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, 2009




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)




16701
Greenspoint Park Drive, Suite 200


Houston,
Texas 77060


(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 than 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 55,267,721 common units outstanding as of May 4, 2009.
















EAGLE
ROCK ENERGY PARTNERS, L.P.




TABLE
OF CONTENTS









PagePART I. FINANCIAL
      INFORMATIONItem 1.
            Financial Statements
            1Unaudited Condensed Consolidated Balance Sheets as of
      March 31, 2009 and December 31, 2008
            1Unaudited Condensed Consolidated Statements of
      Operations for the three months ended March 31, 2009 and
      2008
            2Unaudited Condensed Consolidated Statements of Cash
      Flows for the three months ended March 31, 2009 and
      2008
            3Unaudited Condensed Consolidated Statements of Members’
      Equity for the three months ended March 31, 2009 and
      2008
            4Notes to the Unaudited Condensed Consolidated Financial
      Statements
            5Item
      2.
            Management’s Discussion and Analysis of Financial Condition
      and Results of Operations
            25Item
      3.
            Quantitative and Qualitative Disclosures About Market
      Risk
            45Item
      4.
            Controls and Procedures
            46PART II. OTHER
    INFORMATIONItem
      1.
            Legal Proceedings
            47Item 1A.
            Risk Factors
            47Item
      2.
            Unregistered Sales of Equity Securities and Use of
      Proceeds
            48Item
      3.
            Defaults Upon Senior Securities
            48Item
      4.
            Submission of Matters to a Vote of Security
      Holders
            48Item
      5.
            Other Information
            48Item
      6.
            Exhibits
            48



















Table of Contents




PART 1. FINANCIAL
  INFORMATION




Item 1.
            Financial
      Statements.





EAGLE
ROCK ENERGY PARTNERS, L.P.


UNAUDITED
CONDENSED CONSOLIDATED BALANCESHEETS


($ in thousands)




March 31,
              2009
            
            
            December 31,
              2008ASSETSCURRENT
      ASSETS:Cash
      and cash equivalents
            
            $
            9,831
            
            
            $
            17,916Accounts
      receivable(1)
            
            
            89,020
            
            
            
            115,932Risk
      management assets
            
            
            108,839
            
            
            
            76,769Prepayments
      and other current assets
            
            
            4,944
            
            
            
            2,607Total
      current assets
            
            
            212,634
            
            
            
            213,224PROPERTY,
      PLANT AND EQUIPMENT — Net
            
            
            1,344,424
            
            
            
            1,357,609INTANGIBLE
      ASSETS — Net
            
            
            149,549
            
            
            
            154,206RISK
      MANAGEMENT ASSETS
            
            
            17,440
            
            
            
            32,451OTHER
      ASSETS
            
            
            17,112
            
            
            
            15,571TOTAL
            
            $
            1,741,159
            
            
            $
            1,773,061LIABILITIES
      AND MEMBERS’ EQUITYCURRENT
      LIABILITIES:Accounts
      payable
            
            $
            76,189
            
            
            $
            116,578Due
      to affiliate
            
            
            11,670
            
            
            
            4,473Accrued
      liabilities
            
            
            14,107
            
            
            
            19,565Taxes
      payable
            
            
            1,495
            
            
            
            1,559Risk
      management liabilities
            
            
            14,505
            
            
            
            13,763Total
      current liabilities
            
            
            117,966
            
            
            
            155,938LONG-TERM
      DEBT
            
            
            837,383
            
            
            
            799,383ASSET
      RETIREMENT OBLIGATIONS
            
            
            20,151
            
            
            
            19,872DEFERRED
      TAX LIABILITY
            
            
            39,543
            
            
            
            42,349RISK
      MANAGEMENT LIABILITIES
            
            
            30,024
            
            
            
            26,182OTHER
      LONG TERM LIABILITIES
            
            
            330
            
            
            
            1,622COMMITMENTS
      AND CONTINGENCIES (Note 12)MEMBERS’
      EQUITY:Common
      Unitholders(2)
            
            
            602,602
            
            
            
            625,590Subordinated
      Unitholders(3)
            
            
            97,197
            
            
            
            105,839General
      Partner(4)
            
            
            (4,037
            )
            
            
            (3,714
            )Total
      members’ equity
            
            
            695,762
            
            
            
            727,715TOTAL
            
            $
            1,741,159
            
            
            $
            1,773,061





(1)
            Net
      of allowable for bad debt of $12,080 as of March 31, 2009 and
      December 31, 2008, of which $10.7 million relates to SemGroup L.P.
      which filed for bankruptcy in July
2008.


(2)
            53,043,767
      units were issued and outstanding as of March 31, 2009 and
      December 31, 2008. These amounts do not include unvested restricted
      common units granted under the Partnership’s long-term incentive plan of
      931,226 and 905,486 as of March 31, 2009 and December 31, 2008,
      respectively.


(3)
            20,691,495
      units were issued and outstanding as of March 31, 2009 and
      December 31, 2008.


(4)
            844,551
      units were issued and outstanding as of March 31, 2009 and
      December 31, 2008.




See notes
to unaudited condensed consolidated financial statements.














1
 Table of Contents





EAGLE
ROCK ENERGY PARTNERS, L.P.


UNAUDITED
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


($ in thousands, except per unit
amounts)




Three
      Months
              Ended
      March 31,2009
            
            
            2008REVENUE:Natural
      gas, natural gas liquids, oil, condensate and sulfur sales
            
            $
            150,652
            
            
            $
            304,974Gathering,
      compression, processing and treating fees
            
            
            11,667
            
            
            
            7,143Minerals
      and royalty income
            
            
            3,239
            
            
            
            6,958Commodity
      risk management gains (losses)
            
            
            26,256
            
            
            
            (45,647
            )Other
      revenue
            
            
            42
            
            
            
            60Total
      revenue
            
            
            191,856
            
            
            
            273,488COSTS
      AND EXPENSES:Cost
      of natural gas and natural gas liquids
            
            
            125,819
            
            
            
            224,074Operations
      and maintenance
            
            
            18,201
            
            
            
            15,566Taxes
      other than income
            
            
            2,978
            
            
            
            4,347General
      and administrative
            
            
            12,538
            
            
            
            11,242Impairment
            
            
            242
            
            
            
            —Depreciation,
      depletion and amortization
            
            
            30,063
            
            
            
            25,745Total
      costs and expenses
            
            
            189,841
            
            
            
            280,974OPERATING  INCOME
      (LOSS)
            
            
            2,015
            
            
            
            (7,486
            )OTHER
      INCOME (EXPENSE):Interest
      income
            
            
            32
            
            
            
            301Other
      income
            
            
            560
            
            
            
            1,547Interest
      expense, net
            
            
            (7,539
            )
            
            
            (9,104
            )Interest
      rate risk management gains (losses)
            
            
            (383
            )
            
            
            (13,761
            )Other
      expense
            
            
            (267
            )
            
            
            (215
            )Total
      other income (expense)
            
            
            (7,597
            )
            
            
            (21,232
            )LOSS
      FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
            
            
            (5,582
            )
            
            
            (28,718
            )INCOME
      TAX (BENEFIT) PROVISION
            
            
            (2,730
            )
            
            
            (102
            )LOSS
      FROM CONTINUING OPERATIONS
            
            
            (2,852
            )
            
            
            (28,616
            )DISCONTINUED
      OPERATIONS
            
            
            307
            
            
            
            288NET
      LOSS
            
            $
            (2,545
            )
            
            $
            (28,328
            )NET
      INCOME (LOSS) PER COMMON UNIT — BASIC AND DILUTED:Basic
      and diluted:Loss
      from continuing operations per unitCommon
      units
            
            $
            (0.03
            )
            
            $
            (0.40
            )Subordinated
      units
            
            $
            (0.06
            )
            
            $
            (0.40
            )General
      partner units
            
            $
            (0.03
            )
            
            $
            (0.40
            )Discontinued
      operations per unitCommon
      units
            
            $
            0.00
            
            
            $
            0.00Subordinated
      units
            
            $
            0.00
            
            
            $
            0.00General
      partner units
            
            $
            0.00
            
            
            $
            0.00Net
      loss per unitCommon
      units
            
            $
            (0.03
            )
            
            $
            (0.39
            )Subordinated
      units
            
            $
            (0.06
            )
            
            $
            (0.39
            )General
      partner units
            
            $
            (0.03
            )
            
            $
            (0.39
            )Basic
      and diluted weighted average number outstanding (units in
      thousands)Common
      units
            
            
            53,044
            
            
            
            50,700Subordinated
      units
            
            
            20,691
            
            
            
            20,691General
      partner units
            
            
            845
            
            
            
            845




See notes
to unaudited condensed consolidated financial statements.


2
 Table of Contents








EAGLE
ROCK ENERGY PARTNERS, L.P.


UNAUDITED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


($ in thousands)




Three
      Months
              Ended
      March 31,2009
            
            
            2008CASH
      FLOWS FROM OPERATING ACTIVITIES:Net
      loss
            
            $
            (2,545
            )
            
            $
            (28,328
            )Adjustments
      to reconcile net loss to net cash provided by operating
      activities:Depreciation,
      depletion and amortization
            
            
            30,063
            
            
            
            25,745Impairment
            
            
            242
            
            
            
            —Amortization
      of debt issuance costs
            
            
            267
            
            
            
            217Reclassifying
      financing derivative settlements
            
            
            (4,317
            )
            
            
            2,278Distribution
      from unconsolidated affiliates – return on
investment
            
            
            51
            
            
            
            286Equity
      in earnings of unconsolidated affiliates
            
            
            (505
            )
            
            
            (1,541
            )Equity-based
      compensation expense
            
            
            2,231
            
            
            
            1,159Other
            
            
            (2,507
            )
            
            
            (46
            )Changes
      in assets and liabilities — net of acquisitions:Accounts
      receivable
            
            
            26,912
            
            
            
            (28,370
            )Prepayments
      and other current assets
            
            
            (2,337
            )
            
            
            (1,844
            )Risk
      management activities
            
            
            (12,475
            )
            
            
            46,732Accounts
      payable
            
            
            (42,843
            )
            
            
            20,649Due
      to affiliates
            
            
            7,197
            
            
            
            (197
            )Accrued
      liabilities
            
            
            (5,458
            )
            
            
            (2,761
            )Other
      assets and liabilities
            
            
            1,407
            
            
            
            (834
            )Net
      cash (used in) provided by operating activities
            
            
            (4,617
            )
            
            
            33,145CASH
      FLOWS FROM INVESTING ACTIVITIES:Additions
      to property, plant and equipment
            
            
            (13,087
            )
            
            
            (8,221
            )Purchase
      of intangible assets
            
            
            (718
            )
            
            
            (808
            )Investment
      in unconsolidated affiliates
            
            
            (341
            )
            
            
            —Net
      cash used in investing activities
            
            
            (14,146
            )
            
            
            (9,029
            )CASH
      FLOWS FROM FINANCING ACTIVITIES:Repayment
      of revolving credit facility
            
            
            (71,000
            )
            
            
            (10,069
            )Proceeds
      from revolving credit facility
            
            
            109,000
            
            
            
            —Proceeds
      (payments) for derivative contracts
            
            
            4,317
            
            
            
            (2,278
            )Distributions
      to members and affiliates
            
            
            (31,639
            )
            
            
            (28,528
            )Net
      cash provided by (used in) financing activities
            
            
            10,678
            
            
            
            (40,875
            )NET
      CHANGE IN CASH AND CASH EQUIVALENTS
            
            
            (8,085
            )
            
            
            (16,759
            )CASH
      AND CASH EQUIVALENTS — Beginning of period
            
            
            17,916
            
            
            
            68,552CASH
      AND CASH EQUIVALENTS — End of period
            
            $
            9,831
            
            
            $
            51,793SUPPLEMENTAL
      CASH FLOW DATA:Interest
      paid — net of amounts capitalized
            
            $
            10,828
            
            
            $
            9,515Investments
      in property, plant and equipment not paid
            
            $
            4,063
            
            
            $
            4,631


See notes
to unaudited condensed consolidated financial statements.


3
 Table of Contents





EAGLE
ROCK ENERGY PARTNERS, L.P.


UNAUDITED
CONDENSED CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY





FOR
THE THREE MONTH PERIOD ENDED MARCH 31, 2008


($ in thousands, except unit
amounts)







General
              Partner
            
            
            Number
      of
              Common
              Units
            
            
            Common
              Units
            
            
            Number
      of
              Subordinated
              Units
            
            
            Subordinated
              Units
            
            
            TotalBALANCE
      — December 31, 2007
            
            $
            (3,155
            )
            
            
            50,699,647
            
            
            $
            617,563
            
            
            
            20,691,495
            
            
            $
            112,360
            
            
            $
            726,768Net
      loss
            
            
            (333
            )
            
            
            —
            
            
            
            (19,830
            )
            
            
            —
            
            
            
            (8,165
            )
            
            
            (28,328
            )Distributions
            
            
            (331
            )
            
            
            —
            
            
            
            (20,075
            )
            
            
            —
            
            
            
            (8,122
            )
            
            
            (28,528
            )Equity
      based compensation
            
            
            14
            
            
            
            —
            
            
            
            814
            
            
            
            —
            
            
            
            331
            
            
            
            1,159BALANCE
      — March 31, 2008
            
            $
            (3,805
            )
            
            
            50,699,647
            
            
            $
            578,472
            
            
            
            20,691,495
            
            
            $
            96,404
            
            
            $
            671,071








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
      — December 31, 2008
            
            $
            (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




See notes
to unaudited condensed consolidated financial statements.





