 31, 2010 and 2009, respectively, that are attributable to the change in unrealized gains or losses related to those assets and liabilities still held at March 31, 2010 which are included in the unrealized commodity gains (losses).





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.





The Partnership believes that the fair value of its revolving credit facility does not approximate its carrying value as of March 31, 2010 and December 31, 2009 because the applicable floating rate margin on the revolving credit facility was a below-market rate. The fair value of the revolving credit facility has been estimated based on similar transactions that occurred during the twelve months ended December 31, 2009 and the three months ended March 31, 2010. The Partnership estimates the fair value of the borrowings under its revolving credit facility as of March 31, 2010 was $699.7 million versus a carrying value of $737.4 million.  The Partnership estimated the fair value of the borrowings under its revolving credit facility as of December 31, 2009 was $713.2 million versus a carrying value of $754.4 million.




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 Table of Contents





NOTE 11. RISK MANAGEMENT ACTIVITIES





Interest Rate Derivative Instruments




To mitigate its interest rate risk, the Partnership entered into various interest rate swaps. These swaps convert a portion of the variable-rate interest obligations into fixed-rate interest obligations. The purpose of entering into this swap is to eliminate interest rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments through the end of 2012.  The Partnership has not designated any of its interest rate swaps as hedges and as a result is marking these derivative contracts to fair value with changes in fair values of the interest rate derivative instruments recorded as an adjustment to the mark-to-market gains (losses) on risk management transactions within other income (expense).





On March 30, 2009, the Partnership amended all of its existing interest rate swaps to change the interest rate the Partnership received from three month LIBOR to one month LIBOR through January 9, 2011.  During this time period, the fixed rate to be paid by the Partnership was reduced, on average, by 20 basis points.  After January 9, 2011, the interest rate to be received by the Partnership will change back to three month LIBOR and the fixed rate the Partnership pays will revert back to the original rate through the end of swap maturities in 2012.





The table below summarizes the terms, notional amounts and rates to be paid and the fair values of the various interest swaps as of March 31, 2010:





Effective Date

Expiration Date

Notational Amount

Fixed Rate (a)12/31/2008

12/31/2012

$150,000,000

2.360 % / 2.560%9/30/2008

12/31/2012

150,000,000

4.105 % / 4.295%10/3/2008

12/31/2012

300,000,000

3.895 % / 4.095%








(a)
First amount is the rate the Partnership pays through January 9, 2011 and the second amount is the interest rate the Partnership pays from January 10, 2011 through December 31, 2012.





The Partnership’s interest rate derivative counterparties include Wells Fargo Bank N.A. / Wachovia Bank N.A and The Royal Bank of Scotland plc.





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 objective and comply with the covenants of its revolving credit facility.  In order to manage the risks associated with the future prices of crude oil, natural gas and NGLs, the Partnership engages in non-speculative risk management activities that take the form of commodity derivative instruments.  The Partnership has determined that it is necessary to hedge a substantial portion of its expected production in order to meaningfully reduce its future cash flow volatility.  The Partnership generally limits its hedging levels to 80% of expected future production.   While hedging at this level of production does not eliminate all of the volatility in the Partnership’s cash flows, it allows the Partnership to mitigate the risk of situations where a modest loss of production would put it in an over-hedged position.  The Partnership may hedge for periods of time above the 80% of expected future production levels where it deems it prudent to reduce extreme future price volatility.  However, hedging to that level requires approval of the Board of Directors, which the Partnership has obtained for its 2009 and 2010 hedging activity.  At times, the Partnership’s strategy may involve entering into hedges with strike prices above current future prices or resetting existing hedges to higher price levels in order to meet its cash flow objectives or to stay in compliance with its revolving credit facility.  In addition, the Partnership may also terminate or unwind hedges or portions of hedges when the expected future volumes do not support the level of hedges.  Expected future production for its Upstream and Minerals Businesses is derived from the proved reserves, adjusted for price-dependent expenses and revenue deductions.  For the Midstream Business, expected future production is based on the expected production from wells currently flowing to the Partnership’s processing plants, plus additional volumes the Partnership expects to receive from future drilling activity by its producer customer base.  The Partnership’s expectations for its Midstream Business volumes associated with future drilling are based on information it receives from its producer customer base and historical observations. The Partnership applies the appropriate contract terms to these projections to determine its expected future equity share of the commodities.




The Partnership uses put options, costless collars and fixed-price swaps to achieve its hedging objectives, and often hedges its expected future volumes of one commodity with derivatives of the same commodity.  In some cases, however, the Partnership believes it is better to hedge future changes in the price of one commodity with a derivative of another commodity, which it refers to as “cross-commodity” hedging.  The Partnership will often hedge the changes in future NGL prices (propane and heavier) using crude oil hedges because NGL prices have been highly correlated to crude oil prices and hedging NGLs directly is usually less attractive due to the relative illiquidity in the NGL forward market.  The Partnership will also use natural gas hedges to hedge a portion of its expected future ethane production because forward prices for ethane are often heavily discounted from its current prices.  Also, natural gas prices provide support for ethane prices because in many processing plants ethane can be recombined with the residue gas stream and sold as natural gas.  When the Partnership uses cross-commodity hedging, it will convert the expected volumes of the underlying commodity to equivalent volumes of the hedged commodity.  In the case of NGLs hedged with crude oil derivatives, these conversions are based on the linear regression of the prices of the two commodities observed during the previous 36 months and management’s judgment regarding future price relationships of the commodities.   In the case where ethane is hedged with natural gas derivatives, the conversion is based on the thermal content of ethane.




The Partnership has a risk management policy which allows management to execute crude oil, natural gas and NGL hedging instruments in order to reduce exposure to substantial adverse changes in the prices of these commodities. The Partnership continually monitors and ensures compliance with this risk management policy through senior level executives in our operations, finance and legal departments.







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 Table of Contents





The Partnership has not designated any of its commodity derivative instruments as hedges and therefore is marking these derivative contracts to fair value.  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.




The Partnership’s commodity derivative counterparties include BNP Paribas, Wachovia Bank N.A, Comerica Bank, Barclays Bank PLC, Bank of Nova Scotia, The Royal Bank of Scotland plc, Bank of America N.A., J Aron and Company (an affiliate of Goldman Sachs), BBVA Compass Bank and Credit Suisse Energy LLC (an affiliate of Credit Suisse Group AG).




The following table, as of March 31, 2010, sets forth certain information regarding the Partnership’s commodity derivatives that will mature during the year ended December 31, 2010 (excluding transactions and volumes that settled or were unwound during the three months ended March 31, 2010):




Underlying

Period

Notional Volumes (units)

Type

Floor Strike Price ($/unit)

Cap Strike Price ($/unit)Natural Gas:NYMEX Henry Hub

Apr-Dec 2010

990,000  mmbtu

Costless Collar

$7.70

$9.10NYMEX Henry Hub

Apr-Dec 2010

1,125,000  mmbtu

Swap

6.65NYMEX Henry Hub

Apr-Dec 2010

1,530,000  mmbtu

Swap

6.57Crude Oil:NYMEX WTI

Apr-Dec 2010

45,000  bbls

Costless Collar

50.00

67.50NYMEX WTI

Apr-Dec 2010

81,000  bbls

Costless Collar

90.00

99.80NYMEX WTI

Apr-Dec 2010

45,000  bbls

Put

100.00NYMEX WTI

Apr-Dec 2010

54,000  bbls

Put

90.00NYMEX WTI

Apr-Dec 2010

27,000  bbls

Swap

78.35NYMEX WTI

Apr-Dec 2010

225,000  bbls

Swap

70.00NYMEX WTI

Apr-Dec 2010

360,000  bbls

Swap

51.40NYMEX WTI

Apr-Dec 2010

405,000  bbls

Swap

53.55Natural Gas Liquids:OPIS Ethane Mt Belv non TET

Apr-Dec 2010

3,402,000  gallons

Costless Collar

0.43

0.53OPIS Ethane Mt Belv non TET

Apr-Dec 2010

3,402,000  gallons

Swap

0.58OPIS IsoButane Mt Belv non TET

Apr-Dec 2010

1,890,000  gallons

Costless Collar

0.82

1.02OPIS IsoButane Mt Belv non TET

Apr-Dec 2010

3,137,400  gallons

Swap

1.4045OPIS NButane Mt Belv non TET

Apr-Dec 2010

4,158,000  gallons

Costless Collar

0.82

1.02OPIS NButane Mt Belv non TET

Apr-Dec 2010

6,350,400  gallons

Swap

1.3745OPIS Propane Mt Belv non TET

Apr-Dec 2010

3,780,000  gallons

Costless Collar

0.705

0.81OPIS Propane Mt Belv non TET

Apr-Dec 2010

3,780,000  gallons

Swap

0.755OPIS Propane Mt Belv non TET

Apr-Dec 2010

13,305,600  gallons

Swap

1.0915OPIS Natural Gasoline Mt Belv non TET

Apr-Dec 2010

1,663,200  gallons

Swap

1.6562




During the three months ended March 31, 2010, the Partnership entered into a 12,000 barrels per month WTI costless collar with a floor strike price at $75.00 per barrel and a cap strike price of $89.85 per barrel for its 2011 calendar year.




The following table, as of March 31, 2010, sets forth certain information regarding the Partnership’s commodity derivatives that will mature during the year ended December 31, 2011:




Underlying

Period

Notional Volumes (units)

Type

Floor Strike Price ($/unit)

Cap Strike Price ($/unit)Natural Gas:NYMEX Henry Hub

Jan-Dec 2011

1,200,000  mmbtu

Costless Collar

$7.50

$8.85NYMEX Henry Hub

Jan-Dec 2011

720,000  mmbtu

Swap

7.09NYMEX Henry Hub

Jan-Dec 2011

2,280,000  mmbtu

Swap

6.14Crude Oil:NYMEX WTI

Jan-Dec 2011

139,152  bbls

Costless Collar

75.00

85.70NYMEX WTI

Jan-Dec 2011

360,000  bbls

Costless Collar

80.00

92.40NYMEX WTI

Jan-Dec 2011

144,000  bbls

Costless Collar

75.00

89.85NYMEX WTI

Jan-Dec 2011

125,256  bbls

Swap

80.00NYMEX WTI

Jan-Dec 2011

120,000  bbls

Swap

65.10NYMEX WTI

Jan-Dec 2011

240,000  bbls

Swap

75.00NYMEX WTI

Jan-Dec 2011

240,000  bbls

Swap

80.05NYMEX WTI

Jan-Dec 2011

360,000  bbls

Swap

65.60




During the three months ended March 31, 2010, the Partnership entered into a 16,000 barrels per month NYMEX WTI costless collar with a floor strike price at $75.00 per barrel and a cap strike price of $94.75 per barrel for its 2012 calendar year.




The following table, as of March 31, 2010, sets forth certain information regarding the Partnership’s commodity derivatives that will mature during the year ending December 31, 2012:




Underlying

Period

Notional Volumes (units)

Type

Floor Strike Price ($/unit)

Cap Strike Price ($/unit)Natural Gas:NYMEX Henry Hub

Jan-Dec 2012

1,080,000  mmbtu

Costless Collar

$7.35

$8.65NYMEX Henry Hub

Jan-Dec 2012

3,120,000  mmbtu

Swap

6.77Crude Oil:NYMEX WTI

Jan-Dec 2012

135,576  bbls

Costless Collar

75.30

86.30NYMEX WTI

Jan-Dec 2012

360,000  bbls

Costless Collar

80.00

98.50NYMEX WTI

Jan-Dec 2012

192,000  bbls

Costless Collar

75.00

94.75NYMEX WTI

Jan-Dec 2012

108,468  bbls

Swap

80.30NYMEX WTI

Jan-Dec 2012

240,000  bbls

Swap

68.30NYMEX WTI

Jan-Dec 2012

240,000  bbls

Swap

76.50NYMEX WTI

Jan-Dec 2012

240,000  bbls

Swap

82.02




On April 9, 2010, the Partnership entered into a swap for 20,000 barrels per month of NYMEX WTI crude oil for the twelve months ending December 31, 2010.  The swap price for the transaction is $90.20 per barrel.  On April 19, 2010, the Partnership entered into a swap for 60,000 barrels per month of NYMEX WTI crude oil for the twelve months ending December 31, 2013.  The swap price for the transaction is $89.85 per barrel.





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Fair Value of Interest Rate and Commodity Derivatives




Fair values of interest rate and commodity derivative instruments not designated as hedging instruments in the unaudited condensed consolidated balance sheet as of March 31, 2010 and December 31, 2009:




As of March 31, 2010Derivative Assets

Derivative LiabilitiesBalance Sheet Location

Fair Value

Balance Sheet Location

Fair Value($ in thousands)Interest rate derivatives – assets


$
-



$
-Interest rate derivatives – liabilities



-

Current liabilities


(18,115
)Interest rate derivatives – liabilities



-

Long-term liabilities


(14,122
)Commodity derivatives – assets
Current assets


9,508

Current liabilities


3,005Commodity derivatives – assets
Long-term assets


10,107




-Commodity derivatives – liabilities
Current assets


(3,159
)
Current liabilities


(36,830
)Commodity derivatives – liabilities
Long-term assets


(2,541
)
Long-term liabilities


(17,673
)Total derivatives


$
13,915



$
(83,735
)As of December 31, 2009Derivative Assets

Derivative LiabilitiesBalance Sheet Location

Fair Value

Balance Sheet Location

Fair Value($ in thousands)Interest rate derivatives – assets
Long-term assets

$
600



$
-Interest rate derivatives – liabilities



-

Current liabilities


(16,988
)Interest rate derivatives – liabilities



-

Long-term liabilities


(11,029
)Commodity derivatives – assets
Current assets


3,494

Current liabilities


9,842Commodity derivatives – assets
Long-term assets


2,830

Long-term liabilities


1,684Commodity derivatives – liabilities
Current assets


(1,015
)
Current liabilities


(44,504
)Commodity derivatives – liabilities
Long-term assets


(20
)
Long-term liabilities


(23,370
)Total derivatives


$
5,889



$
(84,365
)




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:




Location of Gain or (Loss) Recognized in Income on Derivatives

Amount of Gain or (Loss) Recognized in Income on DerivativesThree Months Ended March 31,2010


2009($ in thousands)Interest rate risk management losses

$
(9,712
)

$
(383
)Commodity risk management gains


10,795



26,256Total

$
1,083


$
25,873




The Partnership’s hedge counterparties are participants in its credit agreement, and the collateral for the outstanding borrowings under its credit agreement is used as collateral for its hedges.  The Partnership does not have rights to collateral from its counterparties, nor does the Partnership have rights of offset against borrowings under its credit agreement.





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NOTE 12. COMMITMENTS AND CONTINGENT LIABILITIES




Litigation—The Partnership is subject to lawsuits which arise from time to time in the ordinary course of business, such as the interpretation and application of contractual terms related to the calculation of payment for liquids and natural gas proceeds. The Partnership’s accruals were approximately $0.2 million and $0.1 million as of March 31, 2010 and December 31, 2009, respectively, related to these matters. The Partnership has been indemnified up to a certain dollar amount for certain lawsuits that were assumed as part of prior acquisitions. If there ultimately is a finding against the Partnership in the indemnified cases, the Partnership would expect to make a claim against the indemnification up to the limits of the indemnification. For these indemnified lawsuits, the Partnership has not established any accruals because the Partnership considers remote the likelihood of these lawsuits being successful in amounts in excess of the indemnification limits. These matters are not expected to have a material adverse effect on our financial position, results of operations or cash flows.





On February 9, 2010 a lawsuit, alleging certain claims related to the Recapitalization and Related Transactions (see Note 9), was filed on behalf of one of the Partnership’s public unitholders in the Court of Chancery of the State of Delaware naming the Partnership, its general partner, certain affiliates of its general partner, including the general partner of its general partner, and each member of the Partnership’s Board of Directors as defendants.  The complaint alleges a breach by defendants of their fiduciary duties to the Partnership and the public unitholders and seeks to enjoin the Recapitalization and Related Transactions.  The Partnership believes the allegations claimed in the lawsuit are without merit.  On March 11, 2010, in an effort to minimize the further cost, expense, burden and distraction of any litigation relating to the lawsuit, the parties to the lawsuit entered into a Memorandum of Understanding regarding the terms of a potential settlement of the lawsuit.  If the settlement is consummated it, among other things, would resolve the allegations by the plaintiff against the defendants in connection with the Recapitalization and Related Transactions and would provide a release and settlement by a proposed class of the Partnership common unitholders during the period from September 17, 2009 through and including the date of the closing of the transactions of all claims against the defendants as they relate to the Recapitalization and Related Transactions.  As of March 31, 2010, the Partnership’s accrual related to this matter was $0.8 million.  The Partnership has a receivable of approximately $0.5 million established against this accrual for amounts the Partnership expects to recover under its Directors and Officers insurance policies.In the event that the settlement is not consummated, the Partnership intends to vigorously defend against the lawsuit.




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





All coverages are subject to industry accepted policy terms, conditions, limits and deductibles comparable to that obtained by other energy companies with similar operations. The cost of insurance for the energy industry continued to fluctuate over the past year, reflecting the changing conditions in the insurance markets.





Regulatory Compliance—In the ordinary course of business, the Partnership is subject to various laws and regulations. In the opinion of management, the Partnership is in material compliance with existing laws and regulations.




Environmental—The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, the Partnership must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership’s combined results of operations, financial position or cash flows. At March 31, 2010 and December 31, 2009, the Partnership had accrued approximately $4.1 million and $4.4 million, respectively, for environmental matters.




The Partnership has voluntarily undertaken a self-audit of its compliance with air quality standards, including permitting in the Texas Panhandle Segment as well as a majority of its other Midstream Business locations and some of its Upstream Business locations in Texas. This audit has been performed pursuant to the Texas Environmental, Health and Safety Audit Privilege Act, as amended. The Partnership has completed the disclosures to the Texas Commission on Environmental Quality (“TCEQ”), and the Partnership is addressing in due course the deficiencies that it disclosed therein.  The Partnership does not foresee at this time any impediment to the timely corrective efforts identified as a result of these audits.





Since January 1, 2010, the Partnership has received additional Notices of Enforcement (“NOEs”) and Notices of Violation (“NOVs”) from the TCEQ related to air compliance matters and expects to receive additional NOEs or NOVs from the TCEQ from time to time throughout 2010.  Though the TCEQ has the discretion to adjust penalties and settlements upwards based on a compliance history containing multiple, successive NOEs, the Partnership does not expect that the resolution of any existing NOE or any future similar NOE will vary significantly from the administrative penalties and agreed settlements experienced by it to date.





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





The retained revenue interests affect the Partnership’s interest at the Big Escambia Creek, Flomaton and Fanny Church fields in Escambia County, Alabama.  With respect to the Partnership’s Flomaton and Fanny Church fields, the Partnership is currently making payments in satisfaction of the retained revenue interests.   With respect to the Partnership’s Big Escambia Creek field, these payments began in 2010 and continue through the end of 2019.





Other Commitments—The Partnership utilizes operating leases for its corporate office, certain rights-of way, facility locations and vehicles. Rental expense, including leases with no continuing commitment, amounted to approximately $1.8 million and $2.3 million for the three months ended March 31, 2010 and March 31, 2009, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term.





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 Table of Contents




NOTE 13. SEGMENTS




Based on the Partnership’s approach to managing its assets, the Partnership believes its operations consist of four geographic segments in its Midstream Business, one upstream segment that is its Upstream Business, one minerals segment that is its Minerals Business and one functional (corporate) segment:




(i)
Midstream—Texas Panhandle Segment:




gathering, compressing, processing and treating natural gas and marketing of natural gas, NGLs and condensate in the Texas Panhandle;





(ii)
Midstream—South Texas Segment:




gathering, compressing, processing and treating natural gas and marketing of natural gas, NGLs and condensate in South Texas and West Texas;




(iii)
Midstream—East Texas/Louisiana Segment:




gathering, compressing, processing, treating and transporting natural gas and marketing of natural gas, NGLs and condensate and related NGL transportation in East Texas and Louisiana;




(iv)
Midstream—Gulf of Mexico Segment:




gathering and processing of natural gas and fractionating, transporting and marketing of NGLs in South Louisiana, Gulf of Mexico and inland waters of Texas;




(v)
Upstream Segment:





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




(vi)
Minerals Segment:





fee minerals and royalties, lease bonus and rental income either through direct ownership or through investment in other partnerships; and




(vii)
Corporate Segment:




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





17
 Table of Contents





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







Midstream Business

Texas Panhandle


South Texas



East Texas/ Louisiana


Gulf of Mexico



Total MidstreamThree Months Ended March 31, 2010

Segment


Segment



Segment


Segment



Business($ in thousands)Sales to external customers

$
93,675


$
26,583



$
60,363


$
8,859



$
189,480Cost of natural gas and natural gas liquids


66,970



23,638




46,205



7,465




144,278Operating costs and other expenses


8,098



853




4,209



505




13,665Depreciation, depletion, and amortization


11,590



1,487




4,428



1,603




19,108Operating income (loss) from continuing operations

$
7,017


$
605



$
5,521


$
(714
)


$
12,429Capital Expenditures

$
2,204


$
(24
)


$
1,541


$
13



$
3,734Segment Assets

$
530,462


$
92,445



$
285,194


$
83,952



$
992,053Total Segments

Total Midstream


Upstream



Minerals


Corporate



TotalThree Months Ended March 31, 2010

Business


Segment



Segment


Segment



Segments($ in thousands)Sales to external customers

$
189,480


$
22,685



$
5,649


$
10,795

(a)

$
228,609Cost of natural gas and natural gas liquids


144,278



-




-



-




144,278Operating costs and other expenses


13,665



9,107

(b)


462



13,088




36,322Depreciation, depletion and amortization


19,108



8,565




1,409



353




29,435Operating income (loss) from continuing operations

$
12,429


$
5,013



$
3,778


$
(2,646
)


$
18,574Capital Expenditures

$
3,734


$
4,979



$
-


$
634



$
9,347Segment Assets

$
992,053


$
359,356



$
135,277


$
32,535



$
1,519,221Midstream Business

Texas Panhandle


South Texas



East Texas/ Louisiana


Gulf of Mexico



Total MidstreamThree Months Ended March 31, 2009

Segment


Segment



Segment


Segment



Business($ in thousands)Sales to external customers

$
65,763


$
33,348



$
54,660


$
6,310



$
160,081Cost of natural gas and natural gas liquids


51,947



31,069




45,009



5,192




133,217Operating costs and other expenses


8,145



1,061




4,552



418




14,176Depreciation, depletion, and amortization


11,096



1,424




4,771



1,488




18,779Operating income (loss) from continuing operations

$
(5,425
)

$
(206
)


$
328


$
(788
)


$
(6,091
)Capital Expenditures

$
3,111


$
(60
)


$
9,096


$
141



$
12,288Segment Assets

$
555,862


$
76,791



$
329,688


$
90,143



$
1,052,484Total Segments

Total Midstream


Upstream



Minerals


Corporate



TotalThree Months Ended March 31, 2009

Business


Segment



Segment


Segment



Segments($ in thousands)Sales to external customers

$
160,081


$
10,118



$
3,239


$
26,256

(a)

$
199,694Cost of natural gas and natural gas liquids


133,217



-




-



-




133,217Operating costs and other expenses


14,176



6,972

(b)


471



12,538




34,157Depreciation, depletion, amortization and impairment


18,779



9,638




1,675



213




30,305Operating income (loss) from continuing operations

$
(6,091
)

$
(6,492
)


$
1,093


$
13,505



$
2,015Capital Expenditures

$
12,288


$
1,592



$
-


$
895



$
14,775Segment Assets

$
1,052,484


$
387,938



$
140,312


$
149,371



$
1,730,105





(a)
Represents results of the Partnership’s derivative activities.


(b)
Includes sulfur disposal costs of $(0.2) million and $0.4 million for the three months ended March 31, 2010 and 2009, respectively.








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 Table of Contents





NOTE 14. INCOME TAXES




Provision for Income Taxes –The Partnership’s provision for income taxes relates to (i) state taxes for the Partnership and (ii) federal taxes for Eagle Rock Energy Acquisition Co., Inc. (acquiring entity of certain entities acquired in the Redman acquisition) and Eagle Rock Energy Acquisition Co. II, Inc. (acquiring entity of certain entities acquired in the Stanolind Acquisition) and their wholly-owned corporations, Eagle Rock Upstream Development Company, Inc. (successor entity to certain entities acquired in the Redman acquisition) and Eagle Rock Upstream Development Company II, Inc. (successor entity to certain entities acquired in the Stanolind acquisition), which are subject to federal income taxes (the “C Corporations”).




As a result of the taxable income from the underlying partnerships owned by the C Corporations described above, net operating loss carryforwards and statutory depletion carryforwards of $1.0 million and $0.9 million were used during the three months ended March 31, 2010 and 2009, respectively, which resulted in a release of the valuation allowance established for the net operating losses as of December 31, 2009.




Effective Rate -The effective rate for the three period ended March 31, 2010 was 16.1% compared to 51.7% for the three month period ended March 31, 2009.  Due to the fact that the effective rate is a ratio of total tax expense compared to pre-tax book income, the change is due primarily to the fact that the Partnership was in a loss position during the three months ended March 31, 2009 versus income in the three months ended March 31, 2010.




Deferred Taxes -As of March 31, 2010, the net deferred tax liability was $39.0 million compared to $38.7 million as of December 31, 2009 and is primarily attributable to temporary book and tax basis differences of the entities subject to federal income taxes discussed above.  These temporary differences result in a net deferred tax liability which will be reduced as allocation of depreciation and depletion in proportion to the assets contributed brings the book and tax basis closer together over time.  This deferred tax liability was recognized in conjunction with the purchase accounting for the Stanolind and Redman acquisitions.




Texas Franchise Tax -On May 18, 2006, the State of Texas enacted revisions to the existing state franchise tax. In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax, including previously non-taxable entities such as limited partnerships and limited liability corporations. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits.  The Company makes appropriate accruals for this tax during the reporting period.




Accounting for Uncertainty in Income Taxes -The Partnership adopted authoritative guidance related to accounting for uncertainty in income taxes on January 1, 2007.  The Partnership has taken a position which is deemed to be “more likely than not” to be upheld upon review, if any, with respect to the deductibility of certain costs for the purpose of its franchise tax liability on a state franchise return.   The Partnership has recorded a provision of the portion of this tax liability equal to the probability of recognition. The Partnership has not accrued interest and penalties as the amounts are estimated to be de minimis. The amount stated below relates to the tax return filed for 2008 which is still open under current statute. A reconciliation of the beginning and ending amount of the unrecognized tax liabilities is as follows (in thousands):




Balance as of December 31, 2009

$
(267
)Increases related to prior year tax positions


-Increases related to current year tax positions


-Balance as of March 31, 2010

$
(267
)












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 Table of Contents





NOTE 15. EQUITY-BASED COMPENSATION




Eagle Rock Energy G&P, LLC, the general partner of the general partner for Eagle Rock Energy Partners, L.P., has a long-term incentive plan (“LTIP”), as amended, for its employees, directors and consultants who provide services to the Partnership and its subsidiaries and affiliates.  The LTIP covers an aggregate of 2,000,000 common units to be granted either as options, restricted units or phantom units.   As to outstanding restricted units, distributions associated with the restricted units will be distributed directly to the awardees. The Partnership has historically only issued restricted units under the LTIP.  No options or phantom units have been issued to date.




A summary of the LTIP restricted common units’ activity for the three months ended March 31, 2010, is provided below:




Number of Restricted Units


Weighted Average Fair ValueNonvested at December 31, 2009


1,371,019


$
9.35Granted


27,500



5.74Forfeitures


(18,558
)


17.80Nonvested at March 31, 2010


1,379,961



9.17





For the three months ended March 31, 2010 and 2009, non-cash compensation expense of approximately $1.8 million and $2.2 million, respectively, was recorded related to the granted restricted units under the LTIP.




As of March 31, 2010, unrecognized compensation costs related to the outstanding restricted units under the LTIP totaled approximately $7.8 million. The remaining expense is to be recognized over a weighted average of 1.83 years.




In addition to equity awards under the LTIP involving units of the Partnership, Eagle Rock Holdings, L.P. (“Holdings”), which is controlled by NGP, in the past has from time to time granted equity in Holdings to certain employees working on behalf of the Partnership, some of which are named executive officers.  During the three month period ended March 31, 2009, Holdings granted 160,000 “Tier I” incentive interests to one Eagle Rock Energy employee.  The Partnership recorded a portion of the value of the incentive units as compensation expense in the Partnership’s condensed consolidated financial statements.  This allocation is based on management’s estimation of the total value of the incentive unit grant and of the grantee’s portion of time dedicated to the Partnership.  The Partnership recorded non-cash compensation expense of $0.4 million based on management’s estimates related to the Tier I incentive unit grants made by Holdings during the three months ended March 31, 2009.  No Tier I incentive unit grants were made by Holdings during the three months ended March 31, 2010.




NOTE 16.  EARNINGS PER UNIT




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




As of March 31, 2010 and 2009, the Partnership has unvested restricted common units outstanding.  These units will be considered in the diluted weighted average common unit outstanding number in periods of net income.  In periods of net losses, these units are excluded from the diluted weighted average common unit outstanding number.




For the three months ended March 31, 2010, the Partnership determined that it is more dilutive to apply the two-class method versus the treasury stock method in calculating dilutive earnings per unit.  Thus, the unvested restricted common units are included in the computation of the diluted weighted average common unit outstanding calculation, but the denominator in the computation of diluted earnings per unit only includes the basic weighted average common units outstanding.





Under the Partnership’s partnership agreement, for any quarterly period, incentive distribution rights (“IDRs”) participate in net income only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed earnings or losses.  Accordingly, undistributed net income is assumed to be allocated to the other ownership interests on a pro-rata basis.  During the three months ended March 31, 2010 and 2009, the Partnership did not declare a quarterly distribution for the IDRs.








20
 Table of Contents


The restricted common units granted under the LTIP, as discussed in Note 15, contain non-forfeitable rights to the distributions declared by the Partnership and therefore meet the definition of participating securities.  Participating securities are required to be included in the computation of earnings per unit computation pursuant to the two-class method.