4
 Table of Contents





EAGLE
ROCK ENERGY PARTNERS, L.P.


NOTESTO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS







NOTE
1. ORGANIZATION AND DESCRIPTION OF BUSINESS






In May
2006, Eagle Rock Energy Partners, L.P. (“Eagle Rock Energy” or the
“Partnership”), a Delaware limited partnership and an indirect wholly-owned
subsidiary of Eagle Rock Holdings, L.P. (“Holdings”), was formed for the purpose
of completing a public offering of common units. Holdings is a portfolio company
of Irving, Texas–based, private-equity-capital firm Natural Gas Partners. On
October 24, 2006, Eagle Rock Energy Partners, L.P. completed its initial
public offering of common units. In connection with the initial public offering,
Eagle Rock Pipeline, L.P., which was the main operating subsidiary of Holdings,
became a subsidiary of Eagle Rock Energy.




Basis of
Presentation and Principles of Consolidation— The accompanying financial statements
include assets, liabilities and the results of operations of the Partnership.
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,
2008. 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, 2009, are not necessarily indicative of the results that
may be expected for the year ending December 31, 2009.




Description of
Business— The Partnership is a 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 interests 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 accounting 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, 2008. 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. 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


5
 Table of Contents


operating
viability of the project.




Depletion
of proved 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.





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.





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.




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. In connection with the
preparation of these financial statements for the three months ended March 31,
2009, the Partnership recorded impairment charges of $0.2 million in its
Upstream Segment as a result of continued decline in natural gas prices during
the period.  The Partnership did not incur any impairment charges
related to its oil and natural gas properties during the three months ended
March 31, 2008.   The Partnership cannot predict the amount of
additional impairment charges that may be recorded in the future.




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 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, 2009, the Partnership had imbalance
receivables totaling $0.1 million and imbalance payables totaling $2.5 million,
respectively. For the midstream business, as of December 31, 2008, the
Partnership had imbalance receivables totaling $0.3 million and imbalance
payables totaling $2.8 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.




Derivatives—Statement of
Financial Accounting Statements (“SFAS”) No. 133, Accounting for Derivative
Instruments and Hedging Activities,as amended (“SFAS No. 133”),
establishes accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other contracts, and for
hedging activities. SFAS No. 133 requires an entity to recognize all
derivatives as either assets or liabilities in the statement of financial
position and to measure 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 these financial instruments on
its consolidated balance sheets at the instrument’s fair value, and changes in
fair value are reflected in the 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.




6
 Table of Contents


NOTE
3. NEW ACCOUNTING PRONOUNCEMENTS




In
December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS
No. 141R”), which replaces SFAS 141. SFAS 141R requires that all assets,
liabilities, contingent consideration, contingencies and in-process research and
development costs of an acquired business be recorded at fair value at the
acquisition date; that acquisition costs generally be expensed as incurred; that
restructuring costs generally be expensed in periods subsequent to the
acquisition date; and that changes in accounting for deferred tax asset
valuation allowances and acquired income tax uncertainties after the measurement
period impact income tax expense.  SFAS No. 141R is effective for
business combinations for which the acquisition date is on or after the
beginning of the first annual reporting period beginning on or after December
15, 2008, with the exception for the accounting for valuation allowances on
deferred tax assets and acquired tax contingencies associated with
acquisitions.  SFAS No. 141R amends SFAS No. 109, Accounting for Income Taxes,such that adjustments made to valuation allowances on deferred taxes and
acquired tax contingencies associated with acquisitions that closed prior to the
effective date of SFAS No. 141R would also apply the provisions of SFAS No.
141R.  SFAS No. 141R was effective for the Partnership as of January
1, 2009 but the impact of the adoption on the Partnership’s consolidated
financial statements will depend on the nature and the extent of business
combinations occurring after January 1, 2009.




In
December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in
Consolidated Financial Statements—an amendment of APB No. 51 (“SFAS
No. 160”). SFAS No.160 requires that accounting and reporting for minority
interests will be recharacterized as noncontrolling interests and classified as
a component of equity. SFAS 160 also establishes reporting requirements that
provide sufficient disclosures that clearly identify and distinguish between the
interests of the parent and the interests of the noncontrolling owners. This
Statement is effective as of the beginning of an entity’s first fiscal year
beginning after December 15, 2008.  SFAS No. 160 was effective
for the Partnership as of January 1, 2009 and did not have a material impact on
its consolidated results of operations or financial position.




In
February 2008, the FASB issued FASB Staff Position (“FSP”) No. FAS 157-2,
“Effective Date of FASB Statement No. 157” (“FSP FAS 157-2”), which delays
the effective date of SFAS 157 for all nonfinancial assets and nonfinancial
liabilities, except those that are recognized or disclosed at fair value in the
financial statements on at least an annual basis, until fiscal years beginning
after November 15, 2008. FSP FAS 157-2 was effective for the
Partnership as of January 1, 2009 and did not have a material impact on the
consolidated results of operations or financial
position.  Non-financial assets and liabilities that the Partnership
measures at fair value on a non-recurring basis consists primarily of property,
plant and equipment, intangible assets and asset retirement obligations, which
are subject to fair value adjustments in certain circumstances (for example,
when there is evidence of impairment).




In March
2008, the FASB issued SFAS No. 161, Disclosures About Derivative
Instruments and Hedging Activities(“SFAS No. 161”). SFAS
No. 161 requires enhanced disclosures to help investors better understand
the effect of an entity’s derivative instruments and related hedging activities
on its financial position, financial performance, and cash flows. SFAS
No. 161 is effective for financial statements issued for fiscal years and
interim periods beginning after November 15, 2008, with early application
encouraged.  SFAS No. 161 was effective for the Partnership as of
January 1, 2009.  See Note 11 for the additional disclosures required
under FAS No. 161 related to the Partnership’s derivative
instruments.




In March
2008 the FASB approved EITF Issue No. 07-4, Application of the Two-Class Method
under FASB Statement No. 128, Earnings per Share, to Master Limited
Partnerships (“EITF 07-4”), which requires that master limited
partnerships use the two-class method of allocating earnings to calculate
earnings per unit. EITF Issue No. 07-4 is effective for fiscal years
and interim periods beginning after December 15, 2008.  EITF
Issue No. 07-4 was effective for the Partnership as of January 1, 2009 and
the impact on its earnings per unit calculation has been retrospectively applied
to March 31, 2008 (see Note 16).




In April
2008, the FASB issued FASB Staff Position (“FSP”) No. SFAS 142-3, Determination of the Useful Life of
Intangible Assets (“FSP SFAS 142-3”).  FSP SFAS 142-3 amends the
factors that should be considered in developing renewal or extension assumptions
used to determine the useful life of a recognized intangible asset under SFAS
No. 142, Goodwill and Other
Intangible Assets (“SFAS 142”).  The intent of FSP SFAS 142-3 is to
improve the consistency between the useful life of a recognized intangible asset
under SFAS 142 and the period of expected cash flows used to measure the fair
value of the asset under SFAS No. 141R and other applicable accounting
literature.  FSP SFAS 142-3 is effective for financial statements issued
for fiscal years beginning after December 15, 2008 and must be applied
prospectively to intangible assets acquired after the effective date.  FSP
SFAS No. 142-3 was effective for the Partnership as of January 1, 2009 but the
impact of the adoption on the Partnership’s consolidated financial statements
will depend on the nature and the extent of business combinations occurring
after January 1, 2009.




In May
2008, the FASB issued SFAS No. 162, Hierarchy of Generally Accepted
Accounting Principles (“SFAS 162”).  This statement is intended to
improve financial reporting by identifying a consistent framework, or hierarchy,
for selecting accounting principles to be used in preparing financial statements
of nongovernmental entities that are presented in


7
 Table of Contents


conformity
with GAAP.  This statement will be effective 60 days following the U.S.
Securities and Exchange Commission’s approval of the Public Company Accounting
Oversight Board amendment to AU Section 411, The Meaning of Present Fairly in
Conformity with Generally Accepted Accounting Principles.  The
adoption of SFAS 162 did not have a material impact on the Partnership’s
consolidated financial statements.




In June
2008, the FASB issued FSP No. EITF 03-6-1, Determining Whether Instruments
Granted in Share-Based Payment Transactions Are Participating Securities
(“FSP EITF 03-6-1”).  FSP EITF 03-6-1 affects entities that accrue
cash dividends on share-based payment awards during the awards’ service period
when dividends do not need to be returned if the employees forfeit the
awards.  FSP EITF 03-6-1 is effective for fiscal years beginning after
December 15, 2008 and earnings-per-unit calculations would need to be adjusted
retroactively.  FSP EITF 03-6-1 was effective for the Partnership as
of January 1, 2009 and the impact on its earnings per unit calculation has been
retrospectively applied to March 31, 2008. (see Note 16).




In
December 2008, the SEC released Final Rule, Modernization of Oil and Gas
Reporting to revise the existing Regulation S-K and Regulation S-X reporting
requirements to align with current industry practices and technological
advances. The new disclosure requirements include provisions that permit the use
of new technologies to determine proved reserves if those technologies have been
demonstrated empirically to lead to reliable conclusions about reserve volumes.
In addition, the new disclosure requirements require a company to (a) disclose
its internal control over reserves estimation and report the independence and
qualification of its reserves preparer or auditor, (b) file reports when a third
party is relied upon to prepare reserves estimates or conducts a reserve audit
and (c) report oil and gas reserves using an average price based upon the prior
12-month period rather than period-end prices. The provisions of this final
ruling will become effective for disclosures in the Partnership’s Annual Report
on Form 10-K for the year ending December 31, 2009.





In April
2009, the FASB issued FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of
Other-Than-Temporary Impairments “FSP FAS 115-2 and FAS
124-2”).  FSP FAS 115-2 and FAS 124-2 amends the other-than-temporary
impairment guidance for debt securities to make the guidance more operational
and to improve the presentation and disclosure of other-than-temporary
impairments in the financial statements. The most significant change is a
revision to the amount of other-than-temporary loss of a debt security recorded
in earnings. FSP FAS 115-2 and FAS 124-2 is effective for interim and annual
reporting periods ending after June 15, 2009. The Partnership does not believe
that the adoption of FSP FAS 115-2 and FAS 124-2 will have a material impact on
its consolidated financial statements.





In April
2009, the FASB issued FSP FAS 157-4, Determining Fair Value When the
Volume and Level of Activity for the Asset or Liability Have Significantly
Decreased and Identifying Transactions That Are Not Orderly(“FSP FAS
157-4”).  FSP FAS 157-4 provides additional guidance for estimating
fair value in accordance with FASB Statement No. 157, Fair Value Measurements, when
the volume and level of activity for the asset or liability have significantly
decreased.  FSP FAS 157-4 also includes guidance on identifying
circumstances that indicate a transaction is not orderly and emphasizes that
even if there has been a significant decrease in the volume and level of
activity for the asset or liability and regardless of the valuation technique(s)
used, the objective of a fair value measurement remains the same. Fair value is
the price that would be received to sell an asset or paid to transfer a
liability in an orderly transaction (that is, not a forced liquidation or
distressed sale) between market participants at the measurement date under
current market conditions.  FSP FAS 157-4 is effective for interim and
annual reporting periods ending after June 15, 2009, and is applied
prospectively. The Partnership does not believe that the adoption of FSP FAS
157-2 will have a material impact on its consolidated financial
statements.





In April
2009, the FASB issued FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value
of Financial Instruments(“FSP FAS 107-1 and APB 28-1”). FSP FAS 107-1 and APB 28-1
amends FASB Statement No. 107, Disclosures about Fair Value of
Financial Instruments, to require disclosures about fair value of
financial instruments for interim reporting periods of publicly traded companies
as well as in annual financial statements.  FSP FAS 107-1 and APB 28-1
also amends APB Opinion No. 28, Interim Financial Reporting,
to require those disclosures in summarized financial information at interim
reporting periods. FSP FAS 107-1 and APB 28-1 is effective for interim and
annual reporting periods ending after June 15, 2009.  The Partnership
does not believe that the adoption of FSP FAS 107-1 and APB 28-1 will have a
material impact on its consolidated financial statements.




NOTE 4. ACQUISITIONS




2008
Acquisitions




Update on Millennium
Acquisition.  With respect to the South Louisiana assets
acquired in the acquisition of Millennium Midstream Partners, L.P. (“MMP”), 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 Partnership has reported, is


8
 Table of Contents


preparing
to file claims for, and expects to receive payment for physical damage and
business interruption caused by Hurricanes Ike and Gustav. The timing of
collection of such insurance claims is unknown at this time.  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 Ike and Gustav 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, 2008, the escrow
account held 1,777,302 common units and $0.3 million in cash.  During
the three months ended March 31, 2009, the Partnership recovered an additional
65,841 common units and the remaining $0.3 million in cash from the escrow
account.  On April 22, 2009, we recovered an additional 410,733 common
units from the escrow account and $0.1 million representing the distribution for
the fourth quarter of 2008 that was paid into escrow on 342,609 of those units,
per an arrangement with the sellers that the fourth quarter 2008 distribution on
certain units cancelled as part of the purchase price adjustment should be
returned to the Partnership upon cancellation.





NOTE
5. FIXED ASSETS AND ASSET RETIREMENT OBLIGATIONS




Fixed
assets consisted of the following:







March
      31,
              2009
            
            
            December
      31,
              2008($
      in thousands)Land
            
            $
            1,277
            
            
            $
            1,211Plant
            
            
            240,897
            
            
            
            232,219Gathering
      and pipeline
            
            
            662,720
            
            
            
            653,016Equipment
      and machinery
            
            
            18,106
            
            
            
            18,672Vehicles
      and transportation equipment
            
            
            4,157
            
            
            
            3,958Office
      equipment, furniture, and fixtures
            
            
            1,248
            
            
            
            1,023Computer
      equipment
            
            
            4,714
            
            
            
            4,714Corporate
            
            
            126
            
            
            
            126Linefill
            
            
            4,269
            
            
            
            4,269Proved
      properties
            
            
            516,656
            
            
            
            515,452Unproved
      properties
            
            
            73,779
            
            
            
            73,622Construction
      in progress
            
            
            31,173
            
            
            
            39,4981,559,122
            
            
            
            1,547,780Less:
      accumulated depreciation, depletion and amortization
            
            
            (214,698
            )
            
            
            (190,171
            )Net
      fixed assets
            
            $
            1,344,424
            
            
            $
            1,357,609




Depreciation
expense for the three months ended March 31, 2009 and 2008 was
approximately $13.2 million and $10.8 million, respectively. Depletion expense
for three months ended March 31, 2009 and 2008 was approximately $11.1
million and $10.3 million, respectively.  In connection with the
preparation of these financial statements for the three months ended March 31,
2009, the Partnership recorded impairment charges related to its proved property
assets of $0.2 million.  During the three months ended March 31, 2008,
the Partnership did not incur any impairment charges.




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, 2009 and 2008, the
Partnership capitalized interest costs of approximately $0.1 million and $0.3
million, respectively.




Asset Retirement
Obligations—The Partnership recognizes asset retirement obligations for
its oil and gas working interests in accordance with FASB Statement
No. 143, Accounting for
Asset Retirement Obligations (“SFAS 143”). SFAS 143 applies to
obligations associated with the retirement of tangible long-lived assets that
result from the acquisition, construction and development of the assets. SFAS
143 requires that the Partnership record 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 FASB Interpretation No. 47, Accounting for Conditional Asset
Retirement Obligations, an interpretation of FASB Statement No. 143(“FIN 47”). FIN 47 clarified that the term “conditional asset retirement
obligation,” as used in SFAS No. 143, Accounting for Asset Retirement
Obligations,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


9
 Table of Contents


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 if the fair value of the liability can be reasonably
estimated.




A
reconciliation of our liability for asset retirement obligations is as follows
(in thousands):




Asset
      retirement obligations—December 31, 2008
            
            $
            19,872Accretion
      expense
            
            
            279Asset
      retirement obligations—March 31, 2009
            
            $
            20,151




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 and $4.6
million for the three months ended March 31, 2009 and 2008, respectively.
Estimated aggregate amortization expense for 2009 and each of the four
succeeding years is as follows: 2009—$22.9 million; 2010—$21.9 million;
2011—$11.2 million; 2012—$11.2 million; and 2013—$10.1 million. Intangible
assets consisted of the following:




March 31,
              2009
            
            
            December 31,
              2008($
      in thousands)Rights-of-way
      and easements—at cost
            
            $
            86,255
            
            
            $
            85,537Less:
      accumulated amortization
            
            
            (12,134
            )
            
            
            (11,437
            )Contracts
            
            
            123,409
            
            
            
            123,409Less:
      accumulated amortization
            
            
            (47,981
            )
            
            
            (43,303
            )Net
      intangible assets
            
            $
            149,549
            
            
            $
            154,206




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, 2009.




NOTE
7. LONG-TERM DEBT




As of March 31, 2009 and December 31,
2008, the Partnership had $837.4 million and $799.4 million outstanding,
respectively, under its revolving credit facility.  As of March 31,
2009, the Partnership was in compliance with the financial covenants under its
revolving credit facility and the unused capacity available to the Partnership
under the revolving credit facility was approximately $134 million (excluding
the commitment from Lehman Brothers), based on the financial covenants.  As a result of
(i) our borrowing base redetermination in April 2009, which lowered our
borrowing base from $206 million to $135 million, and (ii) approximately $17
million of debt repayment since March 31, 2009, as of the date of this filing
our availability under the revolving credit facility is approximately $100
million – a 26% reduction from our availability as of March 31,
2009.




NOTE
8. MEMBERS’ EQUITY




At
March 31, 2009, there were 53,043,767 common units (excluding unvested
restricted common units), 20,691,495 subordinated units (all subordinated units
owned by Holdings) and 844,551 general partner units outstanding. In addition,
there were 931,226 unvested restricted common units outstanding.




Subordinated
units represent limited liability interests in the Partnership, and holders of
subordinated units exercise the rights and privileges available to unitholders
under the limited liability 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 September 30, 2009 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


10
 Table of Contents


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.




On
February 4, 2009, the Partnership declared its fourth quarter 2008 cash
distribution to all its unitholders (i.e. common, including unvested restricted
units, general and subordinated) of record as of February 10, 2009. The
distribution amount was $0.41 per unit, or approximately $31.6 million. The
distribution was paid on February 13, 2009.




On
April 30, 2009, the Partnership declared a cash distribution of $0.025 per
unit on its common units for the first quarter ending March 31, 2009. In
addition, pursuant to the terms of the Partnership’s partnership agreement, the
Partnership’s general partner will receive a distribution of $0.025 per general
partner unit on May 11, 2009.  The distribution will be paid
May 15, 2009, to the general partner and all common unitholders of record
as of May 11, 2009.




NOTE
9. RELATED PARTY TRANSACTIONS




On
July 1, 2006, the Partnership entered into a month-to-month contract for
the sale of natural gas with an affiliate of Natural Gas Partners, under which
the Partnership sells a portion of its gas supply.  In July 2008, the
company to which the Partnership sold its natural gas was sold by the affiliate
of NGP and thus ceased being a related party.  For the three months
ended March 31, 2008, during which such counterparty was an affiliate, the
Partnership recorded revenues of $16.0 million.




In
addition, during the three months ended March 31, 2009 and 2008, the Partnership
incurred $0.1 million and $0.6 million, respectively, in expenses with related
parties, of which there was an outstanding accounts payable balance of $0.0
million and $0.7 million, respectively, as of March 31, 2009 and
December 31, 2008.




Related
to its investments in unconsolidated subsidiaries, during the three months ended
March 31, 2009 and 2008, the Partnership recorded income of $0.5 million and
$4.0 million, respectively, of which there was no outstanding account receivable
balances as of March 31, 2009 and December 31, 2008.




During
the three month period ended March 31, 2009, the Partnership incurred
approximately $0.2 million for services performed by Stanolind Field Services
(“SFS”), which is an entity controlled by NGP and certain individuals, including
one employee of Eagle Rock Energy G&P, LLC, of which there were no
outstanding accounts payable balance as of March 31, 2009.




As of
March 31, 2009 and December 31, 2008, Eagle Rock Energy G&P, LLC had $11.7
million and $4.5 million, respectively, 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.




NOTE
10. FAIR VALUE OF FINANCIAL INSTRUMENTS




Effective
January 1, 2008, the Partnership adopted SFAS No. 157, which, among other
things, requires enhanced disclosures about assets and liabilities carried at
fair value.




As
defined in SFAS No. 157, 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. SFAS No. 157 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 defined by SFAS No. 157 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


11
 Table of Contents




measures.
Substantially all of these assumptions are observable in the market place
throughout the full term of the instrument, can be derived from observable data
or are supported by observable levels at which transactions are executed in the
marketplace.




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




As of
March 31, 2009, 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
following table discloses the fair value of the Partnership’s derivative
instruments as of March 31, 2009.




Level 1
            
            
            Level 2
            
            
            Level 3
            
            
            Total($
      in thousands)Assets:Crude
      derivatives
            
            $
            —
            
            
            $
            99,266
            
            
            $
            —
            
            
            $
            99,266Natural
      gas derivatives
            
            
            —
            
            
            
            15,566
            
            
            
            —
            
            
            
            15,566NGL
      derivatives
            
            
            —
            
            
            
            —
            
            
            
            11,447
            
            
            
            11,447Total
            
            $
            —
            
            
            $
            114,832
            
            
            $
            11,447
            
            
            $
            126,279Liabilities:Crude
      derivatives
            
            $
            —
            
            
            $
            (7,941
            )
            
            $
            —
            
            
            $
            (7,941
            )Natural
      gas derivatives
            
            
            —
            
            
            
            258
            
            
            
            —
            
            
            
            258Interest
      rate swaps
            
            
            —
            
            
            
            (36,846
            )
            
            
            —
            
            
            
            (36,846
            )Total
            
            $
            —
            
            
            $
            (44,529
            )
            
            $
            —
            
            
            $
            (44,529
            )




As of
March 31, 2009, 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 $31.9 million and $1.7 million,
respectively.




The
following table sets forth a reconciliation primarily of changes in the fair
value of the NGL derivatives classified as Level 3 in the fair value hierarchy
(in thousands):




Balances
      as of January 1, 2009
            
            $
            14,016Total
      gains or losses (realized and unrealized)
            
            
            809Settlements
            
            
            (3,378
            )Net
      liability balances as of March 31, 2009
            
            $
            11,447





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




Realized
and unrealized losses related to the interest rate derivatives are recorded as
part of interest rate risk management gains and losses in the 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 Consolidated Statements of Operations.




12
 Table of Contents






The
following table discloses the fair value of the Partnership’s assets measured at
fair value on a nonrecurring basis for the three months ended March 31, 2009 (in
thousands):




March
      31,
              2009
            
            
            Level 1
            
            
            Level 2
            
            
            Level 3
            
            
            Total
              LossesImpaired
      proved properties
            
            $
            49
            
            
            $
            —
            
            
            $
            —
            
            
            $
            49
            
            
            $
            242




In
connection with the preparation of these financial statements for the three
months ended March 31, 2009, the Partnership wrote down proved properties with a
carrying value of $0.3 million to their fair value of $0.1 million, resulting in
an impairment charge of $0.2 million being included in earnings for the
period.  The Partnership calculated the fair value of the impaired
proved properties using its proved reserves, estimated forward prices and an
estimated weighted average cost of capital.




The
carrying amount of cash equivalents is believed to approximate their fair values
because of the short maturities of these instruments.  The fair value
of accounts receivable and accounts payable are not materially different from
their carrying amounts because of the short-term nature of these
instruments.  As of March 31, 2009, the debt associated with the
revolving credit facility bore interest at floating rates.






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, 2009:





Roll
      Forward
              Effective
      Date
            
            Expiration
              Date
            
            Notional
              Amount
            
            Fixed
              Rate(a)12/31/2008
            
            12/31/2012
            
            $150,000,000
            
            2.360%
      / 2.560%09/30/2008
            
            12/31/2012
            
            150,000,000
            
            4.105%
      / 4.295%10/03/2008
            
            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.




Our
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 Partnership’s cash flows and affect its
ability to achieve its distribution objective and its covenants within 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.  In order to accomplish this, the
Partnership 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 recognizes that hedging


13
 Table of Contents


100% of
its future expected production is not prudent, thus it generally limits its
hedging levels to 80% of expected future production.   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.  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 avoid situations where a modest loss of production would put it
in an over-hedged position.  Expected future production for its
Upstream and Minerals Businesses is derived from the proved reserves, adjusted
for price-dependent expenses and revenue deductions, while 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 volumes
from future drilling are based on information it receives from operators and its
historical observations. The Partnership applies the appropriate contract terms
to these projections to determine its 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.  The
rationale for this practice is that the 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.   In the case where ethane is hedged with natural gas
derivatives, the conversion is based on the thermal content of
ethane.




Currently
these activities are governed by the general partner, which today prohibits
speculative transactions and limits the type, maturity and notional amounts of
derivative transactions. The Partnership has implemented a risk management
policy which will allow 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.




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.




Our
commodity derivative counterparties include BNP Paribas, Wells Fargo Bank N.A. /
Wachovia Bank N.A, Comerica Bank, Barclays Bank PLC, Sempra Energy Trading LLC
(an agent of The Royal Bank of Scotland plc) and its agent Sempra Energy Trading
LLC, Bank of America N.A., J Aron and Company (an affiliate of Goldman Sachs)
and British Petroleum.




On
January 8, 2009, the Partnership executed a series of hedging transactions that
involved the unwinding of a portion of existing “in-the-money” 2011 and 2012 WTI
crude oil swaps and collars, and the unwinding of two “in-the-money” 2009 WTI
crude oil collars. With these transactions, and an additional $13.9 million of
cash, the Partnership purchased a 2009 WTI crude oil swap on 60,000 barrels per
month beginning January 1, 2009 at $97 per barrel. Both the unwound hedges and
new hedges relate to expected volumes in the Partnership’s Midstream and
Minerals Segments.




In
addition to the hedging transactions discussed above, the Partnership also
entered into a 125,000 MMBtu per month Henry Hub natural gas swap at $6.65/MMBtu
on January 19, 2009 for the 2009 calendar year.