The following table presents the Partnership’s basic and diluted weighted average units outstanding for the periods indicated (in thousands):




Three Months EndedMarch 31,2010


2009Basic weighted average units outstanding:Common units


54,203



53,044Subordinated units


20,691



20,691General partner units


845



845Diluted weighted average units outstanding:Common units


54,420



53,044Subordinated units


20,691



20,691General partner units


845



845


The following table presents the Partnership’s basic and diluted income per unit for the three months ended March 31, 2010:




Total


Common Units


Restricted common Units


Subordinated Units


General Partner Units($ in thousands, except for per unit amounts)Income from continuing operations

$
3,953Distributions declared


1,405


$
1,355


$
29


$
-


$
21Assumed income from continuing operations after distribution to be allocated


2,548



1,790



46



684



28Assumed allocation of income from continuing operations


3,953



3,145



75



684



49Discontinued operations


28



20



-



8



-Assumed net income to be allocated

$
3,981


$
3,165


$
75


$
692


$
49Basic and diluted income from continuing operations per unit


$
0.06






$
0.03


$
0.06Basic and diluted discontinued operations per unit





$
-






$
-


$
-Basic and diluted income per unit





$
0.06






$
0.03


$
0.06





The following table presents the Partnership’s basic and diluted loss per unit for the three months ended March 31, 2009:




Total


Common Units


Restricted common Units


Subordinated Units


General Partner Units($ in thousands, except for per unit amounts)Loss from continuing operations

$
(2,852
)Distributions declared


1,368


$
1,326


$
21


$
-


$
21Assumed loss from continuing operations after distribution to be allocated


(4,220
)


(3,001
)


-



(1,171
)


(48
)Assumed allocation of loss from continuing operations


(2,852
)


(1,675
)


21



(1,171
)


(27
)Discontinued operations


307



217



-



86



4Assumed net loss to be allocated

$
(2,545
)

$
(1,458
)

$
21


$
(1,085
)

$
(23
)Basic and diluted loss from continuing operations per unit





$
(0.03
)





$
(0.06
)

$
(0.03
)Basic and diluted discontinued operations per unit





$
-






$
-


$
-Basic and diluted loss per unit





$
(0.03
)





$
(0.06
)

$
(0.03
)











21
 Table of Contents





NOTE 17.  DISCONTINUED OPERATIONS





On April 1, 2009, the Partnership sold its producer services business (which was accounted for in its South Texas Segment) by assigning and novating the contracts under this business to a third-party purchaser.  The Partnership sold the producer services business to a third-party purchaser as it was a low-margin business that was not core to the Partnership’s operations. The Partnership received an initial payment of $0.1 million for the sale of the business.  In addition the Partnership received a contingency payment of $0.1 million in October 2009. The Partnership will also continue to receive a monthly payment equivalent to $0.01 per MMbtu on the volume of gas that flows pursuant to the assigned contracts through March 31, 2011.  Producer services was a business in which the Partnership would negotiate new well connections on behalf of small producers to pipelines other than its own.  During the three months ended March 31, 2010, this business generated revenues of less than $0.1 million and no cost of natural gas and natural gas liquids.  During the three months ended March 31, 2009, this business generated revenues of $19.4 million and cost of natural gas and natural gas liquids of $19.1 million.  For the three months ended March 31, 2010, less than $0.1 million of revenues minus the cost of natural gas and natural gas liquids have been reported as discontinued operations, as compared to revenues minus the cost of natural gas and natural gas liquids of $0.3 million for the three months ended March 31, 2009.





NOTE 18.  SUBSIDIARY GUARANTORS





In the future, the Partnership may issue registered debt securities guaranteed by its subsidiaries.  The Partnership expects that all guarantors would be wholly-owned or available to be pledged and that such guarantees would be joint and several and full and unconditional.  In accordance with practices accepted by the SEC, the Partnership has prepared Condensed Consolidated Financial Statements as supplemental information.  The following Condensed Consolidated Balance Sheets at March 31, 2010 and December 31, 2009 and Condensed Consolidated Statements of Operations and Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2010 and 2009, present financial information for Eagle Rock Energy Partners, L.P. as the Parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors, which are all fully owned by the Parent, on a stand-alone basis, and the consolidation and elimination entries necessary to arrive at the information for the Partnership on a consolidated basis.  The subsidiary guarantors are not restricted from making distributions to the Partnership.





Unaudited Condensed Consolidated Balance SheetMarch 31, 2010($ in thousands)

Parent Issuer


Subsidiary Guarantors


Non-guarantor investments


Consolidating Entries


TotalASSETS:Accounts receivable – related parties

$
66,575


$
-


$
-


$
(66,575
)

$
-Other current assets


4,234



94,712



-



-



98,946Total property, plant and equipment, net


524



1,260,221



-



-



1,260,745Investment in subsidiaries


1,256,621



-



1,199



(1,257,820
)


-Total other long-term assets


6,378



153,152



-



-



159,530Total assets

$
1,334,332


$
1,508,085


$
1,199


$
(1,324,395
)

$
1,519,221LIABILITIES AND EQUITY:Accounts payable – related parties

$
-


$
66,575


$
-


$
(66,575
)

$
-Other current liabilities


42,566



110,804



-



-



153,370Other long-term liabilities


19,603



74,085



-



-



93,688Long-term debt


737,383



-



-



-



737,383Equity


534,780



1,256,621



1,199



(1,257,820
)


534,780Total liabilities and equity

$
1,334,332


$
1,508,085


$
1,199


$
(1,324,395
)

$
1,519,221











Unaudited Condensed Consolidated Balance SheetDecember 31, 2009($ in thousands)

Parent Issuer


Subsidiary Guarantors


Non-guarantor investments


Consolidating Entries


TotalASSETS:Accounts receivable – related parties

$
87,433


$
-


$
-


$
(87,433
)

$
-Other current assets


5,171



93,994



-



-



99,165Total property, plant and equipment, net


212



1,275,669



-



-



1,275,881Investment in subsidiaries


1,244,384



-



1,205



(1,245,589
)


-Total other long-term assets


5,620



153,662



-



-



159,282Total assets

$
1,342,820


$
1,523,325


$
1,205


$
(1,333,022
)

$
1,534,328LIABILITIES AND EQUITY:Accounts payable – related parties

$
-


$
87,433


$
-


$
(87,433
)

$
-Other current liabilities


42,099



114,083



-



-



156,182Other long-term liabilities


15,940



77,425



-



-



93,365Long-term debt


754,383



-



-



-



754,383Equity


530,398



1,244,384



1,205



(1,245,589
)


530,398Total liabilities and equity

$
1,342,820


$
1,523,325


$
1,205


$
(1,333,022
)

$
1,534,328








22
 Table of Contents





Unaudited Condensed Consolidated Statement of OperationsFor the three months ended March 31, 2010($ in thousands)

Parent Issuer


Subsidiary Guarantors


Non-guarantor investments


Consolidating Entries


TotalTotal revenues

$
1,522


$
227,087


$
-


$
-


$
228,609Cost of natural gas and natural gas liquids


-



144,278



-



-



144,278Operations and maintenance


-



19,235



-



-



19,235Taxes other than income


1



3,998



-



-



3,999General and administrative


2,736



10,352



-



-



13,088Depreciation, depletion, and impairment


4



29,431



-



-



29,435Income from operations


(1,219
)


19,793



-



-



18,574Interest expense, net


(7,428
)


(6,427
)


-



-



(13,855
)Other non-operating income


2,002



740



6



(2,480
)


268Other non-operating expense


(744
)


(2,005
)


-



2,480



(269
)Income (loss) before income taxes


(7,389
)


12,101



6



-



4,718Income tax provision


827



(62
)


-



-



765Equity in earnings of subsidiaries


12,197



-



-



(12,197
)


-Income (loss) from continuing operations


3,981



12,163



6



(12,197
)


3,953Discontinued operations


-



28



-



-



28Net income (loss)

$
3,981


$
12,191


$
6


$
(12,197
)

$
3,981











Unaudited Condensed Consolidated Statement of OperationsFor the three months ended March 31, 2009($ in thousands)

Parent Issuer


Subsidiary Guarantors


Non-guarantor investments


Consolidating Entries


TotalTotal revenues

$
(7,080
)

$
206,774


$
-


$
-


$
199,694Cost of natural gas and natural gas liquids


-



133,217



-



-



133,217Operations and maintenance


-



18,641



-



-



18,641Taxes other than income


-



2,978



-



-



2,978General and administrative


42



12,496



-



-



12,538Depreciation, depletion, and impairment


-



30,305



-



-



30,305Income (loss) from operations


(7,122
)


9,137



-



-



2,015Interest expense, net


(7,663
)


(227
)


-



-



(7,890
)Other non-operating income


1,679



996



29



(2,144
)


560Other non-operating expense


(732
)


(1,679
)


-



2,144



(267
)Income (loss) before income taxes


(13,838
)


8,227



29



-



(5,582
)Income tax provision (benefit)


52



(2,782
)


-



-



(2,730
)Equity in earnings of subsidiaries


11,345



-



-



(11,345
)


-Income from continuing operations


(2,545
)


11,009



29



(11,345
)


(2,852
)Discontinued operations


-



307



-



-



307Net income

$
(2,545
)

$
11,316


$
29


$
(11,345
)

$
(2,545
)







23
 Table of Contents





Condensed Consolidated Statement of Cash FlowsFor the three months ended March 31, 2010($ in thousands)

Parent Issuer


Subsidiary Guarantors


Non-guarantor investments


Consolidating Entries


TotalNet cash flows provided by (used in) operating activities

$
15,291


$
9,088


$
(6
)

$
-


$
24,373CASH FLOWS FROM INVESTING ACTIVITIES:Additions to property, plant and equipment


(316
)


(7,942
)


-



-



(8,258
)Purchase of intangible assets


-



(580
)


-



-



(580
)Investment in partnerships


-



(128
)


-



-



(128
)Proceeds from sale of asset


-



33



-



-



33Net cash flows used in investing activities


(316
)


(8,617
)


-



-



(8,933
)CASH FLOWS FROM FINANCING ACTIVITIES:Proceeds from long-term debt


18,000



-



-



-



18,000Repayment of long-term debt


(35,000
)


-



-



-



(35,000
)Proceeds from derivative contracts


-



305



-



-



305Distributions to members and affiliates


(1,328
)


-



-



-



(1,328
)Net cash flows (used in) provided by financing activities


(18,328
)


305



-



-



(18,023
)Net (decrease) increase in cash and cash equivalents


(3,353
)


776



(6
)


-



(2,583
)Cash and cash equivalents at beginning of year


4,922



(2,179
)


(11
)


-



2,732Cash and cash equivalents at end of year

$
1,569


$
(1,403
)

$
(17
)

$
-


$
149








Condensed Consolidated Statement of Cash FlowsFor the three months ended March 31, 2009($ in thousands)

Parent Issuer


Subsidiary Guarantors


Non-guarantor investments


Consolidating Entries


TotalNet cash flows (used in) provided by operating activities

$
(23,729
)

$
19,141


$
(29
)

$
-


$
(4,617
)CASH FLOWS FROM INVESTING ACTIVITIES:Additions to property, plant and equipment


(214
)


(12,873
)


-



-



(13,087
)Purchase of intangible assets


-



(718
)


-



-



(718
)Investment in partnerships


-



(341
)


-



-



(341
)Net cash flows used in investing activities


(214
)


(13,932
)


-



-



(14,146
)CASH FLOWS FROM FINANCING ACTIVITIES:Proceeds from long-term debt


109,000



-



-



-



109,000Repayment of long-term debt


(71,000
)


-



-



-



(71,000
)Proceeds from derivative contracts


-



4,317



-



-



4,317Distributions to members and affiliates


(31,639
)


-



-



-



(31,639
)Net cash flows provided by financing activities


6,361



4,317



-



-



10,678Net (decrease) increase in cash and cash equivalents


(17,582
)


9,526



(29
)


-



(8,085
)Cash and cash equivalents at beginning of year


29,272



(11,356
)


-



-



17,916Cash and cash equivalents at end of year

$
11,690


$
(1,830
)

$
(29
)

$
-


$
9,831








NOTE 19.  SUBSEQUENT EVENTS




In April 2010, the Partnership announced plans to begin construction on an expansion of its ETML gas gathering system in East Texas to provide multi-market capability for producers in the growing Haynesville and Middle Bossier shale plays in Nacogdoches and San Augustine Counties. The expansion includes the construction of a nine-mile, 20-inch diameter pipeline and associated treating facilities in Nacogdoches County, Texas with an initial pipeline capacity of 200 MMcf/d, and the expansion of existing ETML pipeline interconnects into NGPL, TETCO and Gulf South interstate pipelines and the HPL intrastate pipeline. The project, with an estimated total cost of $11.9 million, will expand the Partnership’s interconnect delivery capabilities through its ETML pipeline by 300 MMcf/d and will allow the tie-in of its existing BGS gathering system. The Partnership has purchased the required 20-inch pipe, acquired 100% of the necessary rights-of-way and expects the project to be completed and operational by early third quarter of 2010. Final approval to initiate construction is dependent upon many variables, including the Partnership’s ability to obtain producer commitments to the project.  Based on continued drilling activity and success in the area, the Partnership also is evaluating subsequent expansion phases which could result in a total of over 50 miles of primarily 20-inch diameter pipe extending east / west into Nacogdoches, Angelina, San Augustine and Sabine Counties, Texas, at a total estimated cost of approximately $49 million.





On April 19, 2010, the Partnership announced that the borrowing base under its revolving credit facility, which relates to our Upstream Business, was set at $130 million by its commercial lenders as part of the Partnership’s regularly scheduled semi-annual borrowing base redetermination.  The redetermined borrowing base is effective April 1, 2010, with no additional fees or increase in interest rate spread incurred.





During late April and early May 2010, the Partnership completed a turnaround of its Big Escambia Creek facility to conduct certain standard plant repairs and routine inspections of equipment. In addition to the routine turnaround activities, the Partnership is installing two new compressors that will provide improved reliability and backup for the existing residue gas and plant inlet compression. The new backup compression is expected to be available for service by July 2010. During the plant turnaround activities all wells in the Big Escambia Creek field were shut-in. The duration of both the plant turnaround and the well shut-in was approximately 12 days. The Partnership’s capital and expense associated with the turnaround activities during the three months ended June 30, 2010 is estimated to be $2.0 million and $1.3 million, respectively.  The impact to the Partnership’s production during this period was approximately 48 MMcf of residue gas, 14 MBbls of oil, 8.7 MBbls of plant liquids and 2,000 long tons of sulfur.   The partnership expects the revenue impact of the loss in production to be approximately $1.7 million during the three months ended June 30, 2010.


24
 Table of Contents








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




The following discussion and analysis of financial condition and results of operations should be read in conjunction with our unaudited condensed consolidated financial statements, and the notes thereto, appearing elsewhere in this report, as well as the Consolidated Financial Statements, Risk Factors and Management’s Discussion and Analysis of Financial Condition and Results of Operations presented in our annual report on Form 10-K for the year ended December 31, 2009, filed with the Securities and Exchange Commission. For a description of oil and natural gas terms, see our annual report.