14
 Table of Contents




The
following table, as of March 31, 2009, sets forth certain information regarding
our commodity derivatives that will mature during the year ended
December 31, 2009 (excluding transactions and volumes that settled or were
unwound during the three months ended March 31, 2009):






Underlying
            
            Period
            
            Total
              Notional
              Volumes
              (units)
            
            Type
            
            Floor
              Strike
              Price
              ($/unit)
            
            
            Cap
              Strike
              Price
              ($/unit)Natural
      Gas:IF
      Waha
            
            Apr-Jun 2009
            
            60,000
      mmbtu
            
            Costless
      Collar
            
            
            7.50
            
            
            
            7.95IF
      Waha
            
            Jul-Sep
      2009
            
            60,000
      mmbtu
            
            Costless
      Collar
            
            
            7.50
            
            
            
            8.60IF
      Waha
            
            Oct-Dec
      2009
            
            60,000
      mmbtu
            
            Costless
      Collar
            
            
            7.50
            
            
            
            8.90NYMEX
      Henry Hub
            
            Apr-Dec
      2009
            
            160,000 mmbtu
            
            Costless
      Collar
            
            
            6.25
            
            
            
            11.20NYMEX
      Henry Hub
            
            Apr-Dec
      2009
            
            680,000 mmbtu
            
            Costless
      Collar
            
            
            7.85
            
            
            
            9.25NYMEX
      Henry Hub
            
            Apr-May
      2009
            
            40,000
      mmbtu
            
            Put
            
            
            7.00NYMEX
      Henry Hub
            
            Apr-Dec
      2009
            
            680,000 mmbtu
            
            Swap
            
            
            8.35NYMEX
      Henry Hub
            
            Apr-Dec
      2009
            
            560,000 mmbtu
            
            Swap
            
            
            6.685NYMEX
      Henry Hub
            
            Jun-Dec
      2009
            
            490,000 mmbtu
            
            Swap
            
            
            6.885Crude
      Oil:NYMEX
      WTI
            
            Apr-May
      2009
            
            14,000
      bbls
            
            Costless
      Collar
            
            
            60.00
            
            
            
            80.75NYMEX
      WTI
            
            Apr-Dec
      2009
            
            54,000
      bbls
            
            Costless
      Collar
            
            
            60.00
            
            
            
            77.00NYMEX
      WTI
            
            Apr-Dec
      2009
            
            90,000
      bbls
            
            Costless
      Collar
            
            
            93.00
            
            
            
            100.85NYMEX
      WTI
            
            Apr-Dec
      2009
            
            45,000
      bbls
            
            Put
            
            
            90.00NYMEX
      WTI
            
            Apr-Dec
      2009
            
            63,000
      bbls
            
            Put
            
            
            100.00NYMEX
      WTI
            
            Apr-Dec
      2009
            
            225,000 bbls
            
            Swap
            
            
            71.25NYMEX
      WTI
            
            Apr-Dec
      2009
            
            450,000 bbls
            
            Swap
            
            
            100.00NYMEX
      WTI
            
            Apr-Dec
      2009
            
            450,000 bbls
            
            Swap
            
            
            97.00Natural
      Gas Liquids:OPIS
      Ethane Mt Belv non TET
            
            Apr-Dec
      2009
            
            3,780,000 gallons
            
            Costless
      Collar
            
            
            0.48
            
            
            
            0.58OPIS
      Ethane Mt Belv non TET
            
            Apr-Dec
      2009
            
            3,780,000 gallons
            
            Swap
            
            
            0.53OPIS
      Ethane Mt Belv non TET
            
            Apr-Dec
      2009
            
            9,450,000 gallons
            
            Swap
            
            
            0.6361OPIS
      IsoButane Mt Belv non TET
            
            Apr-Dec
      2009
            
            945,000 gallons
            
            Costless
      Collar
            
            
            0.935
            
            
            
            1.035OPIS
      IsoButane Mt Belv non TET
            
            Apr-Dec
      2009
            
            945,000 gallons
            
            Swap
            
            
            0.985OPIS
      IsoButane Mt Belv non TET
            
            Apr-Dec
      2009
            
            1,134,378 gallons
            
            Swap
            
            
            1.295OPIS
      NButane Mt Belv non TET
            
            Apr-Dec
      2009
            
            2,079,000 gallons
            
            Costless
      Collar
            
            
            0.935
            
            
            
            1.035OPIS
      NButane Mt Belv non TET
            
            Apr-Dec
      2009
            
            2,079,000 gallons
            
            Swap
            
            
            0.985OPIS
      NButane Mt Belv non TET
            
            Apr-Dec
      2009
            
            2,283,750 gallons
            
            Swap
            
            
            1.2775OPIS
      Propane Mt Belv non TET
            
            Apr-Dec
      2009
            
            3,969,000 gallons
            
            Costless
      Collar
            
            
            0.765
            
            
            
            0.815OPIS
      Propane Mt Belv non TET
            
            Apr-Dec
      2009
            
            3,969,000 gallons
            
            Swap
            
            
            0.815OPIS
      Propane Mt Belv non TET
            
            Apr-Dec
      2009
            
            5,570,000 gallons
            
            Swap
            
            
            1.0925OPIS
      Propane Mt Belv non TET
            
            Apr-Dec
      2009
            
            2,179,800 gallons
            
            Swap
            
            
            1.0775OPIS
      Propane Mt Belv non TET
            
            Apr-Dec
      2009
            
            970,242 gallons
            
            Swap
            
            
            1.0775







During
the three months ended March 31, 2009, the Partnership entered into the
following derivative transactions for the 2010 calendar year: a 170,000 MMBtu
per month Henry Hub natural gas swap at $6.14 per MMBtu on February 17, 2009, a
45,000 barrel per month WTI crude oil swap at $53.55 per barrel on February 17,
2009 and a 40,000 barrel per month WTI crude oil swap at $51.40 per barrel on
February 19, 2009.


15
 Table of Contents




The
following table, as of March 31, 2009, sets forth certain information regarding
our commodity derivatives that will mature during the year ended
December 31, 2010:




Underlying
            
            Period
            
            Total
              Notional
              Volumes
              (units)
            
            Type
            
            Floor
              Strike
              Price
              ($/unit)
            
            
            Cap
              Strike
              Price
              ($/unit)Natural
      Gas:NYMEX
      Henry Hub
            
            Jan-Dec
      2010
            
            1,320,000 mmbtu
            
            Costless
      Collar
            
            $
            7.70
            
            
            $
            9.10NYMEX
      Henry Hub
            
            Jan-Dec
      2010
            
            2,040,000 mmbtu
            
            Swap
            
            
            6.14Crude
      Oil:NYMEX
      WTI
            
            Jan-Dec
      2010
            
            60,000
      bbls
            
            Costless
      Collar
            
            
            50.00
            
            
            
            67.50NYMEX
      WTI
            
            Jan-Dec
      2010
            
            60,000
      bbls
            
            Costless
      Collar
            
            
            50.00
            
            
            
            68.00NYMEX
      WTI
            
            Jan-Dec
      2010
            
            108,000 bbls
            
            Costless
      Collar
            
            
            90.00
            
            
            
            99.80NYMEX
      WTI
            
            Jan-Dec
      2010
            
            180,000 bbls
            
            Costless
      Collar
            
            
            50.00
            
            
            
            67.50NYMEX
      WTI
            
            Jan-Dec
      2010
            
            180,000 bbls
            
            Costless
      Collar
            
            
            50.00
            
            
            
            68.00NYMEX
      WTI
            
            Jan-Dec
      2010
            
            60,000
      bbls
            
            Put
            
            
            100.00NYMEX
      WTI
            
            Jan-Dec
      2010
            
            72,000
      bbls
            
            Put
            
            
            90.00NYMEX
      WTI
            
            Jan-Dec
      2010
            
            120,000 bbls
            
            Swap
            
            
            78.35NYMEX
      WTI
            
            Jan-Dec
      2010
            
            300,000 bbls
            
            Swap
            
            
            70.00NYMEX
      WTI
            
            Jan-Dec
      2010
            
            540,000 bbls
            
            Swap
            
            
            53.55NYMEX
      WTI
            
            Jan-Dec
      2010
            
            480,000 bbls
            
            Swap
            
            
            51.40Natural
      Gas Liquids:OPIS
      Ethane Mt Belv non TET
            
            Jan-Dec
      2010
            
            4,536,000 gallons
            
            Costless
      Collar
            
            
            0.43
            
            
            
            0.53OPIS
      Ethane Mt Belv non TET
            
            Jan-Dec
      2010
            
            4,536,000 gallons
            
            Swap
            
            
            0.58OPIS
      IsoButane Mt Belv non TET
            
            Jan-Dec
      2010
            
            2,520,000 gallons
            
            Costless
      Collar
            
            
            0.82
            
            
            
            1.02OPIS
      IsoButane Mt Belv non TET
            
            Jan-Dec
      2010
            
            5,544,000 gallons
            
            Costless
      Collar
            
            
            0.82
            
            
            
            1.02OPIS
      IsoButane Mt Belv non TET
            
            Jan-Dec
      2010
            
            5,040,000 gallons
            
            Costless
      Collar
            
            
            0.705
            
            
            
            0.81OPIS
      IsoButane Mt Belv non TET
            
            Jan-Dec
      2010
            
            5,040,000 gallons
            
            Swap
            
            
            0.755







On March
31, 2009, the Partnership entered into a 30,000 barrel per month NYMEX WTI swap
at $65.60 per barrel for the 2011 calendar year.  The following table,
as of March 31, 2009, sets forth certain information regarding our commodity
derivatives that will mature during the year ended December 31,
2011:




Underlying
            
            Period
            
            Total
              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
            
            
            $
            8.85Crude
      Oil:NYMEX
      WTI(1)
            
            Jan-Dec
      2011
            
            139,152 bbls
            
            Costless
      Collar
            
            
            75.00
            
            
            
            85.70NYMEX
      WTI(2)
            
            Jan-Dec
      2011
            
            125,256 bbls
            
            Swap
            
            
            80.00NYMEX
      WTI
            
            Jan-Dec
      2011
            
            360,000 bbls
            
            Swap
            
            
            65.60





(1)
            460,848
      barrels of this costless collar were “unwound” as part of the January 8,
      2009 hedge transactions.


(2)
            414,744
      barrels of this swap were “unwound” as part of the January 8, 2009 hedge
      transactions.








16
 Table of Contents




The
following table, as of March 31, 2009, sets forth certain information regarding
our commodity derivatives that will mature during the year ended
December 31, 2012:






Underlying
            
            Period
            
            Total
              Notional
              Volumes
              (units)
            
            Type
            
            Floor
              Strike
              Price
              ($/unit)
            
            
            Cap
              Strike
              Price
              ($/unit)NYMEX
      Henry Hub
            
            Jan-Dec
      2012
            
            1,080,000 mmbtu
            
            Costless
      Collar
            
            $
            7.35
            
            
            $
            8.65NYMEX
      WTI(1)
            
            Jan-Dec
      2012
            
            135,576 bbls
            
            Costless
      Collar
            
            
            75.30
            
            
            
            86.30NYMEX
      WTI(2)
            
            Jan-Dec
      2012
            
            108,468 bbls
            
            Swap
            
            
            80.30





(1)
            464,424
      barrels of this costless collar were “unwound” as part of the January 8,
      2009 hedge transactions.


(2)
            371,532
      barrels of this swap were “unwound” as part of the January 8, 2009 hedge
      transactions.




On April
1, 2009, the Partnership entered into a 10,000 barrel per month NYMEX WTI swap
at $65.10 per barrel for the 2011 calendar year and a 20,000 barrel per month
NYMEX WTI swap at $68.30 per barrel for the 2012 calendar year.




Fair
Value of Interest Rate and Commodity Derivatives




Fair
values of interest rate and commodity derivative instruments not designated as
hedging instruments under SFAS No. 133 in the Condensed Consolidated Balance
Sheet as of March 31, 2009 and December 31, 2008:




Derivative
      Assets
            
            Derivative
      LiabilitiesMarch
      31, 2009
            
            December
      31, 2008
            
            March
      31, 2009
            
            December
      31, 2008Balance
              Sheet
              Location
            
            Fair
      Value
            
            Balance
              Sheet
              Location
            
            Fair
      Value
            
            Balance
              Sheet
              Location
            
            Fair
      Value
            
            Balance
              Sheet
              Location
            
            Fair
      Value($
      in thousands)Interest
      rate derivatives – liabilities
            
            
            $
            —
            
            
            
            $
            —
            
            Current
      liabilities
            
            $
            (14,505
            )
            Current
      liabilities
            
            $
            (13,763
            )Interest
      rate derivatives – liabilities
            
            
            
            —
            
            
            
            
            —
            
            Long-term
      liabilities
            
            
            (22,341
            )
            Long-term
      liabilities
            
            
            (26,182
            )Commodity
      derivatives – assets
            Current
      assets
            
            
            112,401
            
            Current
      assets
            
            
            77,603
            
            
            
            
            —
            
            
            
            
            —Commodity
      derivatives – assets
            Long-term
      assets
            
            
            19,413
            
            Long-term
      assets
            
            
            34,088
            
            Long-term
      liabilities
            
            
            258
            
            
            
            
            —Commodity
      derivatives – liabilities
            Current
      assets
            
            
            (3,562
            )
            Current
      assets
            
            
            (834
            )
            Long-term
      liabilities
            
            
            (7,941
            )
            
            
            
            —Commodity
      derivatives – liabilities
            Long-term
      assets
            
            
            (1,973
            )
            Long-term
      assets
            
            
            (1,637
            )
            
            
            
            —
            
            
            
            
            —Total
      derivatives
            
            
            $
            126,279
            
            
            
            $
            109,220
            
            
            
            $
            (44,529
            )
            
            
            $
            (39,945
            )







The
following table sets forth the location of gains and losses for derivatives not
designated as hedging instruments under SFAS No. 133 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 31,2009
            
            
            2008($
      in thousands)Interest
      rate derivatives
            
            Interest
      rate risk management gains (losses)
            
            $
            (383
            )
            
            $
            (13,761
            )Commodity
      derivatives
            
            Commodity
      risk management gains (losses)
            
            
            26,256
            
            
            
            (45,647
            )Total
            
            
            
            $
            25,873
            
            
            $
            (59,408
            )







17
 Table of Contents




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 $0.1 million as of March 31, 2009 and
December 31, 2008 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. For the indemnified lawsuits, the Partnership has
not established any accruals as the likelihood of these suits being successful
against it is considered remote. 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 limits of the indemnification. These
matters are not expected to have a material adverse effect on our financial
position, results of operations or cash flows.