Overview





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




•
Midstream Business—gathering, compressing, treating, processing and transporting of natural gas; fractionating and transporting of natural gas liquids (“NGLs”); and the marketing of natural gas, condensate and NGLs;




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




•
Minerals Business—acquiring and managing fee minerals and royalty interests, either through direct ownership or through investment in other partnerships.





We report on our businesses in seven accounting segments.





We conduct, evaluate and report on our Midstream Business within four distinct segments—the Texas Panhandle Segment, the East Texas/Louisiana Segment, the South Texas Segment and the Gulf of Mexico Segment. Our Texas Panhandle Segment consists of gathering and processing assets in the Texas Panhandle. Our East Texas/Louisiana Segment consists of gathering and processing assets in East Texas, Central Texas and Northern Louisiana. Our South Texas Segment consists of gathering systems and related compression and processing facilities in South Texas and West Texas.   Our Gulf of Mexico Segment consists of gathering and processing assets in Southern Louisiana, the Gulf of Mexico and Galveston Bay, Texas.  During the three months ended March 31, 2010, our Midstream Business generated operating income from continuing operations of $12.4 million compared to an operating loss from continuing operations of $6.1 million during the three months ended March 31, 2009.





We conduct, evaluate and report on our Upstream Business as one segment. Our Upstream Segment includes operated wells in Escambia County, Alabama as well as two treating facilities, one natural gas processing plant and related gathering systems that are inextricably intertwined with ownership and operation of the wells. The Upstream Segment also includes operated and non-operated wells that are primarily located in West, East and South Texas in Ward, Crane, Pecos, Henderson, Rains, Van Zandt, Limestone, Freestone and Atascosa Counties, Texas.  During the three months ended March 31, 2010, our Upstream Business generated operating income of $5.0 million compared to an operating loss of $6.5 million during the three months ended March 31, 2009.  Of important note, sales of sulfur generated revenue of $1.1 million during the three months ended March 31, 2010 compared to the cost of disposal of sulfur exceeding the revenue generated by $0.4 million during the three months ended March 31, 2009.





We conduct, evaluate, and report our Minerals Business as one segment.  Our Minerals Segment consists of fee mineral, royalty and overriding royalty interests located in multiple producing trends in the United States.  A significant portion of the mineral interests that we own are managed by Black Stone Minerals Company, a non-affiliated private partnership (the “Minerals Manager”) that controls the executive rights associated with the minerals.  During the three months ended March 31, 2010, our Minerals Business generated operating income of $3.8 million compared to operating income of $1.1 million during the three months ended March 31, 2009.  Included within these numbers is lease bonus revenue of $0.2 million generated during the three months ended March 31, 2010 compared to $0.6 million during the three months ended March 31, 2009.





On December 21, 2009, we entered into a definitive agreement to sell our Minerals Business subject to the approval of a majority of our non-affiliated common unitholders of the agreements described under “Recapitalization and Related Transactions” below.  As the sale of the Minerals Business is conditioned upon the approval by a majority of our non-affiliated common unitholders, we have not classified the assets of our Minerals Business as assets-held-for-sale or the operations as discontinued.  If the transactions are approved by a majority of the non-affiliated common unitholders, we will classify the assets of the Minerals Business as assets-held-for-sale and the operations as discontinued.





The final segment that we report on is our Corporate Segment, in which we account for our commodity derivative/hedging activity and our corporate-level general and administrative expenses.  During the three months ended March 31, 2010, our Corporate Segment generated an operating loss of $2.6 million compared to an operating income of $13.5 million during the three months ended March 31, 2009.  Within these numbers were gains, realized and unrealized, on commodity derivatives of $10.8 million during the three months ended March 31, 2010 compared to gains, realized and unrealized, on commodity derivatives of $26.3 million during the three months ended March 31, 2009.





We have an experienced management team dedicated to growing, operating and maximizing the profitability of our assets.  Our management team is experienced in gathering and processing natural gas, operating oil and natural gas properties and assets, and managing royalties and minerals.





We are controlled by our general partner who is controlled by its general partner (collectively “general partner”), who in turn is managed by its board of directors (the “Board of Directors”).





Impairment





In connection with the preparation of our unaudited condensed consolidated financial statements for the three months ended March 31, 2009, we recorded impairment charges for certain fields within our proved properties within our Upstream Segment.  These impairment charges were necessary due to the continued decline in natural gas prices during the period.  As a result, we incurred impairment charges of $0.2 million in our Upstream Segment.  No impairment charges were recorded for the three months ended March 31, 2010.





Pursuant to generally accepted accounting principles in the United States, 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.




Acquisitions




Historically, we have grown through acquisitions.  Going forward, we will continue to assess acquisition opportunities, regardless of whether such opportunity is in the midstream, upstream, or minerals business (subject to the sale of this business, see below), for their potential accretive value. Our ability to complete acquisitions will depend on our ability to finance the acquisitions, either through the issuance of additional securities, debt or equity, or the incurrence of additional debt under our revolving credit facility, on terms acceptable to us.  See further discussion under “Liquidity and Capital Resources.”




Recent Transactions





In February 2010, we announced our intention to deploy a currently idle high-efficiency cryogenic plant to the Texas Panhandle in order to increase efficiency and accommodate volume growth from the Granite Wash Play. Deployment of the cryogenic plant (the “Phoenix Plant”), in replacement of an aging facility, is phase two of our Texas Panhandle consolidation and processing capacity expansion project originally announced in February 2008.





In April 2010, we announced plans to begin construction on an expansion of our ETML gas gathering system in East Texas to provide multi-market capability for producers in the growing Haynesville and Middle Bossier shale plays in Nacogdoches and San Augustine Counties. The expansion includes the construction of a nine-mile, 20-inch diameter pipeline and associated treating facilities in Nacogdoches County, Texas with an initial pipeline capacity of 200 MMcf/d, and the expansion of existing ETML pipeline interconnects into NGPL, TETCO and Gulf South interstate pipelines and the HPL intrastate pipeline. The project, with an estimated total cost of $11.9 million, will expand our interconnect delivery capabilities through its ETML pipeline by 300 MMcf/d and will allow the tie-in of its existing BGS gathering system. We have purchased the required 20-inch pipe, acquired 100% of the necessary rights-of-way and expect the project to be completed and operational by early third quarter of 2010. Final approval to initiate construction is dependent upon many variables, including our ability to obtain producer commitments to the project.  Based on continued drilling activity and success in the area, we also are evaluating subsequent expansion phases which could result in a total of over 50 miles of primarily 20-inch diameter pipe extending east / west into Nacogdoches, Angelina, San Augustine and Sabine Counties, Texas, at a total estimated cost of approximately $49 million.





On April 19, 2010, we announced that the borrowing base under our revolving credit facility, which relates to our Upstream Business, was set at $130 million by our commercial lenders as part of our regularly scheduled semi-annual borrowing base redetermination.  The redetermined borrowing base is effective April 1, 2010, with no additional fees or increase in interest rate spread incurred.








25
 Table of Contents


During late April and early May 2010, we completed a turnaround of our Big Escambia Creek facility to conduct certain standard plant repairs and routine inspections of equipment. In addition to the routine turnaround activities, we are installing two new compressors that will provide improved reliability and backup for the existing residue gas and plant inlet compression. The new backup compression is expected to be available for service by July 2010. During the plant turnaround activities all wells in the Big Escambia Creek field were shut-in. The duration of both the plant turnaround and the well shut-in was approximately 12 days. Our capital and expense associated with the turnaround activities during the three months ended June 30, 2010 is estimated to be $2.0 million and $1.3 million, respectively.  The impact to our production during this period was approximately 48 MMcf of residue gas, 14 MBbls of oil, 8.7 MBbls of plant liquids and 2,000 long tons of sulfur. We expect the revenue impact of the loss in production to be approximately $1.7 million during the three months ended June 30, 2010.





Recapitalization and Related Transactions





On December 21, 2009, we announced that we, through certain of our affiliates, had entered into definitive agreements with affiliates of NGP and Black Stone to improve our liquidity and simplify our capital structure.  The definitive agreements include:  (i) a Securities Purchase and Global Transaction Agreement, entered into between Eagle Rock and NGP, including Eagle Rock’s general partner entities controlled by NGP, and (ii) a Purchase and Sale Agreement (the “Minerals Business Sale Agreement”), entered into between Eagle Rock and Black Stone for the sale of our Minerals Business.  The Securities Purchase and Global Transaction Agreement was amended and restated on January 12, 2010 to allow for greater flexibility in the payment of the contemplated transaction fee to Holdings, which is controlled by NGP (we refer to the amended Securities Purchase and Global Transaction Agreement throughout this document as the “Global Transaction Agreement”).




The Global Transaction Agreement and Minerals Business Sale Agreement include the following key provisions, which we refer to collectively as the “Recapitalization and Related Transactions.”






·
An option in favor of us, exercisable until December 31, 2012, by the issuance of 1,000,000 newly-issued common units, to capture the value of the controlling interest in us through (i) acquiring our general partner, and such general partner’s general partner, and thereby acquiring the 844,551 general partner units outstanding, and (ii) reconstituting our Board of Directors to allow our common unitholders not affiliated with NGP to elect the majority of our directors (the “GP Acquisition Option”);






·
The sale of our Minerals Business to Black Stone for total consideration of $174.5 million in cash, subject to customary adjustments;






·
The simplification of our capital structure through the contribution, and resulting cancellation, of our existing incentive distribution rights currently held by our general partner (which is ultimately controlled and 100% beneficially owned by Holdings) and approximately 20.7 million of our existing subordinated units currently held by Holdings;






·
A rights offering in which Holdings and NGP will fully participate with respect to approximately 9.5 million common and general partner units owned or controlled by Holdings and NGP as well as with respect to common units it receives as payment of the transaction fee, if any; and






·
For a period of up to five months following unitholder approval of the Global Transaction Agreement, NGP’s commitment to back-stop (primarily through Holdings) up to $41.6 million, at a price of $3.10 per common unit, of an Eagle Rock equity offering to be undertaken at the sole option of the Partnership’s Conflicts Committee.




In exchange for NGP’s and Holdings’ contributions and commitments under the Global Transaction Agreement, Eagle Rock will pay Holdings, subject to a successful unitholder vote, a transaction fee of $29 million in newly-issued common units.  The units were valued at $6.0101 per unit, based on 90% of the volume-adjusted trailing 10-day average of the trading price of Eagle Rock’s common units as of April 24, 2010, resulting in a total of approximately 4.8 million units to be paid to Holdings upon completion of the Minerals Business sale.




We filed a copy of the Minerals Business Sale Agreement, and the Global Transaction Agreement and related ancillary agreements, on Form 8-K with the SEC on December 21, 2009 and January 12, 2010, respectively.




Completion of the Recapitalization and Related Transactions is expected to occur in the second quarter of 2010, subject to customary closing conditions including approval of the Global Transaction Agreement and the transactions contemplated therein, including certain partnership agreement amendments, by a majority of the common units held by non-affiliates of NGP. The transactions contemplated by the Global Transaction Agreement are conditioned upon the consummation of the transactions contemplated in the Minerals Business Sale Agreement, which is conditioned on unitholder approval of the Global Transaction Agreement and related amendments to the Eagle Rock partnership agreement.




We will hold a special meeting of our common unitholders on May 14, 2010 for unitholders of record at the close of business on March 29, 2010, to vote on certain of the proposed Recapitalization and Related Transactions.




On March 8, 2010, we entered into the Second Amendment to our revolving credit facility, dated as of December 13, 2007, with Wachovia Bank, N.A., Bank of America, N.A., HSH NordBank AG, New York Branch, The Royal Bank of Scotland, PLC, BNP Paribas and the other lenders party thereto (the “Credit Facility Amendment”).





Prior to execution of the Credit Facility Amendment, we had concluded that we would require a waiver from our lender group in order to exercise the GP Acquisition Option without triggering a “Change in Control” event and potential event of default under our revolving credit facility.  The Credit Facility Amendment, however, modifies the definition of “Change in Control” in such a way that the exercise of the GP Acquisition Option would not trigger a “Change in Control” event and potential default provided we receive unitholder approval of the Recapitalization and Related Transactions prior to July 31, 2010.  In light of the amendment, the Conflicts Committee of our Board of Directors currently intend to cause us to exercise the GP Acquisition Option as soon as practicable after the required unitholder approval of the Recapitalization and Related Transactions.    The Credit Facility Amendment will take effect upon us providing written notice to our lender group that the required unitholder approvals have been obtained prior to July 31, 2010.





In addition to modifying the definition of “Change in Control,” the Credit Facility Amendment also:





·
Reduces the maximum permitted Senior Secured Leverage Ratio (as such term is defined in the revolving credit facility) from 4.25 to 1.0 under the current revolving credit facility to 3.75 to 1.0 (and from 4.75 to 1.0 to 4.25 to 1.0 for specified periods following certain permitted acquisitions);





·
Obligates the Partnership to use $100 million of the proceeds from the sale of our Minerals Business to make a mandatory prepayment towards our outstanding borrowings under the revolving credit facility; and





·
Reduces, upon such mandatory prepayment, the Partnership’s borrowing capacity under the revolving credit facility by the $100 million amount of such mandatory prepayment; however, the Partnership’s availability under its revolving credit facility is not currently impacted because it is calculated based on its outstanding debt and compliance with financial covenants.





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 Table of Contents





Presentation of Financial Information




For a description of the presentation of our financial information in this report, please see Note 1 to the unaudited condensed consolidated financial statements.




How We Evaluate Our Operations




Our management uses a variety of financial and operational measurements to analyze our performance. We view these measurements as important factors affecting our profitability and review these measurements on a monthly basis for consistency and trend analysis. These measures include oil, gas, NGL and sulfur volumes, and margins, operating expenses and Adjusted EBITDA (more fully described later under “Non-GAAP Financial Measures”) on a company-wide basis.




General Trends and Outlook




We expect our business to continue to be affected by the key trends as discussed in our Annual Report on Form 10-K for the year ended December 31, 2009. In particular, we continue to be affected by volatility in commodity prices including the prices for crude oil, natural gas, NGLs, condensate, and sulfur, among others; the reaction to the fall in natural gas prices by our producer customers in the Midstream Business, especially in the form of reduced drilling activity and curtailment or shutting-in of natural gas production; as well as the possibility of a prolonged period of economic recession. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about our interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.




On February 2, 2010, we declared our fourth quarter 2009 cash distribution of $0.025 per unit to our general partner (as to our general partner units) and our common unitholders of record as of the close of business on February 8, 2010.  The distribution was paid on February 12, 2010.





On April 27, 2010, we declared our first quarter 2010 cash distribution of $0.025 per unit to our general partner (as to our general partner units) and our common unitholders of record as of the close of business on May 7, 2010.  The distribution will be paid on May 14, 2010.