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
coverage’s 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, 2009 and December 31, 2008, the
Partnership had accrued approximately $8.6 million 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. This auditing has been and is being undertaken pursuant to
the Texas Environmental, Health and Safety Audit Privilege Act, as amended. The
Partnership has begun making the disclosures to the Texas Commission on
Environmental Quality (“TCEQ”) as a result of the completion of the first of
these self-audits, and it is addressing in due course the deficiencies that it
disclosed therein.  The Partnership does not foresee at this time any
impediment to its successful conclusion of these audits and the resulting
corrective effort.




During
the three months ended March 31, 2009, the Partnership received additional
Notices of Enforcement (“NOEs”) and a Notice of Violation (“NOV”) from the TCEQ
related to air compliance matters in the Texas Panhandle Segment.  The
Partnership expects to receive additional NOEs or NOVs from the TCEQ from time
to time throughout 2009.  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.


18
 Table of Contents




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 are expected to begin in 2010 and
continue through the end of 2019.




Other Commitments—The
Partnership utilizes assets under operating leases for its corporate office,
certain rights-of way and facilities locations, vehicles and in several areas of
its operation. Rental expense, including leases with no continuing commitment,
amounted to approximately, $2.3 million and $1.3 million for the three months
ended March 31, 2009 and March 31, 2008, respectively. Rental expense for leases
with escalation clauses is recognized on a straight-line basis over the initial
lease term.




NOTE
13. SEGMENTS




Based on
the Partnership’s approach to managing its assets, the Partnership believes its
operations consist of 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,
processing, transporting and marketing of natural gas in the Texas
Panhandle;




(ii)
            Midstream—South Texas
      Segment:




gathering,
processing, transporting and marketing of natural gas in South
Texas;




(iii)
            Midstream—East Texas/Louisiana
      Segment:




gathering,
processing and marketing of natural gas 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.







19
 Table of Contents


The
Partnership’s chief operating decision-maker currently reviews its operations
using these segments. The Partnership 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
      Segments
              Three
      Months Ended March 31, 2009
            
            Texas
              Panhandle
              Segment
            
            
            South
              Texas
              Segment
            
            
            East Texas /
              Louisiana
              Segment
            
            
            Gulf
      of
              Mexico
            
            
            Total
              Midstream
              Segments($
      in millions)Sales
      to external customers
            
            $
            65.7
            
            
            $
            26.0
            
            
            $
            54.7
            
            
            $
            6.3
            
            
            $
            152.7Cost
      of natural gas and natural gas liquids
            
            
            51.9
            
            
            
            23.7
            
            
            
            45.0
            
            
            
            5.2
            
            
            
            125.8Operating
      costs and other expenses
            
            
            8.1
            
            
            
            1.1
            
            
            
            4.6
            
            
            
            0.4
            
            
            
            14.2Depreciation,
      depletion, amortization and impairment
            
            
            11.1
            
            
            
            1.4
            
            
            
            4.8
            
            
            
            1.5
            
            
            
            18.8Operating
      income (loss) from continuing operations
            
            $
            (5.4
            )
            
            $
            (0.2
            )
            
            $
            0.3
            
            
            $
            (0.8
            )
            
            $
            (6.1
            )Capital
      Expenditures
            
            $
            3.1
            
            
            $
            0.0
            
            
            $
            9.1
            
            
            $
            0.1
            
            
            $
            12.3Segment
      Assets
            
            $
            526.2
            
            
            $
            76.8
            
            
            $
            359.4
            
            
            $
            90.1
            
            
            $
            1,052.5





Three
      Months Ended March 31, 2009
            
            Total
              Midstream
              Segments
            
            
            Upstream
              Segment
            
            
            Minerals
              Segment
            
            
            Corporate
              Segment
            
            
            Total
              Segments($
      in millions)Sales
      to external customers
            
            $
            152.7
            
            
            $
            9.7
            
            
            $
            3.2
            
            
            $
            26.3
            (a)
            
            $
            191.9Cost
      of natural gas and natural gas liquids
            
            
            125.8
            
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            125.8Operating
      costs and other expenses
            
            
            14.2
            
            
            
            6.5
            
            
            
            0.5
            
            
            
            12.6
            
            
            
            33.8Depreciation,
      depletion, amortization and impairment
            
            
            18.8
            
            
            
            9.6
            
            
            
            1.7
            
            
            
            0.2
            
            
            
            30.3Operating
      income (loss) from continuing operations
            
            $
            (6.1
            )
            
            $
            (6.4
            )
            
            $
            1.0
            
            
            $
            13.5
            
            
            $
            2.0Capital
      Expenditures
            
            $
            12.3
            
            
            $
            1.6
            
            
            $
            0.0
            
            
            $
            0.9
            
            
            $
            14.8Segment
      Assets
            
            $
            1,052.5
            
            
            $
            388.0
            
            
            $
            140.3
            
            
            $
            160.4
            
            
            $
            1,741.2




Midstream
      Segments
              Three
      Months Ended March 31, 2008
            
            Texas
              Panhandle
              Segment
            
            
            South
              Texas
              Segment
            
            
            East Texas /
              Louisiana
              Segment
            
            
            Total
              Midstream
              Segments($
      in millions)Sales
      to external customers
            
            $
            156.3
            
            
            $
            46.5
            
            
            $
            70.4
            
            
            $
            273.2Cost
      of natural gas and natural gas liquids
            
            
            120.1
            
            
            
            44.0
            
            
            
            60.0
            
            
            
            224.1Operating
      costs and other expenses
            
            
            7.7
            
            
            
            0.7
            
            
            
            3.5
            
            
            
            11.9Depreciation,
      depletion, and amortization
            
            
            10.7
            
            
            
            0.9
            
            
            
            2.9
            
            
            
            14.5Operating
      income from continuing operations
            
            $
            17.8
            
            
            $
            0.9
            
            
            $
            4.0
            
            
            $
            22.7Capital
      Expenditures
            
            $
            6.9
            
            
            $
            0.4
            
            
            $
            2.1
            
            
            $
            9.4Segment
      Assets
            
            $
            585.9
            
            
            $
            98.1
            
            
            $
            257.7
            
            
            $
            941.7




Three
      Months Ended March 31, 2008
            
            Total
              Midstream
              Segments
            
            
            Upstream
              Segment
            
            
            Minerals
              Segment
            
            
            Corporate
              Segment
            
            
            Total
              Segments($
      in millions)Sales
      to external customers
            
            $
            273.2
            
            
            $
            39.0
            
            
            $
            7.0
            
            
            $
            (45.7
            )(a)
            
            $
            273.5Cost
      of natural gas and natural gas liquids
            
            
            224.1
            
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            224.1Operating
      costs and other expenses
            
            
            11.9
            
            
            
            7.6
            
            
            
            0.4
            
            
            
            11.3
            
            
            
            31.2Depreciation,
      depletion, and amortization
            
            
            14.5
            
            
            
            8.4
            
            
            
            2.6
            
            
            
            0.2
            
            
            
            25.7Operating
      income (loss) from continuing operations
            
            $
            22.7
            
            
            $
            23.0
            
            
            $
            4.0
            
            
            $
            (57.2
            )
            
            $
            (7.5
            )Capital
      Expenditures
            
            $
            9.4
            
            
            $
            2.9
            
            
            $
            —
            
            
            $
            0.1
            
            
            $
            12.4Segment
      Assets
            
            $
            941.7
            
            
            $
            469.1
            
            
            $
            142.7
            
            
            $
            65.4
            
            
            $
            1,618.9


____________________


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





20
 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 of $0.9 million
and $0.1 million were used during the three months ended March 31, 2009 and
2008, respectively, which resulted in a partial release of the valuation
allowance established for the net operating losses as of December 31,
2008.




Effective Rate -The
effective rate for the three month period ended March 31, 2009 was 51.7%,
respectively compared to 100% for the same period in 2008.  The
changes in effective tax rates are attributable to the provision amounts for the
total of state and federal taxes being applied against book income for the three
months ended March 31, 2009.




DeferredTaxes -As of March 31, 2009,
the net deferred tax liability was $39.5 million compared to $42.3 million as of
December 31, 2008 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.




Accounting for Uncertainty in Income
Taxes -In accordance with FASB Interpretation No. 48, Accounting for Uncertainty in Income
Taxes, the Partnership must recognize the tax effects of any uncertain
tax positions it may adopt, if the position taken by the Partnership is more
likely than not sustainable.  If a tax position meets such criteria,
the tax effect to be recognized by the Partnership would be the largest amount
of benefit with more than a 50% chance of being realized upon settlement.This guidance was
effective January 1, 2007, and the Partnership’s adoption of this guidance had
and continues to have no material impact on its financial position, results of
operations or cash flows.




Texas Franchise Tax -On
May 18, 2006, the State of Texas enacted revisions to the pre-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.




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., approved 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 covering an aggregate of
2,000,000 common units to be granted either as options, restricted units or
phantom units.   The Partnership has historically only issued
restricted units under the LTIP.  As to outstanding restricted units,
distributions associated with the restricted units will be distributed directly
to the awardees. No options or phantom units have been issued to
date.




A summary
of the restricted common units’ activity for the three months ended
March 31, 2009, is provided below:




Number of
              Restricted
              Units
            
            
            Weighted
              Average
              Fair ValueOutstanding
      at December 31, 2008
            
            
            905,486
            
            
            $
            17.00Granted
            
            
            54,700
            
            
            $
            6.26Forfeitures
            
            
            (28,960
            )
            
            $
            15.39Outstanding
      at March 31, 2009
            
            
            931,226
            
            
            $
            16.42





No restricted units vested
during the three months ended March 31, 2009.


21
 Table of Contents


For the
three months ended March 31, 2009 and March 31, 2008, non-cash
compensation expense of approximately $1.8 million and $1.2 million,
respectively, was recorded related to the granted restricted units.




As of
March 31, 2009, unrecognized compensation costs related to the outstanding
restricted units under our LTIP totaled approximately $11.7 million. The
remaining expense is to be recognized over a weighted average of 1.8
years.




In
addition to equity awards involving units of the Partnership, Eagle Rock
Holdings, L.P., 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 ended March 31, 2009, Holdings granted 160,000 “Tier I” incentive
interests to one Eagle Rock Energy employee.  Under the guidance of
U.S. Securities and Exchange Commission Staff Accounting Bulletin Topic 1.B:
“Allocation Of Expenses And
Related Disclosure In Financial Statements Of Subsidiaries, Divisions Or Lesser
Business Components Of Another Entity,” the Partnership recorded a
portion of the value of the incentive units as compensation expense in the
Partnership’s 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.




NOTE
16.  EARNINGS PER UNIT




Basic
earnings per unit are computed by dividing the net income, or loss, by the
weighted average number of units outstanding during a period. To determine net
income, or 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.





On
January 1, 2009, the Partnership adopted the provisions of EITF 07-4, which
provides that for master limited partnerships (“MLPs”), current period earnings
be reduced by the amount of available cash that will be distributed with respect
to that period for purposes of calculating earnings per unit.  Any
residual amount representing undistributed earnings is assumed to be allocated
to the various ownership interests in accordance with the contractual provisions
of the partnership agreement.  In addition, incentive distribution
rights (“IDRs”), which represent a limited partnership ownership interest, are
considered to be participating securities because they have the right to
participate in earnings with common equity holders.





Under the
Partnership’s partnership agreement, for any quarterly period, 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, 2009 and 2008, the
Partnership did not declare a quarterly distribution for the IDRs.





On
January 1, 2009, the Partnership also adopted the provisions of FSP EITF 03-6-1,
which provides that share-based payment awards that contain non-forfeitable
rights to dividends or dividend equivalents meets the definition of a
participating security and shall be included in the computation of
earnings-per-unit pursuant to the two-class method, as provided by SFAS No. 128,
Earnings Per
Share.  The restricted common units granted under the LTIP, as
discussed in Note 15, contain non-forfeitable rights to the distributions
declared by the Partnership.




After
applying the provisions of EITF 07-4 and FSP EITF 03-6-1, net loss per common,
subordinated and general partner unit for the three months ended March 31, 2008
remained at $0.39.  Earnings per unit has not been separately
disclosed for the restricted common units, as they restricted common units are
not considered a separate class of equity.