Cautionary Note Regarding Forward-Looking Statements





Certain matters discussed in this report, excluding historical information, include certain “forward-looking” statements. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “continue,” “estimate,” “forecast,” “may,” “will,” or similar expressions help identify forward-looking statements. Although we believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that these objectives will be reached. In addition, forward-looking statements speak only as of the date on which such statements are made.  Actual results may differ materially from any results projected, forecasted, estimated or expressed in forward-looking statements because many of the factors which determine these results are subject to uncertainties and risks, difficult to predict, and beyond management’s control. We assume no obligation to update any forward-looking statement as of any future date.  For additional discussion of risks, uncertainties and assumptions, see our annual report on Form 10-K for the year ended December 31, 2009, filed with the Securities and Exchange Commission on March 9, 2010, as well as the risks disclosed in Part II, Item 1A below.





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 Table of Contents







Summary of Consolidated Operating Results





Below is a summary table of our consolidated operating results for the three months ended March 31, 2010 and March 31, 2009, respectively. Operating results for our individual operating segments are presented in tables in this Item 2.







Three MonthsEnded March 31,2010


2009REVENUE:

($ in thousands)Natural gas, natural gas liquids, oil, condensate and sulfur sales

$
199,296


$
158,490Gathering, compression, processing and treating fees


12,833



11,667Minerals and royalty income


5,649



3,239Unrealized commodity derivative gains (losses)


13,478



(4,522
)Realized commodity derivative (losses) gains


(2,683
)


30,778Other revenue


36



42Total revenue


228,609



199,694COSTS AND EXPENSES:Cost of natural gas and natural gas liquids


144,278



133,217Operations and maintenance


19,235



18,641Taxes other than income


3,999



2,978General and administrative


13,088



12,538Impairment


-



242Depreciation, depletion and amortization


29,435



30,063Total costs and expenses


210,035



197,679OPERATING  INCOME


18,574



2,015OTHER INCOME (EXPENSE):Interest income


2



32Other income


268



560Interest expense


(4,145
)


(7,539
)Realized interest rate derivative losses


(4,890
)


(3,482
)Unrealized interest rate derivative (losses) gains


(4,822
)


3,099Other expense


(269
)


(267
)Total other income (expense)


(13,856
)


(7,597
)INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES


4,718



(5,582
)INCOME TAX (BENEFIT) PROVISION


765



(2,730
)INCOME (LOSS) FROM CONTINUING OPERATIONS


3,953



(2,852
)DISCONTINUED OPERATIONS


28



307NET INCOME (LOSS)

$
3,981


$
(2,545
)ADJUSTED EBITDA (a)

$
36,805


$
41,105





(a)
See “Non-GAAP Financial Measures” and Reconciliation of ‘Adjusted EBITDA’ to net cash flows provided by operating activities and net loss within Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations for a definition and reconciliation to GAAP.





Adjusted EBITDA, for the three months ended March 31, 2010 and 2009, excludes amortization of commodity hedge costs (including costs of hedge reset transactions) of $2.6 million and $12.2 million, respectively.  Including these amortization costs, our Adjusted EBITDA for the three months ended March 31, 2010 and 2009 would have been $34.2 million and $28.9 million, respectively.





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 Table of Contents





Midstream Business (Four Segments)




Texas Panhandle Segment




Three MonthsEnded March 31,2010


2009REVENUE:

($ in thousands, except prices and volumes)Natural gas, natural gas liquids, oil, condensate and sulfur sales

$
90,733


$
62,950Gathering and treating services


2,942



2,813Total revenue


93,675



65,763Cost of natural gas and natural gas liquids


66,970



51,947Operating costs and expenses:Operations and maintenance


8,098



8,145Depreciation, depletion and amortization


11,590



11,096Total operating costs and expenses


19,688



19,241Operating income (loss)

$
7,017


$
(5,425
)Capital expenditures

$
2,204


$
3,111Realized average prices:Oil and condensate (per Bbl)

$
68.50


$
47.23Natural gas (per MMbtu)

$
5.20


$
3.45NGLs (per Bbl)

$
48.22


$
24.61Production volumes:Gathering volumes (Mcf/d) (a)


128,493



144,203NGLs (net equity gallons) (b)


9,555,983



10,635,049Condensate (net equity gallons) (b)


8,719,633



6,192,426Natural gas short position (MMbtu/d) (a)


(4,301
)


(6,141
)





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


(b)
Installation of additional measurement facilities in January 2010 has improved the measurement of NGLs and condensate volumes resulting in increased equity condensate volumes and a corresponding decrease in equity NGL volumes.




Revenues and Cost of Natural Gas and Natural Gas Liquids.For the three months ended March 31, 2010, revenues minus cost of natural gas and natural gas liquids for our Texas Panhandle Segment operations totaled $26.7 million compared to $13.8 million for the three months ended March 31, 2009.  The increase is primarily driven by the higher NGL, natural gas and condensate pricing as compared to pricing in 2009.  This increase was partially offset by inclement weather during the three months ended March 31, 2010, which management estimates negatively impacted operating income in the Texas Panhandle Segment by approximately $1.0 million.




The lower gathering volumes during the three months ended March 31, 2010 compared to the same period in the prior year were due to natural declines in the underlying existing wells in addition to reduced drilling activity during 2009.   The dramatic fall in commodity prices experienced in the latter part of 2008 and continuing throughout 2009 resulted in many of our producer customers significantly reducing drilling activity in the Texas Panhandle, presumably not to be resumed until commodity prices rise to levels which justify drilling.   While oil prices have recovered from the lows seen in the three months ended March 31, 2009, natural gas prices have not recovered to levels that have caused our producers to increase drilling activity back to the 2008 levels.





Our Texas Panhandle Segment primarily covers ten counties in Texas and consists of our East Panhandle System and our West Panhandle System. The drilling activity in the West Panhandle System is not sufficient to offset the natural declines experienced on this system. While our contract mix in the West Panhandle System provides us with a higher equity share of the production, the overall decline will continue and we expect to recover smaller equity production in the future on the West Panhandle System.





The East Panhandle System experienced growth in volumes and equity production due to the active Granite Wash drilling play located in Roberts, Hemphill and Wheeler Counties, Texas through much of 2008; however, due to lower commodity values during the fourth quarter of 2008 and continuing through the first nine months of 2009, we experienced a significant decline in drilling activity in this area.





Recent drilling by the largest operators in the Granite Wash play, utilizing horizontal drilling technologies, has resulted in initial natural gas production rates of 6 MMcf/d or better.   These operators believe the economics of the Granite Wash play will be significantly enhanced due to the fewer number of wells and lower capital required to develop the same amount of acreage versus conventional vertical drilling results.  We have extensive gathering and processing facilities in Roberts and Hemphill Counties, Texas and long term acreage dedications from several of the larger producers.   We believe we will benefit in the future due to the application of this technology in the Granite Wash play with increased natural gas and condensate production in the East Panhandle System.





The liquids content of the natural gas is lower in the East Texas Panhandle System and our contract mix provides us with a smaller share of equity production as compared to the West Panhandle System. At the current lower drilling activity in the East Panhandle System we would be unable to offset the continued decline on the West Panhandle System of NGL and condensate equity gallons.  Our current goal is to aggressively contract for new volumes in the East Panhandle System to offset the decline in volumes and our share of equity production in the West Panhandle System.




Operating Expenses.Operating expenses, including taxes other than income, were $8.1 million for the three months ended March 31, 2010 and March 31, 2009.





Depreciation and Amortization. Depreciation and amortization expenses for the three months ended March 31, 2010 were $11.6 million compared to $11.1 million for the three months ended March 31, 2009.  The major item impacting the $0.5 million increase was depreciation expense associated with the capital expenditures placed into service during the period.




Capital Expenditures.Capital expenditures for the three months ended March 31, 2010 were $2.2 million compared to $3.1 million for the three months ended March 31, 2009. The decrease in capital expenditures of $0.9 million was driven by reduced maintenance capital associated with fewer new well connects due to the lower drilling activity and by less growth capital due to expenditures related to our Stinnett – Cargray plant consolidation project incurred in the three months ended March 31, 2009.





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 Table of Contents







East Texas/Louisiana Segment




Three MonthsEnded March 31,2010


2009REVENUE:

($ in thousands, except prices and volumes)Natural gas, natural gas liquids, oil, condensate and sulfur sales

$
51,841


$
47,451Gathering and treating services


8,522



7,209Total revenue


60,363



54,660Cost of natural gas and natural gas liquids


46,205



45,009Operating costs and expenses:Operations and maintenance


4,209



4,552Depreciation, depletion and amortization


4,428



4,771Total operating costs and expenses


8,637



9,323Operating income

$
5,521


$
328Capital expenditures

$
1,541


$
9,096Realized average prices:Oil and condensate (per Bbl)

$
68.45


$
50.75Natural gas (per MMbtu)

$
5.89


$
4.29NGLs (per Bbl)

$
39.02


$
18.98Production volumes:Gathering volumes (Mcf/d) (a)


212,907



271,571NGLs (net equity gallons)


4,679,582



2,676,419Condensate (net equity gallons)


471,293



609,805Natural gas short position (MMbtu/d) (a)


1,828



3,277





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





Revenues and Cost of Natural Gas and Natural Gas Liquids. For the three months ended March 31, 2010, revenues minus cost of natural gas and natural gas liquids for our East Texas/Louisiana Segment totaled $14.2 million compared to $9.7 million for the three months ended March 31, 2009.  This increase is due to increased prices for both condensate and NGLs and higher NGL equity gallons due to recovery of additional ethane gallons.  During the first two months of 2009, we were operating our facilities in ethane rejection mode.  Ethane rejection mode is when we elect to not recover the ethane component in the natural gas stream in our plants and instead choose to leave the ethane component in the residue gas stream sold at the tailgate of our plants.  We operate in this manner when the value of ethane is worth more in the gas stream than as a separate component.





Our gathering volumes for the three months ended March 31, 2010 decreased by 22% as compared to the three months ended March 31, 2009.   This decline is due to natural declines in the underlying existing wells in addition to reduced drilling activity during 2009.   The dramatic fall in commodity prices experienced in the latter part of 2008 and into 2009 resulted in many of our producer customers significantly reducing drilling, presumably not to be resumed until commodity prices rise to levels which justify drilling.   While oil prices have recovered from the lows seen in the three months ended March 31, 2009, natural gas prices have not recovered to levels that have caused our producers to increase drilling activity back to the 2008 levels.





Operating Expenses.Operating expenses for the three months ended March 31, 2010 were $4.2 million compared to $4.6 million for the three months ended March 31, 2009. The major items impacting the $0.3 million decrease in operating expense for the three months was due to overall cost reduction initiatives implemented across the segment in operating expenses.





Depreciation and Amortization.Depreciation and amortization expenses for the three months ended March 31, 2010 were $4.4 million compared to $4.8 million for the three months ended March 31, 2009. The major item impacting the $0.3 million decrease was the impairment taken in the fourth quarter of 2009 resulting in decreased depletable bases.




Capital Expenditures.Capital expenditures for the three months ended March 31, 2010 were $1.5 million compared to $9.1 million for the three months ended March 31, 2009. Our decrease in capital spending of $7.6 million for the three months ended March 31, 2010 is due primarily to the construction of gathering lines to producers in the Brookeland and Tyler County gathering systems incurred during the three months ended March 31, 2009.







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 Table of Contents




South Texas Segment




Three MonthsEnded March 31,2010


2009REVENUE:

($ in thousands, except prices and volumes)Natural gas, natural gas liquids, oil, condensate and sulfur sales

$
25,649


$
31,788Gathering and treating services


934



1,557Other revenue


-



3Total revenue


26,583



33,348Cost of natural gas and natural gas liquids


23,638



31,069Operating costs and expenses:Operations and maintenance


853



1,061Depreciation, depletion and amortization


1,487



1,424Total operating costs and expenses


2,340



2,485Operating income (loss) from continuing operations


605



(206
)Discontinued Operations


28



307Operating income

$
633


$
101Capital expenditures

$
(24
)

$
(60
)Realized average prices:Oil and condensate (per Bbl)

$
78.36


$
26.87Natural gas (per MMbtu)

$
5.44


$
4.35NGLs (per Bbl)

$
49.98


$
25.89Production volumes:Gathering volumes (Mcf/d) (a)


74,124



97,413NGLs (net equity gallons)


305,698



224,505Condensate (net equity gallons)


484,066



647,460Natural gas short position (MMbtu/d) (a)


1,063



500





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





Revenues and Cost of Natural Gas and Natural Gas Liquids.During the three months ended March 31, 2010, the South Texas Segment contributed $2.9 million in revenues minus cost of natural gas and natural gas liquids as compared to $2.3 million for the three months ended March 31, 2009.  We were negatively impacted by declining gathering volumes, offset by increased commodity prices during the three months ended March 31, 2010 as compared to the same periods in 2009.




Operating Expenses.Operating expenses for the three months ended March 31, 2010 were $0.9 million compared to $1.1 million for the three months ended March 31, 2009.  The major item impacting the $0.2 million decrease in operating expense for the three months ended March 31, 2010 was the overall cost reduction initiatives implemented across the segment in operating expenses.




Depreciation and Amortization.Depreciation and amortization expenses for the three months ended March 31, 2010 were $1.5 million compared to $1.4 million for the three months ended March 31, 2009.





Discontinued Operations.  On April 1, 2009, we sold our producer services line of business, and we have classified the revenues minus the cost of natural gas and natural gas liquids as discontinued operations.  During the three months ended March 31, 2010, this business generated revenues of less than $0.1 million and no cost of natural gas and natural gas liquids.  During the three months ended March 31, 2009, this business generated revenues of $19.4 million and cost of natural gas and natural gas liquids of $19.1 million.  For the three months ended March 31, 2010, less than $0.1 million of revenues minus the cost of natural gas and natural gas liquids have been reported as discontinued operations, as compared to revenues minus the cost of natural gas and natural gas liquids of $0.3 million for the three months ended March 31, 2009.





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Gulf of Mexico Segment





Three MonthsEnded March 31,2010


2009REVENUE:

($ in thousands, except prices and volumes)Natural gas, natural gas liquids, oil, condensate and sulfur sales

$
8,424


$
6,222Gathering and treating services


435



88Total revenue


8,859



6,310Cost of natural gas and natural gas liquids


7,465



5,192Operating costs and expenses:Operations and maintenance


505



418Depreciation, depletion and amortization


1,603



1,488Total operating costs and expenses


2,108



1,906Operating loss

$
(714
)

$
(788
)Capital expenditures

$
13


$
141Realized average prices:Oil and condensate (per Bbl)

$
74.50


$
42.14NGLs (per Bbl)

$
48.50


$
27.96Production volumes:Gathering volumes (Mcf/d) (a)


102,291



116,627NGLs (net equity gallons)


1,087,316



1,712,150





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





Revenues and Cost of Natural Gas and Natural Gas Liquids.During the three months ended March 31, 2010, the Gulf of Mexico Segment contributed $1.4 million in revenues minus cost of natural gas and natural gas liquids compared to $1.1 million during the three months ended March 31, 2009.  This increase can be attributed to higher condensate and NGLS prices during the three months ended March 31, 2010 as compared to the three months ended March 31, 2009 offset by a reduction in volumes and NGLs.  The reduction in volumes is due to natural declines in the underlying existing wells, reduced drilling activity during 2009 and an adjustment downward in our ownership percentage at the North Terrebonne Plant.  Our ownership percentage in North Terrebonne adjusts up or down annually based upon our volume of gas from committed leases as compared to the total volumes of gas from all plant owners committed leases.