22
 Table of Contents




The
following table presents the Partnership’s calculation of basic and diluted loss
per unit for the periods indicated:







Three
      Months Ended
              March 31,2009
            
            
            2008(In
      thousands, except for
              per
      unit amounts)Loss from continuing
      operations
            
            $
            (2,852
            )
            
            $
            (28,616
            )Distribution
      declared
            
            $
            1,368
            
            
            $
            29,077Assumed loss from continuing
      operations after distribution to be allocated
            
            $
            (4,220
            )
            
            $
            (57,693
            )Discontinued
      operations
            
            $
            307
            
            
            $
            288Assumed net loss after
      distribution to be allocated
            
            $
            (3,913
            )
            
            $
            (57,405
            )Distribution
      declared
            
            $
            1,368
            
            
            $
            29,077Assumed net loss to
      be
      allocated
            
            $
            (2,545
            )
            
            $
            (28,328
            )Assumed loss from continuing
      operations after distribution allocated to:Common
      units
            
            $
            (3,001
            )
            
            $
            (40,493
            )Subordinated
      units
            
            $
            (1,171
            )
            
            $
            (16,526
            )General
      partner units
            
            $
            (48
            )
            
            $
            (674
            )Discontinued operations
      allocated to:Common
      units
            
            $
            217
            
            
            $
            202Subordinated
      units
            
            $
            86
            
            
            $
            83General
      partner units
            
            $
            4
            
            
            $
            3Assumed net loss after
      distribution allocated to:Common
      units
            
            $
            (2,783
            )
            
            $
            (40,291
            )Subordinated
      units
            
            $
            (1,086
            )
            
            $
            (16,443
            )General
      partner units
            
            $
            (44
            )
            
            $
            (671
            )Distribution declared
      to:Common
      units
            
            $
            1,326
            
            
            $
            20,280Restricted
      common units
            
            $
            21
            
            
            $
            183Subordinated
      units
            
            $
            —
            
            
            $
            8,276General
      partner units
            
            $
            21
            
            
            $
            338Net loss and distribution
      allocated to:Common
      units
            
            $
            (1,457
            )
            
            $
            (20,011
            )Restricted
      common units
            
            $
            21
            
            
            $
            183Subordinated
      units
            
            $
            (1,086
            )
            
            $
            (8,167
            )General
      partner units
            
            $
            (23
            )
            
            $
            (333
            )Basic and diluted weighted
      average unit outstanding during period:Common
      units
            
            
            53,044
            
            
            
            50,700Subordinated
      units
            
            
            20,691
            
            
            
            20,691General
      partner units
            
            
            845
            
            
            
            845Basic
      and diluted loss from continuing operations per unit:Common
      units
            
            $
            (0.03
            )
            
            $
            (0.40
            )Subordinated
      units
            
            $
            (0.06
            )
            
            $
            (0.40
            )General
      partner units
            
            $
            (0.03
            )
            
            $
            (0.40
            )Basic
      and diluted discontinued operations per unit:Common
      units
            
            $
            0.00
            
            
            $
            0.00Subordinated
      units
            
            $
            0.00
            
            
            $
            0.00General
      partner units
            
            $
            0.00
            
            
            $
            0.00Basic
      and diluted loss per unit:Common
      units
            
            $
            (0.03
            )
            
            $
            (0.39
            )Subordinated
      units
            
            $
            (0.06
            )
            
            $
            (0.39
            )General
      partner units
            
            $
            (0.03
            )
            
            $
            (0.39
            )





23
 Table of Contents





NOTE 17.  SUBSEQUENT
EVENTS





On April
1, 2009, the Partnership sold its producer services business (which is accounted
for in its South Texas Segment) by assigning and novating the contracts under
this business to a third-party purchaser.  The Partnership assigned
these contracts to a third-party purchaser as it is a low-margin business that
is 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 will receive a contingency payment of up to $0.1 million in October,
2009, and it will receive a monthly payment equivalent to $0.01 per MMbtu on the
volume of gas that flows pursuant to the assigned contracts for the next two
years.  Producer services is 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, 2009, this
business generated revenues of $26.8 million and cost of natural gas and natural
gas liquids of $26.5 million, as compared to revenues of $52.0 million and cost
of natural gas and natural gas liquids of $51.7 million during the three months
ended March 31, 2008.  For the three months ended March 31, 2009 and
2008, $0.3 million of revenues minus the cost of natural gas and natural gas
liquids have been reported as discontinued operations.


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, 2008, filed with the Securities and Exchange Commission. For a
description of oil and natural gas terms, see such 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/Northern Louisiana. Our South Texas Segment consists of gathering systems
and related compression and processing facilities in South Texas, Central 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.  During the three months ended March 31, 2009, our
Midstream Business generated an operating loss from continuing operations of
$6.1 million, compared to operating income from continuing operations of $22.7
million during the three months ended March 31, 2008.




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.  During the three months ended March 31, 2009, our Upstream
Business generated an operating loss of $6.5 million, compared to operating
income of $23.0 million during the three months ended March 31,
2008.  Of important note, sales of sulfur generated revenues of ($0.4)
million during the three months ended March 31, 2009, compared to revenue of
$5.4 million generated during the three months ended March 31,
2008.




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 a
non-affiliated private partnership (the “Minerals Manager”) that controls the
executive rights associated with the minerals.  During the three
months ended March 31, 2009, our Minerals Business generated an operating income
of $1.1 million, compared to operating income of $3.9 million during the
three months ended March 31, 2008.  Included within these numbers is
lease bonus revenue of $0.6 million generated during the three months ended
March 31, 2009, compared to $1.1 million during the three months ended March 31,
2008.





The final
segment that we report on is our Corporate Segment, which is where we account
for our commodity derivative/hedging activity and our general and administrative
expenses.  During the three months ended March 31, 2009, our Corporate
Segment generated operating income of $13.5 million, compared to an operating
loss of $57.1 million during the three months ended March 31,
2008.  Within these numbers were gains, realized and unrealized, on
commodity derivatives of $26.3 million during the three months ended March 31,
2009, compared to losses, realized and unrealized, on commodity derivatives of
$45.6 million during the three months ended March 31, 2008.





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, operation of oil and natural gas
properties and assets, and management of 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”).





25
 Table of Contents


Impairment




In
connection with preparation of our Unaudited Condensed Consolidated Financial
Statements for the three months ended March 31, 2009, we determined that we
needed to record an impairment charge 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.




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, 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 with
Liquidity and Capital
Resources.




Below is
a summary of our important acquisition transactions completed during the year
ended December 31, 2008.




Stanolind Acquisition -On
April 30, 2008, we completed the acquisition of all of the outstanding capital
stock of Stanolind Oil and Gas Corp. (“Stanolind”).  Stanolind
operated crude oil and natural gas producing properties in the Permian Basin of
West Texas, primarily in Ward, Crane and Pecos Counties.




Millennium Acquisition -On
October 1, 2008, we 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.




Recent
Transactions




On April
1, 2009, we sold our producer services business (which is accounted for in our
South Texas Segment) by assigning and novating the contracts under this business
to a third-party purchaser.  We assigned these contracts to a
third-party purchaser as it is a low-margin business that is not core to the
Partnership’s operations.   We received an initial payment of
$0.1 million for the sale of the business.  In addition we will
receive a contingency payment of up to $0.1 million in October, 2009 and we will
receive a monthly payment equivalent to $0.01 per MMbtu on the volume of gas
that flows pursuant to the assigned contracts for the next two
years.  The producer services business was a low margin 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, 2009, this business generated revenues of $26.8 million and cost
of natural gas and natural gas liquids of $26.5 million, as compared to revenues
of $52.0 million and cost of natural gas and natural gas liquids of $51.7
million during the three months ended March 31, 2008. For the three months ended
March 31, 2009 and 2008, $0.3 million of revenues minus the cost of natural gas
and natural gas liquids have been reported as discontinued
operations.






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;
margins, operating expenses and Adjusted EBITDA (more fully described later
under “Non-GAAP Financial Measures”) on a company-wide basis.




26
 Table of Contents


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, 2008. More
significantly, recent events impacting the world’s economy and financial systems
will play an important role in the performance and growth prospects for our
business.  These recent events include but are not limited to:
continued turbulence in the world’s banking system and reduced availability of
credit on attractive terms; precipitous drops in the value of almost all asset
classes including equity, bonds, real estate, and other investment vehicles;
significant declines in commodity prices including the prices for crude oil,
natural gas, NGLs, condensate, and sulfur, among others; the significant
reaction to the fall in commodity prices by our 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 widespread expectation 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 or interpretations of available information
prove to be incorrect, our actual results may vary materially from our expected
results.





On April
29, 2009, we announced that we will pay a quarterly cash distribution of $0.025
per common unit for the quarter ended March 31, 2009, a reduction in the
distribution payment from the quarter ended December 31, 2008, which was $0.41
on all units.  The distribution will be paid on May 15, 2009 to our
common unitholders of record as of the close of business on May 11,
2009.  In addition, pursuant to the terms of our partnership
agreement, our general partner will receive a distribution of $0.025 per general
partner unit on May 11, 2009.





Additionally,
we announced that the borrowing base under our revolving credit facility, which
relates to our Upstream Business, was redetermined from $206 million as of March
31, 2009 to $135 million currently.  This reduction in the borrowing
base occurred in connection with a scheduled redetermination in accordance with
our revolving credit facility and is primarily the result of the deterioration
of commodity prices in the oil and natural gas industry.  After taking
into account this redetermination, we remain in compliance with the financial
and other covenants in our revolving credit facility.





In light
of the borrowing base redetermination and the deterioration of commodity prices
in the oil and natural gas industry, which has led to declines in our customers’
drilling activity and hydrocarbon throughput volumes in our gathering and
processing systems, as well as reduced revenues in our Upstream and Minerals
businesses, the Board of Directors has determined to create cash reserves for
the proper conduct of our business and to remain in compliance with financial
covenants under our revolving credit facility.  The cash not
distributed will be used primarily to reduce our outstanding debt under our
revolving credit facility and to continue the execution of our hedge strategy to
maintain future cash flows.  We anticipate continuing this strategy
until such time as the commodity prices in the oil and natural gas industry
improve and our customer’s increase the drilling activity and throughput volumes
in our gathering and processing systems and plants and the general economy
returns to levels conducive to increasing the cash distributions to be paid to
the unitholders.






Cautionary
Note Regarding Forward-Looking Statements




Certain
matters discussed in this report, excluding historical information, include
certain “forward-looking” statements within the meaning of Section 27A of
the Securities Act of 1933 and Section 21E of the Securities Exchange Act
of 1934. 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. 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. For additional discussion of risks, uncertainties and assumptions, see
our annual report on Form 10-K for the year ended December 31, 2008, filed
with the Securities and Exchange Commission on March 13, 2009 as well as the
risks disclosed in Part II, Item 1A below.







27
 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, 2009 and March 31, 2008, respectively. Operating results for
our individual operating segments are presented in tables in this
Item 2.







Three
      Months Ended
              March
      31,2009
            
            
            2008($
      in thousands)Revenues:Natural
      gas, natural gas liquids, oil, condensate and sulfur sales
            
            $
            150,652
            
            
            $
            304,974Gathering,
      compression, processing and treating services
            
            
            11,667
            
            
            
            7,143Minerals
      and royalty income
            
            
            3,239
            
            
            
            6,958Realized
      commodity derivative gains (losses)
            
            
            30,778
            
            
            
            (12,575
            )Unrealized
      commodity derivative gains (losses)
            
            
            (4,522
            )
            
            
            (33,072
            )Other
            
            
            42
            
            
            
            60Total
      revenues
            
            
            191,856
            
            
            
            273,488Cost
      of natural gas and natural gas liquids
            
            
            125,819
            
            
            
            224,074Expenses:Operations
      and maintenance
            
            
            18,201
            
            
            
            15,566Taxes
      other than income
            
            
            2,978
            
            
            
            4,347General
      and administrative
            
            
            12,538
            
            
            
            11,242Impairment
            
            
            242
            
            
            
            —Depreciation,
      depletion, and amortization
            
            
            30,063
            
            
            
            25,745Total
      costs and expenses
            
            
            189,841
            
            
            
            280,974Operating
      income (loss)
            
            
            2,015
            
            
            
            (7,486
            )Other
      income (expense):Interest
      income
            
            
            32
            
            
            
            301Other
      income
            
            
            560
            
            
            
            1,547Interest
      expense, net
            
            
            (7,539
            )
            
            
            (9,104
            )Unrealized
      interest rate derivative gains (losses)
            
            
            3,099
            
            
            
            (13,660
            )Realized
      interest rate derivative gains (losses)
            
            
            (3,482
            )
            
            
            (101
            )Other
      expense
            
            
            (267
            )
            
            
            (215
            )Total
      other income (expense)
            
            
            (7,597
            )
            
            
            (21,232
            )Loss
      from continuing operations before income taxes
            
            
            (5,582
            )
            
            
            (28,718
            )Income
      tax (benefit) provision
            
            
            (2,730
            )
            
            
            (102
            )Loss
      from continuing operations
            
            
            (2,852
            )
            
            
            (28,616
            )Discontinued
      operations
            
            
            307
            
            
            
            288Net
      loss
            
            $
            (2,545
            )
            
            $
            (28,328
            )Adjusted
      EBITDA(a)
            
            $
            41,105
            
            
            $
            52,490


____________________


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












28
 Table of Contents


Midstream
Business (Four Segments)




Texas
Panhandle Segment


Three Months Ending
              March
      31,2009
            
            
            2008($
      in thousands,
              except
      for realized prices)Revenues:Sales
      of natural gas, NGLs, oil and condensate
            
            $
            62,950
            
            
            $
            153,855Gathering
      and treating services
            
            
            2,813
            
            
            
            2,469Total
      revenues
            
            
            65,763
            
            
            
            156,324Cost
      of natural gas and natural gas liquids
            
            
            51,947
            
            
            
            120,118Operating
      costs and expenses:Operations
      and maintenance
            
            
            8,145
            
            
            
            7,748Depreciation
      and amortization
            
            
            11,096
            
            
            
            10,709Total
      operating costs and expenses
            
            
            19,241
            
            
            
            18,457Operating
      income (loss)
            
            $
            (5,425
            )
            
            $
            17,749Capital
      Expenditures
            
            $
            3,111
            
            
            $
            6,986Realized
      average prices:Oil
      and condensate (per Bbl)
            
            $
            47.23
            
            
            $
            90.80Natural
      gas (per Mcf)
            
            $
            3.45
            
            
            $
            7.41NGLs
      (per Bbl)
            
            $
            24.61
            
            
            $
            62.96Production
      volumes:Gathering
      volumes (Mfc/d)(a)
            
            
            144,203
            
            
            
            154,570NGLs
      (net equity gallons)
            
            
            10,635,049
            
            
            
            13,933,466Condensate
      (net equity gallons)
            
            
            6,192,426
            
            
            
            7,950,786Natural
      gas short position (MMbtu/d)(a)
            
            
            (6,141
            )
            
            
            (7,263
            )


____________________


(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 ofdays in the respective
      period.




Revenues and Cost of Natural Gas and
Natural Gas Liquids.For the three months ended March 31, 2009, the
revenues minus cost of natural gas and natural gas liquids for our Texas
Panhandle Segment operations totaled $13.8 million compared to $36.2
million for the three months ended March 31, 2008. There were two primary
contributors to this decrease: (i) lower NGL, natural gas and condensate
pricing, as compared to pricing in 2008, and (ii) lower NGL equity
production as compared to production in 2008.  The lower NGL equity
production was primarily due to lower gathered volumes in 2009 as compared to
2008 in the West Panhandle System of approximately 9.9% and operating the plants
in ethane rejection for much of the first two months of 2009.  Ethane
rejection operations will result in a lower volume of equity liquids that will
be offset by a smaller natural gas short position.  Ethane rejection
operations are where 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 tailgates of our plants.  We operate in
this manner when the value of ethane is worth more in the gas stream than
recovering the ethane and selling it as an NGL.




The lower
gathering volumes during the three months ended March 31, 2009 compared to the
same period in the prior year was due to reduced drilling activity during 2009
that was not sufficient to replace the natural volume declines in our West
Panhandle Systems and our East Panhandle System.   The dramatic
fall in commodity prices experienced in the fall of 2008 and early 2009 has
resulted in many of our producer customers significantly reducing drilling
activity in the Texas Panhandle, specifically in the Granite Wash play of the
East Panhandle System, until commodity prices rise to levels to justify economic
drilling decisions.




The
drilling activity in the West Panhandle System is not sufficient to offset the
natural declines experienced on the 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 strong growth in volumes and equity production due to the active
Granite Wash drilling play located in Roberts and Hemphill Counties, Texas
through much of 2008; however due to lower commodity values during the fourth
quarter of 2008 and continuing during the first three months of 2009, we are
seeing a significant


29
 Table of Contents


decline
in drilling activity. 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 to capture new volumes in the East Panhandle System from our
competitors 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, for three months ended
March 31, 2009 were $8.1 million compared to $7.7 million for the three
months ended March 31, 2008. The major item impacting the $0.4 million
increase in operating expense was an increase in environmental compliance costs
of about $0.3 million during the three months ended March 31, 2009 as compared
to the same period in the prior year.




Depreciation and
Amortization. Depreciation and amortization expenses for three months
ended March 31, 2009 were $11.1 million compared to $10.7 million for the
three months ended March 31, 2008.  The $0.4 million increase is
due to beginning the depreciation expense associated with capital expenditures
placed into service.




Capital Expenditures.Capital
expenditures for three months ended March 31, 2009 were $3.1 million
compared to $7.0 million for the three months ended March 31, 2008. We
classify capital expenditures as either maintenance capital which represents
routine well connects and capitalized maintenance activities or as growth
capital which represents organic growth projects. In the three months ended
March 31, 2009, growth capital represented 74% of our capital expenditures
as compared to 79% in the three months ended March 31, 2008. The decrease
in capital of $3.9 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 spent in the three months ending March 31,
2008.




East
Texas/Louisiana Segment


Three Months Ending
              March
      31,2009(b)
            
            
            2008($
      in thousands,
              except
      for realized prices)Revenues:Sales
      of natural gas, NGLs, oil and condensate
            
            $
            47,451
            
            
            $
            66,959Gathering
      and treating services
            
            
            7,209
            
            
            
            3,448Total
      revenues
            
            
            54,660
            
            
            
            70,407Cost
      of natural gas and natural gas liquids
            
            
            45,009
            
            
            
            60,019Operating
      costs and expenses:Operations
      and maintenance
            
            
            4,552
            
            
            
            3,480Depreciation
      and amortization
            
            
            4,771
            
            
            
            2,869Total
      operating costs and expenses
            
            
            9,323
            
            
            
            6,349Operating
      income (loss)
            
            $
            328
            
            
            $
            4,039Capital
      expenditures
            
            $
            9,096
            
            
            $
            2,051Realized
      average prices:Oil
      and condensate (per
      Bbl)
            
            $
            50.75
            
            
            $
            102.59Natural
      gas (per Mcf)
            
            $
            4.29
            
            
            $
            8.61NGLs
      (per Bbl)
            
            $
            18.98
            
            
            $
            52.52Production
      volumes:Gathering
      volumes (Mfc/d)(a)
            
            
            271,571
            
            
            
            163,817NGLs
      (net equity gallons)
            
            
            2,676,419
            
            
            
            4,950,723Condensate
      (net equity gallons)
            
            
            435,291
            
            
            
            352,875Natural
      gas long position (MMbtu/d)(a)
            
            
            3,277
            
            
            
            367


____________________


(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.


(b)
            Includes
      operations related to the Millennium Acquisition effective October 1,
      2008.


30
 Table of Contents


Revenues and Cost of Natural Gas and
Natural Gas Liquids. For the three months ended March 31, 2009,
revenues minus cost of natural gas and natural gas liquids for our East
Texas/Louisiana Segment totaled $9.7 million compared to $10.4 million for
the three months ended March 31, 2008.  The Millennium
Acquisition positively impacted the East Texas/Louisiana Segment’s revenue minus
cost of natural gas and natural gas liquids by $4.5 million during the three
months ended March 31, 2009.  Our lower NGL equity gallons were
primarily due to operating the facilities in ethane rejection during much of the
first two months of 2009. Ethane rejection operations are where 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
tailgates of our plants.  We operate in this manner when the value of
ethane is worth more in the gas stream than recovering the ethane and selling it
as an NGL.




We were
negatively impacted by lower NGL and condensate pricing during the three months
ended March 31, 2009 as compared to the three months ended March 31,
2008. We were positively impacted by a 66% gathering volume growth during the
three months ended March 31, 2009 compared to the three months ended
March 31, 2008. Volumes increased due to both the Millennium Acquisition
and continued drilling in the Austin Chalk play in Tyler and Jasper Counties,
Texas while other East Texas/Louisiana Segment gathering systems saw a reduction
in volumes. Excluding the Millennium Acquisition, our gathering volumes
decreased by 0.7%.  The offsetting reduction in higher margin gas
volumes is being replaced with lower margin, fixed fee, volumes from the
Millennium Acquisition.  The gas volumes from the Millennium
Acquisition are primarily dry gas that does not require processing to remove
NGLs prior to delivery to the interstate pipelines in order to meet the
pipelines’ gas quality tariff requirements.  The lower margin gas,
though contributing to a significant increase in overall gathered volumes, has
not offset the lower revenues and margins due to the lower NGL, condensate and
natural gas prices during the first three months of 2009 as compared to the same
time period in 2008.  We constructed a new seven mile lateral from our
Brookeland gathering system into an active Austin Chalk drilling area where we
have a large dedicated acreage position under a life-of-lease contract with an
active significant producer.  The production rates of wells drilled in
the Austin Chalk play are characterized by high initial decline rates;
therefore, operators must conduct active drilling programs if they are to
maintain or grow their production in this play.  During the last three
months of 2008 and continuing into the first three months of 2009, we saw a
significant reduction in drilling activity due to lower commodity
values.




Operating Expenses.Operating
expenses for the three months ended March 31, 2009 were $4.6 million
compared to $3.5 million in for the three months ended March 31, 2008. The
major items impacting the $1.1 million increase in operating expense was due to
the three months of expenses associated with operating the assets acquired
as part of the Millennium Acquisition.   Excluding operating the
assets acquired as part of the Millennium Acquisition, operating expenses were
relatively flat for the three months ended March 31, 2009 as compared to the
same period in 2008.




Depreciation and Amortization.Depreciation and amortization expenses for the three months ended
March 31, 2009 were $4.8 million compared to $2.9 million in for the three
months ended March 31, 2008. The major items impacting the $1.9 million
increase were (i) three months of depreciation and amortization of the assets
acquired as part of Millennium Acquisition and (ii) beginning the
depreciation expense associated with the capital expenditures placed into
service.




Capital Expenditures.Capital
expenditures for the three months ended March 31, 2009 were $9.1 million
compared to $2.1 million in for the three months ended March 31, 2008. We
classify capital expenditures as either maintenance capital which represents
routine well connects and capitalized maintenance activities or as growth
capital which represents organic growth projects. Our increase in capital
spending of $7.0 million is due primarily to the construction of gathering lines
to both the significant producer discussed above and two other producers in the
Brookeland and Tyler County gathering systems.







31
 Table of Contents




South
Texas Segment


Three Months Ending
              March 31,2009(b)
            
            
            2008($
      in thousands,
              except
      for realized prices)Revenues:Sales
      of natural gas, NGLs, oil and condensate
            
            $
            24,390
            
            
            $
            45,194Gathering
      and treating services
            
            
            1,557
            
            
            
            1,226Other
            
            
            3
            
            
            
            2Total
      revenues
            
            
            25,950
            
            
            
            46,422Cost
      of natural gas and natural gas liquids
            
            
            23,671
            
            
            
            43,937Operating
      costs and expenses:Operations
      and maintenance
            
            
            1,061
            
            
            
            653Depreciation
      and amortization
            
            
            1,424
            
            
            
            939Total
      operating costs and expenses
            
            
            2,485
            
            
            
            1,592Operating
      income (loss) from continuing operations
            
            
            (206
            )
            
            
            893Discontinued
      operations
            
            
            307
            
            
            
            288Operating
      income (loss)
            
            $
            101
            
            
            $
            1,181Capital
      expenditures
            
            $
            (60
            )
            
            $
            361Realized
      average prices:Oil
      and condensate (per
      Bbl)
            
            $
            26.87
            
            
            $
            90.81Natural
      gas (per Mcf)
            
            $
            4.35
            
            
            $
            8.24NGLs
      (per Bbl)
            
            $
            25.89
            
            
            $
            86.18Production
      volumes:Gathering
      volumes (Mfc/d)(a)
            
            
            97,413
            
            
            
            78,075NGLs
      (net equity gallons)
            
            
            224,505
            
            
            
            —Condensate
      (net equity gallons)
            
            
            647,460
            
            
            
            449,862Natural
      gas  long position (MMbtu/d)(a)
            
            
            500
            
            
            
            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.


(b)
            Includes
      operations related to the Millennium Acquisition effective October 1,
      2008.




Revenues and Cost of Natural Gas and
Natural Gas Liquids.During the three months ended March 31, 2009
the South Texas Segment contributed $2.3 million in revenues minus cost of
natural gas and natural gas liquids as compared to $2.5 million for the period
ended March 31, 2008.  We were negatively impacted by lower NGL and
condensate pricing during the three months ended March 31, 2009 as compared
to the three months ended March 31, 2008.   This decline was
offset by the impact of the assets acquired as part of the Millennium
Acquisition which contributed revenue minus cost of natural gas and natural gas
liquids by $0.8 million during the three months ended March 31,
2009.




Operating Expenses.Operating
expenses for the three months ended March 31, 2009 were $1.1 million
compared to $0.7 million in for the three months ended March 31,
2008.  The major item impacting the $0.4 million increase in operating
expense was three months of expenses associated with operating the assets
acquired as part of the Millennium Acquisition.




Depreciation and Amortization.Depreciation and amortization expenses for the three months ended
March 31, 2009 were $1.4 million compared to $0.9 million in for the three
months ended March 31, 2008.  The major item impacting the $0.5
million increase was three months of depreciation and amortization of the assets
acquired as part of Millennium Acquisition.




Capital Expenditures.Capital
expenditures for the three months ended March 31, 2009 were ($0.1) million
compared to $0.4 million in for the three months ended March 31, 2008. We
classify capital expenditures as either maintenance capital which represents
routine well connects and capitalized maintenance activities or as growth
capital which represents organic growth projects.


32
 Table of Contents


Discontinued
Operations.On April 1, 2009, we sold our producer services
line of business, and thus have classified the revenues minus the cost of
natural gas and natural gas liquids as discontinued
operations.  During the three months ended March 31, 2009, this
business generated revenues of $26.8 million and cost of natural gas and natural
gas liquids of $26.5 million, as compared to revenues of $62.6 million and cost
of natural gas and natural gas liquids of $62.4 million during the three months
ended March 31, 2008.