Operating Expenses.Operating expenses for the three months ended March 31, 2010 were $0.5 million compared to $0.4 million for the three months ended March 31, 2009.





Depreciation and Amortization.Depreciation and amortization expenses for the three months ended March 31, 2010 was $1.6 million compared to $1.5 million for the three months ended March 31, 2009.





Capital Expenditures.Capital expenditures for the three months ended March 31, 2010 and 2009 was less than $0.1 million and $0.1 million, respectively.




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 Table of Contents


Upstream Business (One segment)







Three MonthsEnded March 31,2010


2009REVENUE:

($ in thousands, except prices and volumes)Oil and condensate sales (a)

$
10,985


$
5,958Natural gas sales (b)


4,632



1,895Natural gas liquids sales (c)


5,964



2,226Sulfur sales


1,068



-Other


36



39Total revenue


22,685



10,118Operating costs and expenses:Operations and maintenance


9,292



6,532Sulfur disposal costs (e)


(185
)


440Impairment


-



242Depreciation, depletion and amortization


8,565



9,396Total operating costs and expenses


17,672



16,610Operating income (loss)

$
5,013


$
(6,492
)Capital expenditures

$
4,979


$
1,592Realized average prices: (d)Oil and condensate (per Bbl)

$
56.57


$
28.37Natural gas (per Mcf)

$
5.21


$
4.20NGLs (per Bbl)

$
49.53


$
19.11Sulfur (per Long ton) (e)

$
43.87


$
-Production volumes:Oil and condensate (Bbl)


197,465



207,530Natural gas (Mcf)


942,463



886,284NGLs (Bbl)


120,418



124,966Total (Mcfe)


2,849,761



2,881,260Sulfur (per Long ton) (e)


19,116



28,340





(a)
Revenues include a change in the value of product imbalances of $(181) and $(13) for the three months ended March 31, 2010 and 2009, respectively.


(b)
Revenues include a change in the value of product imbalances of $(278) and $(1,847) for the three months ended March 31, 2010 and 2009, respectively.


(c)
Revenues include a change in the value of product imbalances of $0 and $(139) for the three months ended March 31, 2010 and 2009, respectively.


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


(e)
During the three months ended March 31, 2010, an adjustment was made to decrease sulfur volumes by 5,230 long tons related to a prior period adjustment.  This adjustment is excluded from the calculation of realized prices.




Revenue. For the three months ended March 31, 2010 and 2009, the Upstream Segment contributed $22.7 million and $10.1 million of revenue, respectively.  The increase in revenue was due to substantially higher realized prices for oil, natural gas, NGLs and sulfur and lower non-cash mark-to-market of product imbalances during the three months ended March 31, 2010 compared to the three months ended March 31, 2009.  During the three months ended March 31, 2010, production averaged 10.5 MMcf/d of natural gas, 2.2 MBO/d of oil and condensate, and 1.3 MB/d of NGLs and 271 LT/d of sulfur.




During the three months ended March 31, 2010, sulfur revenue was $1.1 million compared to the cost to dispose of sulfur which exceeded the sales price by $0.4 million during the three months ended March 31, 2009.  In addition, during the three months ended March 31, 2010, we recorded a credit to sulfur disposal costs of $0.2 million to adjust for an overaccrual of sulfur cost in  a prior period.  Historically, sulfur was viewed as a low value by-product in the production of oil and natural gas.  In 2009, deterioration in the sulfur market during the three months ended March 31, 2009 caused the price at the Tampa, Florida market to decline to $5 per long ton, and we incurred costs to dispose of our sulfur at that time.   During the three months ended March 31, 2010, sulfur began to recover and priced at $90 per long ton on February 1, 2010 at the Tampa, Florida market.




Operating Expenses. Operating expenses, including severance and ad valorem taxes, totaled $9.3 million for the Upstream Segment during the three months ended March 31, 2010, as compared to $6.5 million for the three months ended March 31, 2009.  The increase in operating expense can be attributed to increased well workover expense associated with two well workovers in our Alabama operations incurred during the three months ended March 31, 2010 as compared to the same period in the prior year.  The production associated with the two wells was restored during the three months ended March 31, 2010.




Depreciation, Depletion and Amortization.Depreciation, depletion and amortization expense for the three months ended March 31, 2010 was $8.6 million as compared to $9.4 million for the three months ended March 31, 2009, respectively.  The decrease for the three months ended March 31, 2010 compared to the comparable period in 2009 is due to the decrease in our depletable base as a result of the impairment charges we incurred during the fiscal year 2009.




Impairment.No impairment charges were incurred during the three months ended March 31, 2010.  During the three months ended March 31, 2009, we incurred impairment charges related to certain fields within our Upstream Segment of $0.2 million due to the continued decline of natural gas prices during the periods.




Capital Expenditures.  The Upstream Segment’s capital expenditures for the three months ended March 31, 2010 and 2009 was $5.0 million and $1.6 million, respectively.  The increase in capital expenditures is due to drilling activity in our Permian operations, recompletions in the Jourdanton field and the acquisition of compression equipment required for the planned turnaround at our Big Escambia Creek facility that occurred during late April and early May 2010.  See further discussion of the turnaround in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Recent Transactions.   During the three months ended March 31, 2010, we drilled and completed one well, and was in the process of drilling and completing two additional wells in our Ward Estes field.







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 Table of Contents







Minerals Business (One segment)




Three MonthsEnded March 31,2010


2009REVENUE:

($ in thousands, except prices and volumes)Oil and condensate sales

$
2,904


$
1,676Natural gas sales


2,303



865Natural gas liquids sales


231



129Lease bonus, rentals and other


211



569Total revenue


5,649



3,239Operating costs and expenses:Operations and maintenance


462



471Depletion


1,409



1,675Total operating costs and expenses


1,871



2,146Operating income

$
3,778


$
1,093Realized average prices:Oil and condensate (per Bbl)

$
73.00


$
38.95Natural gas (per Mcf)

$
4.44


$
3.07NGLs (per Bbl)

$
43.27


$
22.59Production volumes:Oil and condensate (Bbl)


39,781



43,026Natural gas (Mcf)


518,190



282,202NGLs (Bbl)


5,338



5,711Total (Mcfe)


788,904



564,358




Revenue.  For the three months ended March 31, 2010 our revenue was $5.6 million as compared to $3.2 million for the three months ended March 31, 2009, respectively.  The increase in revenue was due to increases in commodity prices and regeneration from new wells, as discussed below.  This increase was offset by lower lease bonus income due to the reduced leasing activity in the three months ended March 31, 2010 as compared to the three months ended March 31, 2009, as discussed below.   During the three months ended March 31, 2010, as a result of regeneration we received an initial royalty payment for 35 new wells of which 17 were new Haynesville shale producers.




One of the distinctive characteristics of our large, diversified mineral position is that operators are continually conducting exploration and development drilling, recompletion, and workover operations on our interests; in our minerals segment, we refer to this phenomenon as “regeneration.” We do not pay for these operations, but we do receive a share of the production they generate. This mode of operation has resulted in relatively constant production rates from our mineral interests in the past, and while we expect that regeneration will continue, we are uncertain if it will continue at rates sufficient to maintain or grow the segment’s production rate so long as commodity prices remain at their current levels. The new sources of production that we expect will materialize due to regeneration will also be the source of future extensions and discoveries and positive revisions to our reserve estimates, which may effect out future depletion rates.




Additionally, we received approximately $0.2 million in bonus and delay rental payments during the three months ended March 31, 2010 as compared to $0.6 million in the three months ended March 31, 2009. The amount of revenue we receive from bonus and rental payments varies significantly from month to month; therefore, we do not believe a meaningful set of conclusions can be drawn by observing changes in leasing activity over small time periods. Commodity prices may affect the amount of leasing that will occur on the minerals in future periods, and it is impossible to predict the timing or amount of future bonus payments.  However, we do expect to receive some level of bonus payments in the future.




Operating Expenses. Operating expenses of $0.5 million for the three months ended March 31, 2010 and March 31, 2009 are predominately production and ad valorem taxes. These taxes are levied by various state and local taxing entities.




Depletion.  Our depletion during the three months ended March 31, 2010 was $1.4 million as compared to $1.7 million for the three months ended March 31, 2009.




On December 21, 2009, we entered into a definitive agreement to sell our Minerals Business subject to the approval of a majority of our non-affiliated common unitholders of the agreements described under “Recapitalization and Related Transactions” above.  As the sale of the Minerals Business is conditioned upon the approval by a majority of our non-affiliated common unitholders of the Recapitalization and Related Transactions, we have not classified the assets of our Minerals Business as assets-held-for-sale or the operations as discontinued.  If the transactions are approved by a majority of the non-affiliated common unitholders, we will classify the assets of the Minerals Business as assets-held-for-sale and the operations as discontinued.  If the Recapitalization and Related Transactions are approved at the special meeting of our common unitholders scheduled for May 14, 2010, we anticipate that the sale of our Minerals Business will close during the second quarter of 2010.









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Corporate Segment




Three MonthsEnded March 31,2010


2009REVENUE:

($ in thousands)Unrealized commodity derivative gains (losses)

$
13,478


$
(4,522
)Realized commodity derivative (losses) gains


(2,683
)


30,778Total revenue


10,795



26,256Operating costs and expenses:General and administrative


13,088



12,538Depreciation, depletion and amortization


353



213Total costs and expenses


13,441



12,751Operating (loss) income


(2,646
)


13,505Other income (expense):Interest income


2



32Other income


268



560Interest expense


(4,145
)


(7,539
)Realized interest rate derivative losses


(4,890
)


(3,482
)Unrealized interest rate derivative (losses) gains


(4,822
)


3,099Other expense


(269
)


(267
)Total other income (expense)


(13,856
)


(7,597
)(Loss) income from continuing operations before taxes


(16,502
)


5,908Income tax provision (benefit)


765



(2,730
)(Loss) income from continuing operations

$
(17,267
)

$
8,638




Revenues. The volatility inherent in commodity prices generates uncertainty around our cash flows. We attempt to counter this volatility by entering into certain derivative transactions to reduce our exposure to commodity price risk.




Our Corporate Segment’s revenues, which consist solely of our commodity derivatives activity, decreased to a gain of $10.8 million for the three months ended March 31, 2010, from a gain of $26.3 million for the three months ended March 31, 2009.  As a result of our commodity hedging activities, revenues include realized losses of $2.7 million on risk management activity that was settled during the three months ended March 31, 2010 and unrealized mark-to-market gains of $13.5 million for the three months ended March 31, 2010 as compared to realized gains of $30.8 million on risk management activity that was settled during the three months ended March 31, 2009 and unrealized mark-to-market losses of $4.5 million for the three months ended March 31, 2009.  Included with our unrealized commodity derivative gains (losses) are the amortization of put premiums and other derivative costs of $2.6 million and $12.2 million during the three months ended March 31, 2010 and 2009, respectively.




As the forward price curves for our hedged commodities shift in relation to the various strike prices of our commodity derivatives, the fair value of those instruments changes.  The unrealized, non-cash, mark-to-market results during the three months ended March 31, 2010 reflects forward curve price movements from the beginning to the end of the three-month and nine-month period for commodities underlying the derivative instruments.  The unrealized mark-to-market results for the three months ended March 31, 2010 and 2009 had no impact on cash activities for those periods and are excluded from our calculation of Adjusted EBITDA.




Given the uncertainty surrounding future commodity prices, and the general inability to predict these as they relate to the caps, floors, swaps and 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.




General and Administrative Expenses. General and administrative expenses were $13.1 million for the three months ended March 31, 2010 as compared to $12.5 million for the three months ended March 31, 2009.  Equity-based compensation expense decreased by approximately $0.4 million during the three months ended March 31, 2010 as compared to the three months ended March 31, 2009.  The three months ended March 31, 2009 included an allocation of expense of $0.4 million from Eagle Rock Holdings, L.P. due to its issuance of Tier I units to one of our executives.  No Tier I units were granted during the three months ended March 31, 2010.  This decrease was offset by increased insurance expense of $0.3 million during the three months ended March 31, 2010 as a result of a rebate received during the three months ended March 31, 2009, a charge to bad debt expense of $0.3 million during the three months ended March 31, 2010, an increase in our contract labor and other professional services expenses of $0.1 million and a net increase in other miscellaneous expenses of $0.3 million.  Included within our other professional services expenses for the three months ended March 31, 2010, are legal and other professional advisory fees of $1.0 million related to the Recapitalization and Related Transactions and the related lawsuit.




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





Total Other Income (Expense). Total other income (expense) includes both realized and unrealized gains and losses from our interest rate swaps. We incurred expense of $13.9 million for the three months ended March 31, 2010 as compared to $7.6 million for the three months ended March 31, 2009.  During the three months ended March 31, 2010, we incurred realized losses from our interest rate swaps of $4.9 million as compared to realized losses of $3.5 million during the three months ended March 31, 2009. We also incurred unrealized mark-to-market losses of $4.8 million and unrealized mark-to-market gains of $3.1 million during the three months ended March 31, 2010 and 2009, respectively.  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 to $4.1 million for the three months ended March 31, 2010 as compared to $7.5 million during the three months ended March 31, 2009, respectively.  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.  All of our outstanding debt consists of borrowings under our revolving credit facility, which bears interest primarily based on a LIBOR rate plus the applicable margin.  The decrease in interest expense is due to lower LIBOR rates during the three months ended March 31, 2010 as compared to the same period in 2009 and lower debt balances as a result of paying down debt over the last twelve months.





Income Tax Provision (Benefit) –Income tax provision for the three months ended March 31, 2010 and 2009 relates to (i) state taxes due by us and (ii) federal taxes due by Eagle Rock Energy Acquisition Co., Inc. (acquiring entity of certain entities acquired in the acquisition of Redman Energy Corporation “Redman Acquisition” in 2007) and Eagle Rock Energy Acquisition Co. II, Inc. (acquiring entity of certain entities acquired in the Stanolind Acquisition) and their wholly-owned corporations, Eagle Rock Upstream Development Company, Inc. (successor entity to certain entities acquired in the Redman Acquisition) and Eagle Rock Upstream Development Company II, Inc. (successor entity to certain entities acquired in the Stanolind Acquisition), which are subject to federal income taxes (the “C Corporations”).  During the three months ended March 31, 2010, our tax provision increased by $3.5 million as compared to the same periods in the prior year.  These increases were the result of 2010 income projected for the C Corporations resulting from utilization of our remaining net operating loss carryforwards during the year ended December 31, 2009.




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Adjusted EBITDA




Adjusted EBITDA, as defined under “Non-GAAP Financial Measures,” decreased by $4.3 million from $41.1 million for the three months ended March 31, 2009 to $36.8 million for the three months ended March 31, 2010.




As described above, for the three months ended March 31, 2010, revenues minus cost of natural gas and natural gas liquids for the Midstream Business (including the Texas Panhandle, East Texas/Louisiana, South Texas and the Gulf of Mexico Segment) increased by $18.3 million as compared to the three months ended March 31, 2009. For the three months ended March 31, 2010, revenues for our Upstream and Mineral Segments increased by $13.4 million as compared to the same period in the prior year.  Our Corporate Segment’s realized commodity derivatives loss increased by $33.5 million as compared to the three months ended March 31, 2009. This resulted in a decline of $1.7 million of total incremental revenues minus cost of natural gas and natural gas liquids for the three months ended March 31, 2010 as compared to the same period in the prior year.   The incremental revenue amounts are adjusted to exclude the impact of unrealized commodity derivatives and the non-cash mark-to-market Upstream Segment imbalances, which are not included in the calculation of Adjusted EBITDA.





Operating expenses (including taxes other than income) decreased by $0.5 million for our Midstream Business with respect to the three months ended March 31, 2010, while operating expenses for our Upstream and Minerals Segments increased by $2.6 million as compared to the three months ended March 31, 2009.




General and administrative expense, captured in the Corporate Segment, increased by $1.0 million as compared to the same period in the prior year.  These amounts are adjusted to exclude non-cash compensation charges related to our LTIP program and other operating expenses.




As a result, revenues (excluding the impact of unrealized commodity derivative activity and non-cash mark-to-market of Upstream product imbalances) minus cost of natural gas and natural gas liquids decreased by $1.7 million operating expenses increased by $2.1 million and general and administrative expenses increased by $1.0 million resulting in the decrease to Adjusted EBITDA during the three months ended March 31, 2010 as compared to the three months ended March 31, 2009.




Adjusted EBITDA, for the three months ended March 31, 2010 and 2009, excludes amortization of commodity hedge costs (including, for the three months ended March 31, 2010, costs of hedge reset transactions) of $2.6 million and $12.2 million, respectively.  Including these amortization costs, our Adjusted EBITDA for the three months ended March 31, 2010 and 2009 would have been $34.2 million and $28.9 million, respectively.




For a discussion of Adjusted EBITDA and reconciliation to GAAP, see “Non-GAAP Financial Measures” at the end of this item.




Liquidity and Capital Resources




Historically, our sources of liquidity have included cash generated from operations, equity investments by our existing owners, equity investments by other institutional investors and borrowings under our existing revolving credit facility.




We believe that the cash generated from these sources will continue to be sufficient to meet our expected quarterly cash distributions and our requirements for short-term working capital and long-term capital expenditures.




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




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




•
comply with applicable law or any partnership debt instrument or other agreement; or




•
provide funds for distributions to unitholders and the general partner in respect of any one or more of the next four quarters.





The actual distributions we will declare will be subject to our operating performance, prevailing market conditions (including forward oil, natural gas and sulfur prices), the impact of unforeseen events and the approval of our Board of Directors and will be done pursuant to our distribution policy.





In response to, in part, a lack of liquidity due to our high leverage levels and restricted access to the capital markets during 2009, our Board of Directors determined to reduce the quarterly distribution with respect to each quarter of 2009 and the first quarter of 2010 to $0.025 per common and general partner unit, as compared to $0.41 per common, subordinated and general partner unit paid with respect to the fourth quarter of 2008.  This decision was made to establish cash reserves (as against available cash) for the proper conduct of our business and to enhance our ability to remain in compliance with financial covenants under our revolving credit facility in future periods.  The cash not distributed has been used to reduce our outstanding debt under our revolving credit facility, to continue to execute our hedge strategy to maintain future cash flows and/or to fund growth capital expenditures.








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Under the terms of the agreements governing our revolving credit facility, we are prohibited from declaring or paying any distribution to unitholders if a default or event of default (as defined in such agreements) exists.Our goal is to reduce our ratio of outstanding debt to Adjusted EBITDA, or “leverage ratio,” with respect to our Midstream and Minerals Businesses, which as of March 31, 2010 was 4.54, to approximately 3.0 to 3.5, including without limitation, by reducing outstanding indebtedness.  We believe this leverage ratio range to be appropriate in light of these more turbulent economic conditions and more in-line with historical midstream industry standards.  Our leverage ratio has been negatively impacted in 2009 by the effect of lower commodity prices on our Adjusted EBITDA.  In response, we took steps to reduce our outstanding indebtedness under our revolving credit facility and to improve our Adjusted EBITDA position through prudent management of our hedging portfolio, including by hedge reset transactions.  During the three months ended March 31, 2010, we reduced our outstanding debt under the revolving credit facility by $17.0 million from $754.4 million to $737.4 million and since March 31, 2009, we reduced our outstanding indebtedness under the revolving credit facility by $100 million.  Based primarily on our current expectations of continued depressed natural gas prices, decreased drilling activity and a smaller contribution to our Adjusted EBITDA from our hedge portfolio and not taking into consideration the Recapitalization and Related Transactions (described above), we do not expect to be able to maintain the same level of debt reduction achieved during the past twelve months.  The actual amount and timing of further debt repayment will depend on a number of factors, including but not limited to, changes in commodity prices, our producer customers’ drilling plans, availability of external capital, and the potential consummation of asset acquisitions or divestitures, as well as future determinations of the borrowing base under our revolving credit facility and the effect of the Recapitalization and Related Transactions.  We also plan to reduce our leverage ratio by investing in attractive organic growth opportunities in our Midstream Business which will increase our Adjusted EBITDA.  Based on our strategy, we believe that we will remain in compliance with our financial covenants through 2010.




For a detailed description of our revolving credit facility, see the description under Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Debt Covenants included in our annual report on Form 10-K for the year ended December 31, 2009 and below under “Revolving Credit Facility and Debt Covenants.”




In the event that we acquire additional midstream assets or natural gas or oil properties that exceed our existing capital resources, we expect that we will finance those acquisitions with a combination of expanded or new debt facilities or cash reserves established by our general partner and, if necessary, new equity issuances.  In light of our current leverage ratio, we are experiencing restricted access to the capital markets.  If we are unable to reduce our leverage ratio, we expect our level of acquisition activity to be lower going forward than that which we experienced in 2008 and 2007.




Working Capital.Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. As of March 31, 2010, working capital was ($54.4) million as compared to ($57.0) million as of December 31, 2009.




The net increase in working capital of $2.6 million from December 31, 2009 to March 31, 2010, resulted primarily from the following factors:




·
cash balances and marketable securities, net of due to affiliates, decreased overall by $2.6 million and was impacted primarily by the distributions paid on February 12, 2010 with respect to the fourth quarter of 2009 financial results, the results of operations, timing of capital expenditures payments, and financing activities including our debt activities (the due to affiliate liability of $12.9 million as of March 31, 2010 is owed to Eagle Rock Energy G&P, LLC);




·
trade accounts receivable decreased by $2.2 million primarily from the impact of lower commodity prices on our consolidated revenue;




·
risk management net working capital balance increased by a net $3.6 million as a result of the changes in current portion of the mark-to-market unrealized positions, increased other derivative costs, which includes the unwinding of long-term positions to purchase current positions (see Hedging Strategy), and amortization of the put premiums and other derivative costs;




·
accrued liabilities decreased by $3.1 million primarily reflecting payment of employee benefit accruals, lower interest payments and the timing of payment of unbilled expenditures related primarily to capital expenditures.





Cash Flows for the Three Months Ended March 31, 2010 Compared to the Three Months Ended March 31, 2009





Cash Flow from Operating Activities. Cash flows from operating activities increased $29.0 million during the three months ended March 31, 2010 as compared to the three months ended March 31, 2009 as a result of higher commodity prices across our three businesses.  These higher commodity prices resulted in higher cash flows from the sale of our equity crude oil, natural gas and natural gas liquids volumes and higher cash flows from the sale of sulfur.  Higher commodity prices also resulted in us realizing net settlement losses during the three months ended March 31, 2010, of which $0.3 million of cash received was reclassified to cash from financing activities, compared to $4.3 million of cash received being reclassified during the three months ended March 31, 2009.




Cash Flows from Investing Activities. Cash flows used in investing activities for the three months ended March 31, 2010, as compared to the three months ended March 31, 2009, decreased by $5.2 million due to the decrease in capital expenditures in 2010.  The investing activities for the current period reflect additions to property, plant and equipment expenditures of $8.3 million versus $13.1 million for the prior year period.  This decrease is attributable to lower well-connect activity in our Midstream Business resulting from the reduced drilling activity of our producer customers, as well as lower capital spending associated with the maintenance of our Big Escambia Creek facility, for which we performed a scheduled turnaround during the three months ended March 31, 2009.





Cash Flows from Financing Activities. Cash flows used in financing activities during the three months ended March 31, 2010 were $18.0 million versus cash flows provided by financing activities of $10.7 during the three months ended March 31, 2009. Key differences between periods include net repayments to our revolving credit facility of $17.0 million during the three months ended March 31, 2010 as compared to net proceeds of $38.0 million from our revolving credit facility during the three months ended March 31, 2009.  Distributions to members decreased to cash outflows of $1.3 million during the three months ended March 31, 2010 as compared to $31.6 million during the three months ended March 31, 2009 as a result of reducing our quarterly distribution to $0.025 from $0.41 in 2009.





Hedging Strategy





We use a variety of hedging instruments to accomplish our risk management objectives.  At times our hedging strategy may involve entering into hedges with strike prices above current futures prices or resetting existing hedges to higher price levels in order to meet our cash flow requirements, stay in compliance with our revolving credit facility covenants and continue to execute on our distribution 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.




Revolving Credit Facility and Debt Covenants





As of March 31, 2010, unused capacity available to us under our credit agreement, based on outstanding debt and compliance with financial covenants as of that date, was approximately $60.9 million.  The credit agreement is scheduled to mature on December 13, 2012.





Our revolving credit facility accommodates, through the use of a borrowing base for our Upstream Business and traditional cash-flow based covenants for our Midstream and Minerals Businesses, the allocation of indebtedness to either our Upstream Business (to be measured against the borrowing base) or to our Midstream and Minerals Businesses (to be measured against the cash-flow based covenant).  At March 31, 2010, we were in compliance with our covenants under the revolving credit facility. Our interest coverage ratio, as defined in the credit agreement (i.e., Consolidated EBITDA divided by Consolidated Interest Expense), was 4.79 as compared to a minimum interest coverage covenant of 2.5, and our leverage ratio, as defined in the credit agreement (i.e., Total Funded Indebtedness divided by Adjusted Consolidated EBITDA), was 4.54 as compared to a maximum leverage ratio of 5.0.  In April 2010, our borrowing base was redetermined to $130 million, effective April 1, 2010.  Our covenant compliance throughout 2009 was benefited substantially from the contributions of our hedging portfolio.  Absent any changes to the current hedge positions in place for 2010, we anticipate a lower contribution from our hedges in 2010, which, among other factors, could result in us exceeding the allowable covenant levels in the revolving credit facility.  Our strategies to remain in compliance include (i) the liquidity enhancements contemplated in the Recapitalization and Related Transactions, (ii) asset sales, and/or (iii) enhancements to our hedging portfolio (including through hedge reset transactions).  Based on our strategy, we believe that we will remain in compliance with our financial covenants through 2010.





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Capital Requirements




We anticipate that we will have sufficient liquidity and access to capital to continue to maintain and commercially exploit our Midstream Business (all four segments), Upstream Segment, and Mineral Segment assets consistent with our current operations.  Additionally, as an operator of midstream and upstream assets, our capital requirements have increased to maintain those assets, hold production and throughput constant and to replace reserves. We anticipate that we will meet these requirements through cash generated from operations.  We believe, however, that substantial growth would require access to external capital sources.   At this time, we cannot provide assurances that we will be able to obtain the necessary capital under terms acceptable to us.





Our 2010 capital budget anticipates that we will spend approximately $62.6 million in total for the year on our existing assets, approximately $11.9 million of which is pending further approval from our Board of Directors.  Our capital expenditures were approximately $9.3 million for the three months ended March 31, 2010.  We anticipate a higher level of capital expenditures in our Upstream segment during 2010 associated with additional drilling in our Permian area, and the plant turnaround at our Big Escambia Creek facility, compared to 2009 capital expenditures.




The energy business can be capital intensive, requiring significant investment for the acquisition or development of new facilities. We categorize our capital expenditures as either:




•
growth capital expenditures, which are made to acquire additional assets to increase our business, to expand and upgrade existing systems and facilities or to construct or acquire similar systems or facilities in our Midstream Business (and our Upstream Business with respect to the Big Escambia Plant and other Alabama plants and facilities), or grow our production in our Upstream Business; or




•
maintenance capital expenditures, which are made to replace partially or fully depreciated assets, to meet regulatory requirements, to maintain the existing operating capacity of our assets and extend their useful lives, or to connect wells to maintain existing system volumes and related cash flows in our Midstream Business (and in our Upstream Business with respect to the Big Escambia Plant and other Alabama plants and facilities); in our Upstream Business, maintenance capital also includes capital which is expended to maintain our production  in the near future.




Since our inception in 2002, we have made substantial growth capital expenditures. We anticipate that when economic conditions allow us, we will continue to make growth capital expenditures and acquisitions; however we anticipate that our expenditures and acquisitions in 2009 and 2010 will not return to the levels maintained by us prior to 2009. We continually review opportunities for both organic growth projects and acquisitions which will enhance our financial performance.  De-levering our business by reducing our debt and enhancing our liquidity and access to new capital such that we once again have the ability to develop and maintain sources of funds to meet our capital requirements are critical to our ability to meet our growth objectives over the long-term.





We historically have financed our maintenance capital expenditures (including well-connect costs) with internally generated cash flow and our growth capital expenditures ultimately with draws from our revolving credit facility (although such expenditures were often funded out of internally generated cash flow as an interim step).  We anticipate funding our limited growth capital expenditures, for the foreseeable future, out of cash flow generated from operations, and, to the extent necessary, withdraws from our revolving credit facility.




Off-Balance Sheet Obligations




We have no off-balance sheet transactions or obligations.




Recent Accounting Pronouncements





The Financial Accounting Standards Board (the “FASB”) has codified a single source of U.S. Generally Accepted Accounting Principles (U.S. GAAP), the Accounting Standards Codification.Unless needed to clarify a point to readers, the Partnership will refrain from citing specific section references when discussing application of accounting principles or addressing new or pending accounting rule changes.





In June 2009, the FASB issued authoritative guidance which reflects the FASB’s response to issues entities have encountered when applying previous guidance.  In addition, this guidance addresses concerns expressed by the SEC, members of the United States Congress, and financial statement users about the accounting and disclosures required in the wake of the subprime mortgage crisis and the deterioration in the global credit markets.  In addition, because this guidance eliminates the exemption from consolidation for qualified special-purpose entities (“QSPEs”) a transferor will need to evaluate all existing QSPEs to determine whether they must be consolidated.   The guidance is effective for financial asset transfers occurring after the beginning of an entity’s first fiscal year that begins after November 15, 2009.  Early adoption of was prohibited.   This guidance was effective for us as of January 1, 2010 and did not have a material impact on our consolidated financial statements.





In June 2009, the FASB issued authoritative guidance, which amends the consolidation guidance applicable to variable interest entities (VIEs). The amendments will significantly affect the overall consolidation analysis.  While the FASB’s discussions leading up to the issuance of this guidance focused extensively on structured finance entities, the amendments to the consolidation guidance affect all entities and enterprises, as well as qualifying special-purpose entities (QSPEs) that were excluded from previous guidance.  Accordingly, an enterprise will need to carefully reconsider its previous conclusions, including (1) whether an entity is a VIE, (2) whether the enterprise is the VIE’s primary beneficiary, and (3) what type of financial statement disclosures are required.  This guidance is effective as of the beginning of the first fiscal year that begins after November 15, 2009, and early adoption was prohibited.  This guidance was effective for us as of January 1, 2010 and did not have a material impact on our consolidated financial statements.





In September 2009, the FASB issued a consensus which revises the standards for recognizing revenue on arrangements with multiple deliverables.  Before evaluating how to recognize revenue for transactions with multiple revenue generating activities, an entity should identify all the deliverables in the arrangement and, if there are multiple deliverables, evaluate each deliverable to determine the unit of accounting and whether it should be treated separately or in combination.  The consensus removes certain thresholds for separation, provides criteria for allocation of revenue amongst deliverables and expands disclosure requirements.  The standards will be effective June 1, 2010, for fiscal year 2011, unless we elect to early adopt the standards.  We have not determined if it will early adopt the standards.





In January 2010, the FASB issued additional guidance on fair value disclosures. The new guidance clarifies two existing disclosure requirements and requires new disclosures such as: (1) a “gross” presentation of activities (purchases, sales, and settlements) within the Level 3 rollforward reconciliation, which will replace the “net” presentation format; and (2) detailed disclosures about the transfers in and out of Level 1 and 2 measurements. This guidance is effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 rollforward information, which is required for annual reporting periods beginning after December 15, 2010, and for interim reporting periods within those years. We adopted the fair value disclosures guidance on January 1, 2010, except for the gross presentation of the Level 3 rollforward information which is not required to be adopted by us until January 1, 2011 (see Notes 10 and 11).





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Non-GAAP Financial Measures




We include in this filing 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; 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 Eagle Rock’s financial statements such as investors, commercial banks and research analysts.  For example, Eagle Rock’s lenders under its revolving credit facility use a variant of Eagle Rock’s Adjusted EBITDA in a compliance covenant designed to measure the viability of Eagle Rock and its ability to perform under the terms of its revolving credit facility; Eagle Rock, therefore, uses Adjusted EBITDA to measure its compliance with its revolving credit facility.  We believe that investors benefit from having access to the same financial measures that our management team uses in evaluating performance.  Adjusted EBITDA is useful in determining our ability to sustain or increase distributions. By excluding unrealized derivative gains (losses), a non-cash, mark-to-market benefit (charge) which represents the change in fair market value of our executed derivative instruments and is independent of our assets’ performance or cash flow generating ability, we believe Adjusted EBITDA reflects more accurately our ability to generate cash sufficient to pay interest costs, support our level of indebtedness, make cash distributions to our unitholders and general partner and finance our maintenance capital expenditures. We further believe that Adjusted EBITDA also describes more accurately the underlying performance of our operating assets by isolating the performance of our operating assets from the impact of an unrealized, non-cash measure designed to describe the fluctuating inherent value of a financial asset. Similarly, by excluding the impact of non-recurring discontinued operations, Adjusted EBITDA provides users of our financial statements a more accurate picture of our current assets’ cash generation ability, independently from that of assets which are no longer a part of our operations. Eagle Rock’s 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 Eagle Rock. For example, we include in Adjusted EBITDA the actual settlement revenue created from our commodity hedges by virtue of transactions undertaken by us to reset commodity hedges to higher prices or purchase puts or other similar floors despite the fact that we exclude from Adjusted EBITDA any charge for amortization of the cost of such commodity hedge reset transactions or puts. For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP (accounting principles generally accepted in the United States), see the table below.




Adjusted EBITDA should not be considered an alternative to net income (loss), operating income (loss), cash flows from operating activities or any other GAAP measure of liquidity or financial performance.





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 incomes determined under GAAP, as well as Adjusted EBITDA, to evaluate our liquidity.





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Reconciliations of “Adjusted EBITDA” to net cash flows provided by operation activities and net loss







Three Months EndedMarch 31,2010


2009($ in thousands)Net cash flows provided by (used in) operating activities

$
24,373


$
(4,617
)Add (deduct):Depreciation, depletion, amortization and impairment


(29,435
)


(30,305
)Amortization of debt issuance costs


(269
)


(267
)Risk management portfolio value changes


8,656



12,475Reclassing financing derivative settlements


305



4,317Other


(2,635
)


730Accounts receivables and other current assets


(1,506
)


(24,575
)Accounts payable, due to affiliates and accrued liabilities


2,827



41,104Other assets and liabilities


1,665



(1,407
)Net income (loss)


3,981



(2,545
)Add (deduct):Interest (income) expense, net


9,302



11,256Depreciation, depletion and amortization


29,435



30,305Income tax (benefit) provision


765



(2,730
)EBITDA


43,483



36,286Add (deduct):Risk management portfolio value changes


(8,656
)


1,423Restricted unit compensation expense


1,808



2,231Non-cash mark-to-market Upstream imbalances


466



2,032Discontinued operations


(28
)


(307
)Other income


(268
)


(560
)ADJUSTED EBITDA

$
36,805


$
41,105Three Months EndedMarch 31,2010



2009Amortization of commodity derivative costs

$
2,648


$
12,159







Adjusted EBITDA, for the three months ended March 31, 2010 and 2009, excludes amortization of commodity hedge costs (including costs of hedge reset transactions).  Including these amortization costs, our Adjusted EBITDA for the three months ended March 31, 2010 and 2009 would have been $34.2 million and $28.9 million, respectively.





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Item 3. Quantitative and Qualitative Disclosures About Market Risk.




Risk and Accounting Policies




We are exposed to market risks associated with adverse changes in commodity prices, interest rates and counterparty credit. We may use financial instruments such as put and call options, swaps and other derivatives to mitigate the effects of the identified risks. Adverse effects on our cash flow from changes in crude oil, natural gas, NGL product prices or interest rates could adversely impact our ability to make distributions to our unitholders, meet debt service obligations, fund required capital expenditures and other similar requirements. Our management has established a comprehensive review of our market risks and has developed risk management policies and procedures to monitor and manage these market risks. Our general partner is responsible for the overall approval of market risk management policies, delegation of transaction authority levels, and for the establishment of a Risk Management Committee. The Risk Management Committee is composed of officers (including, on an ex officio basis, our chief executive officer) who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee 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, sulfur and other commodities as a result of our gathering, processing, producing and marketing activities, which produce a naturally long position in crude oil, NGLs, sulfur and natural gas. Both our profitability and our cash flow are affected by volatility in prevailing prices for these commodities. These prices are impacted by changes in the supply and demand for these commodities, as well as market uncertainty and other factors beyond our control. Historically, changes in the prices of NGLs, such as natural gasoline, have generally correlated with changes in the price of crude oil but those correlations may change in the future.




We frequently use financial derivatives to reduce our exposure to commodity price risk. We have implemented a risk management policy which allows management to execute crude oil, natural gas liquids and natural gas hedging instruments, which may include swaps, collars, options and other derivatives, in order to reduce exposure to substantial adverse changes in the prices of these commodities. These hedges are only intended to mitigate the risk associated with our natural physical position.  To date we have been unable to identify financial derivatives to reduce our exposure to sulfur price risk.




We have not designated our derivative contracts as accounting hedges. As a result, we mark our derivatives to fair value with the resulting change in fair value included in our statement of operations.  For the three months ended March 31, 2010, we recorded a gain on risk management instruments of $10.8 million representing a fair value (unrealized) gain of $13.5 million, amortization of put premiums and other derivative costs of $2.6 million and net (realized) settlement loss of $2.7 million.  For the three months ended March 31, 2009, we recorded a gain on risk management instruments of $26.3 million representing a fair value (unrealized) loss of $4.5 million, amortization of put premiums and other derivative costs of $12.2 million and net (realized) settlement gains of $30.8 million.  As of March 31, 2010, the fair value net liability of these commodity contracts, including put premiums and other derivative costs, totaled approximately $37.6 million.




We continually monitor our hedging and contract 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 existing revolving credit agreement. To mitigate its interest rate risk, we have entered into various interest rate swaps. These swaps convert the variable-rate term loan into a fixed-rate obligation. The purpose of entering into these swaps is to eliminate interest rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments through the end of 2012. 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.  For the three months ended March 31, 2010, the Partnership recorded a fair value (unrealized) loss of $4.8 million and a realized loss of $4.9 million.  For the three months ended March 31, 2009, we recorded a fair value (unrealized) gain of $3.1 million and a realized loss of $3.5 million.  As of March 31, 2010, the fair value liability of these interest rate contracts totaled approximately $32.2 million.




Credit Risk





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





This concentration of credit risk may affect our overall credit risk in that these customers may be similarly affected by changes in the natural gas, natural gas liquids, petrochemical and other segments of the energy industry, the economy in general, the regulatory environment and other factors.  Our credit risk monitoring is not an absolute protection against credit loss.  Our credit risk monitoring is intended to mitigate our exposure to significant credit risk.





Our derivative counterparties, both commodity and interest rate, include BNP Paribas, Wells Fargo Bank N.A., Wachovia Bank N.A, Bank of Nova Scotia, Comerica Bank, Barclays Bank PLC, The Royal Bank of Scotland plc, Bank of America N.A., J Aron and Company (an affiliate of Goldman Sachs), BBVA Compass Bank and Credit Suisse Energy LLC (an affiliate of Credit Suisse Group AG).




Item 4.
Controls and Procedures.




Evaluation of Disclosure Controls and Procedures





Based on the evaluation of our disclosure controls and procedures (as defined in the 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 that occurred during the Partnership’s most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.




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PART II. OTHER INFORMATION




Item 1.
Legal Proceedings.




Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we are and may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. However, we are not currently a party to any material litigation. We maintain insurance policies with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, assure you 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.





On February 9, 2010 a lawsuit, alleging certain claims related to the Recapitalization and Related Transactions (see Note 9), was filed on behalf of one of the Partnership’s public unitholders in the Court of Chancery of the State of Delaware naming the Partnership, its general partner, certain affiliates of its general partner, including the general partner of its general partner, and each member of the Partnership's Board of Directors as defendants.  The complaint alleges a breach by defendants of their fiduciary duties to the Partnership and the public unitholders and seeks to enjoin the Recapitalization and Related Transactions.  The Partnership believes the allegations claimed in the lawsuit are without merit.  On March 11, 2010, in an effort to minimize the further cost, expense, burden and distraction of any litigation relating to the lawsuit, the parties to the lawsuit entered into a Memorandum of Understanding regarding the terms of a potential settlement of the lawsuit.  If the settlement is consummated it, among other things, would resolve the allegations by the plaintiff against the defendants in connection with the recapitalization and related transactions and would provide a release and settlement by a proposed class of the Partnership common unitholders during the period from September 17, 2009 through and including the date of the closing of the transactions of all claims against the defendants as they relate to the Recapitalization and Related Transactions.  In the event that the settlement is not consummated, the Partnership intends to vigorously defend against the lawsuit.




We have voluntarily undertaken a self-audit of our compliance with air quality standards, including permitting in the Texas Panhandle Segment as well as a majority of our other Midstream Business locations and some of our Upstream Business locations in Texas. This audit has been performed pursuant to the Texas Environmental, Health and Safety Audit Privilege Act, as amended. We have completed the disclosures to the Texas Commission on Environmental Quality (“TCEQ”), and we are addressing in due course the deficiencies that we disclosed therein.  We do not foresee at this time any impediment to the timely corrective efforts identified as a result of these audits.





Since January 1, 2010, we have received additional Notices of Enforcement (“NOEs”) and Notices of Violation (“NOVs”) from the TCEQ related to air compliance matters and expect to receive additional NOEs or NOVs from the TCEQ from time to time throughout 2010.  Though the TCEQ has the discretion to adjust penalties and settlements upwards based on a compliance history containing multiple, successive NOEs, we do not expect that the resolution of any existing NOE or any future similar NOE will vary significantly from the administrative penalties and agreed settlements experienced by it to date.






Item 1A.                Risk Factors.




Not applicable






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




We did not sell our equity securities in unregistered transactions during the period covered by this report.




We did not repurchase any of our common units during the period covered by this report.




Item 3.
Defaults Upon Senior Securities.




None.




Item 4.
Reserved.





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Item 5.                     Other Information.




None.




Item 6.
Exhibits.





10.1
Amended and Restated Securities Purchase and Global Transaction Agreement dated January 12, 2010 among Natural Gas Partners VII, L.P., Natural Gas Partners VIII, L.P., Montierra Minerals & Production, L.P., Montierra Management, LLC, Eagle Rock Holdings, L.P., Eagle Rock Energy G & P, LLC, Eagle Rock Energy GP, L.P. and Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 10.1 of the registrant’s current report on Form 8-K filed with the Commission on January 12, 2010).10.2
Credit Facility Amendment dated as of March 8, 2010, by and among Eagle Rock Energy Partners, L.P., as borrower, Wachovia Bank, N.A., Bank of America, N.A., HSH Nordbank AG, New York Branch, The Royal Bank of Scotland, PLC, BNP Paribas and the other lenders party thereto, and the Guarantors thereto (incorporated by reference to Exhibit 10.1 of the registrant’s current report on Form 8-K filed with the Commission on March 9, 2010).31.1
Certification by Joseph A. Mills pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.31.2
Certification by Jeffrey P. Wood pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.32.1
Certification by Joseph A. Mills pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350.32.2
Certification by Jeffrey P. Wood pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350.











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SIGNATURES




Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.





Date: May 7, 2010
EAGLE ROCK ENERGY PARTNERS, L.P.By:
EAGLE ROCK ENERGY GP, L.P., its general partnerBy:
EAGLE ROCK ENERGY G&P, LLC, its general partnerBy:
/s/ Jeffrey P. WoodJeffrey P. WoodSenior Vice President,Chief Financial Officer and Treasurer of Eagle RockEnergy G&P, LLC, General Partner of Eagle RockEnergy GP, L.P., General Partner of Eagle RockEnergy Partners, L.P.












































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EAGLE ROCK ENERGY PARTNERS, L.P.





EXHIBIT INDEX





10.1
Amended and Restated Securities Purchase and Global Transaction Agreement dated January 12, 2010 among Natural Gas Partners VII, L.P., Natural Gas Partners VIII, L.P., Montierra Minerals & Production, L.P., Montierra Management, LLC, Eagle Rock Holdings, L.P., Eagle Rock Energy G & P, LLC, Eagle Rock Energy GP, L.P. and Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 10.1 of the registrant’s current report on Form 8-K filed with the Commission on January 12, 2010).10.2
Credit Facility Amendment dated as of March 8, 2010, by and among Eagle Rock Energy Partners, L.P., as borrower, Wachovia Bank, N.A., Bank of America, N.A., HSH Nordbank AG, New York Branch, The Royal Bank of Scotland, PLC, BNP Paribas and the other lenders party thereto, and the Guarantors thereto (incorporated by reference to Exhibit 10.1 of the registrant’s current report on Form 8-K filed with the Commission on March 9, 2010).31.1
Certification by Joseph A. Mills pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.31.2
Certification by Jeffrey P. Wood pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.32.1
Certification by Joseph A. Mills pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350.32.2
Certification by Jeffrey P. Wood pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350.