Gulf
of Mexico Segment


Three Months Ending
              March 31,2009(b)
            
            
            2008($
      in thousands,
              except
      for realized prices)Revenues:Sales
      of natural gas, NGLs, oil and condensate
            
            $
            6,222
            
            
            $
            —Gathering
      and treating services
            
            
            88
            
            
            
            —Total
      revenues
            
            
            6,310
            
            
            
            —Cost
      of natural gas and natural gas liquids
            
            
            5,192
            
            
            
            —Operating
      costs and expenses:Operations
      and maintenance
            
            
            418
            
            
            
            —Depreciation
      and amortization
            
            
            1,488
            
            
            
            —Total
      operating costs and expenses
            
            
            1,906
            
            
            
            —Operating
      income (loss)
            
            $
            (788
            )
            
            $
            —Capital
      Expenditures
            
            $
            141
            
            
            $
            —Realized
      average prices:Oil
      and condensate (per Bbl)
            
            $
            42.14
            
            
            $
            —Natural
      gas (per Mcf)
            
            $
            6.27
            
            
            $
            —NGLs
      (per Bbl)
            
            $
            27.96
            
            
            $
            —Production
      volumes:Gathering
      volumes (Mfc/d)(a)
            
            
            116,627
            
            
            
            —NGLs
      (net equity gallons)
            
            
            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.


(b)
            Includes
      operations related to the Millennium Acquisition starting on October 1,
      2008.




Revenues and Cost of Natural Gas and
Natural Gas Liquids.The Gulf of Mexico Segment is a new segment and new
area of operations for us in 2008.  We entered into this segment as a
result of the Millennium Acquisition, effective October 1, 2008.During the three months
ended March 31, 2009, the Gulf of Mexico Segment contributed $1.1 million in
revenues minus cost of natural gas and natural gas liquids.  As a
result of damage inflicted by Hurricanes Gustav and Ike, the non –operated
Yscloskey plant did not come back online in mid-January 2009 and the
non-operated North Terrebonne plant came back online in mid-November 2008. We
have reported, are preparing to file insurance claims for, and expect to receive
payment for business interruption caused by Hurricanes Gustav and Ike in the
amount of approximately $1.7 million.  We have not accrued any amounts
related to the business interruption insurance claims.




Operating
Expenses.Operating expenses for the three months ended March
31, 2009 were $0.4 million.  We continued to incur operating expenses
associated with the Yscloskey and North Terrebonne plants while the plants were
undergoing repair for the hurricane damage.  We anticipate that the
costs we incurred for the repair of the two plants will either be covered by
insurance proceeds or by the previous owners pursuant to the Millennium
Acquisition purchase and sale agreement.  During the three months
ended March 31, 2009, we received payment from the Millennium Acquisition escrow
in December, 2008 in the amount of $0.3 million and began canceling common units
held in escrow to satisfy our claims.  We may elect to cancel common
units or wait to receive cash payment from the insurer for future amounts at our
discretion.




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




Capital
Expenditures.Capital expenditures for the three month period
ended March 31, 2009 for the Gulf of Mexico Segment was $0.1
million.


33
 Table of Contents




Upstream
Business (one segment)







Three Months Ending
              March 31,2009
      (a)
            
            
            2008($
      in thousands,
              except
      for realized prices)Revenues:Oil
      and condensate
            
            $
            5,958
            
            
            $
            18,333Natural
      Gas
            
            
            1,895
            
            
            
            7,126NGLs
            
            
            2,226
            
            
            
            8,140Sulfur
            
            
            (440
            )
            
            
            5,367Other
            
            
            39
            
            
            
            58Total
      revenues
            
            
            9,678
            
            
            
            39,024Operating
      costs and expenses:Operations
      and maintenance
            
            
            6,532
            
            
            
            7,589Impairment
            
            
            242
            
            
            
            —Depreciation,
      depletion and amortization
            
            
            9,396
            
            
            
            8,425Total
      operating costs and expenses
            
            
            16,170
            
            
            
            16,014Operating
      income (loss)
            
            $
            (6,492
            )
            
            $
            23,010Capital
      expenditures
            
            $
            1,592
            
            
            $
            2,923Realized
      average prices:Oil
      and condensate (per Bbl)
            
            $
            28.31
            
            
            $
            91.03Natural
      gas (per Mcf)
            
            $
            2.13
            
            
            $
            8.46NGLs
      (per Bbl)
            
            $
            17.98
            
            
            $
            63.87Sulfur (per Long
      ton)
            
            $
            (15.38
            )
            
            $
            204.60Production
      volumes:Oil
      and condensate ( Bbl)
            
            
            210,451
            
            
            
            201,405Natural
      gas (Mcf)
            
            
            890,803
            
            
            
            842,197NGLs
      (Bbl)
            
            
            123,779
            
            
            
            127,453Total
      (Mcfe)
            
            
            2,896,183
            
            
            
            2,815,345Sulfur(Long ton)
            
            
            28,606
            
            
            
            26,232





(a)
            Includes
      operations from the Stanolind Acquisition effective May 1,
      2008.




Revenue. For the three months
ended March 31, 2009 and 2008, the Upstream Segment contributed $9.7 million and
$39.0 million of revenue, respectively.  The decrease in revenue was
due to substantially lower realized prices for oil, natural gas, NGLs and sulfur
and the non-cash mark-to-market of product imbalances, partially offset by three
months of operations related to the assets acquired in the Stanolind
Acquisition.  During the three months ending March 31, 2009,
production averaged 9.9 MMcf/d, 2.3 MBO/d, 1.4 MB/d of NGL’s and 318 LT/d of
sulfur.  The period included three months of production from the
assets acquired in the Stanolind Acquisition which averaged 805
BOE/d.




During
the three months ended March 31, 2009, sulfur sales generated revenues of ($0.4)
million related to the disposal of the sulfur compared to revenue of $5.4
million during the three months ended March 31, 2008.  Historically,
sulfur was viewed as a low value by-product in the production of oil and natural
gas.  Due to an increase in demand in the global fertilizer market
during the first nine months of 2008, the price per long ton peaked at over $600
at the Tampa, Florida market (before effects of net-backs) in September,
2008.  Deterioration in the sulfur market during three months ended
March 31, 2009 has caused the price at the Tampa, Florida market to decline to
$0 per long ton and we are incurring costs to dispose of the sulfur produced at
this time.   We expect this to be an ongoing issue until the
sulfur market returns to a normal demand/supply equilibrium.




Operating Expenses. Operating
expenses, including severance and ad valorem taxes, totaled $6.5 million for the
Upstream Segment during the three months ended March 31, 2009, as compared to
$7.6 million for the three-month period




34
 Table of Contents


endingMarch 31,
2008.  The operating expenses include three months of expenses related
to the assets acquired in the Stanolind acquisition.  The decrease in
operating expense can be attributed to lower well workover expense incurred
during the three months ended March 31, 2009, as compared to the same period in
the prior year and additional expenses being incurred during the three months
ended March 31, 2008 in anticipation of the planned turnaround at the BEC
treating facility in April 2008.




Depreciation, Depletion and
Amortization.Depreciation, depletion and amortization expense for the
three months ended March 31, 2009 was $9.4 million, as compared to $8.4 million
for the three month period ending March 31, 2008 respectively.  The
increase for the three months ended March 31, 2009 compared to the comparable
period in 2008 is due to the depletion expense related to the assets added
through the Stanolind acquisition and the curtailed production during the three
months ended March 31, 2008 ahead of the planned turnaround at the BEC treating
facility in April 2008.  This increase was partially offset by the
decrease in our depletable base as a result of the impairment charges we
incurred during the last three months of fiscal year 2008.




Impairment.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 continue
decline of natural gas prices during the period.  No impairment
charges were incurred during the three months ended March 31, 2008.




Capital
Expenditures.  The Upstream Segment’s maintenance capital
expenditures for the three months ended March 31, 2009 and 2008 was $0.8 million
and $2.9 million, respectively.  Growth capital expenditures during
the three months ended March 31, 2009 totaled $0.8 million and were associated
with the completion of drilling projects associated with properties acquired in
the Stanolind acquisition.  We did not incur any growth capital
expenditures during the three months ended March 31, 2008.  The
maintenance capital expenditures during the three months ended March 31, 2009
were associated with the BEC and Flomaton treating facilities, well completions,
recompletions, workovers, equipping and leasing activities.






Minerals
Business (one segment)




Three Months Ending
              March 31,2009
            
            
            2008($
      in thousands,
              except
      for realized prices)Revenues:Oil
      and condensate
            
            $
            1,676
            
            
            $
            3,367Natural
      Gas
            
            
            865
            
            
            
            2,209NGLs
            
            
            129
            
            
            
            235Lease
      bonus, rentals and other
            
            
            569
            
            
            
            1,147Total
      revenues
            
            
            3,239
            
            
            
            6,958Operating
      costs and expenses:Operations
      and maintenance
            
            
            471
            
            
            
            443Depletion
            
            
            1,675
            
            
            
            2,611Total
      operating costs and expenses
            
            
            2,146
            
            
            
            3,054Operating
      income (loss)
            
            $
            1,093
            
            
            $
            3,904Realized
      average prices:Oil
      and condensate (per Bbl)
            
            $
            38.95
            
            
            $
            89.00Natural
      gas (per Mcf)
            
            $
            3.07
            
            
            $
            6.99NGLs
      (per Bbl)
            
            $
            22.59
            
            
            $
            56.15Production
      volumes:Oil
      and condensate ( Bbl)
            
            
            43,026
            
            
            
            37,833Natural
      gas (Mcf)
            
            
            282,202
            
            
            
            315,956NGLs
      (Bbl)
            
            
            5,711
            
            
            
            4,185Total
      (Mcfe)
            
            
            574,624
            
            
            
            568,064




Revenue.  For the three months ended March 31, 2009 our revenue
was $3.2 million as compared to $7.0 million for three months ended March 31,
2008.  The decrease in revenue was due to decreases in commodity
prices offset by slightly higher production volumes.




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 are at their
current levels. We have observed rapid and significant reductions in the active
drilling rig count in virtually every producing basin of the United States,
except for the Haynesville and Marcellus shale plays. The new sources of
production that we expect to 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.  During the three months ended March 31, 2009, as a result of
regeneration we received an initial royalty payment for 73 new
wells.




Additionally,
we received approximately $0.6 million and $1.1 million in bonus and delay
rental payments during the three months ended March 31, 2009 and March 31, 2008,
respectively. Substantially all of this was derived from our ownership in the
minerals. 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.  We do expect to receive some level
of bonus payments in the future, however.




Operating Expenses. Operating
expenses of $0.5 million, for the three months ended March 31, 2009 as compared
to $0.4 million for the three months ended March 31, 2008 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, 2009 was $1.7 million, as
compared to $2.6 million for the three months ended March 31,
2008.  The decrease in depletion expense for the three months ended
March 31, 2009, as compared to the same period in the prior year is due to an
incorrect rate being used to calculate depletion causing an overstatement of
depletion during the three months ended March 31, 2008.  An adjustment
of $0.7 million was recorded during the three months ended June 30, 2008 to
correct this overstatement.




35
 Table of Contents




Corporate
Segment






Three
      Months Ended
              March 31,2009
            
            
            2008($
      in thousands)Revenues:Unrealized
      commodity derivative losses
            
            $
            (4,522
            )
            
            $
            (33,072
            )Realized
      commodity derivative (losses) gains
            
            
            30,778
            
            
            
            (12,575
            )Total
      revenues
            
            
            26,256
            
            
            
            (45,647
            )Expenses:General
      and administrative
            
            
            12,538
            
            
            
            11,242Depreciation
      and amortization
            
            
            213
            
            
            
            192Total
      costs and expenses
            
            
            12,751
            
            
            
            11,434Operating
      income (loss)
            
            
            13,505
            
            
            
            (57,081
            )Other
      income (expense):Interest
      income
            
            
            32
            
            
            
            301Other
      income
            
            
            560
            
            
            
            1,547Interest
      expense, net
            
            
            (7,539
            )
            
            
            (9,104
            )Unrealized
      interest rate derivatives gains (losses)
            
            
            3,099
            
            
            
            (13,660
            )Realized
      interest rate derivatives gains (losses)
            
            
            (3,482
            )
            
            
            (101
            )Other
      expense
            
            
            (267
            )
            
            
            (215
            )Total
      other income (expense)
            
            
            (7,597
            )
            
            
            (21,232
            )Income
      (loss) before taxes
            
            
            5,908
            
            
            
            (78,313
            )Income
      tax (benefit) provision
            
            
            (2,730
            )
            
            
            (102
            )Segment
      gain (loss)
            
            $
            8,638
            
            
            $
            (78,211
            )




Revenues. As a master limited
partnership, we intend to distribute Available Cash (as defined in our
partnership agreement) every quarter to our unitholders. The volatility inherent
in commodity prices generates uncertainty around achieving a steady flow of
available cash. We counter this by entering into certain derivative transactions
to reduce our exposure to commodity price risk and reduce uncertainty
surrounding our cash flows.




Our
Corporate Segment’s revenues, which solely include our commodity derivatives
activity, increased to a gain of $26.3 million for the three months ended
March 31, 2009, from a loss of $45.6 million for the three months ended
March 31, 2008. As a result of our commodity hedging activities, revenues
include a total realized gain of $30.8 million on risk management activity
that was settled during the three months ended March 31, 2009, and an
unrealized mark-to-market loss of $4.5 million for three months ended
March 31, 2009, as compared to a realized loss of $12.6 million on
risk management activity that was settled for the three months ended
March 31, 2008 and an unrealized mark-to-market net loss of
$33.1 million for the three months ended March 31,
2008.  Included with our unrealized commodity derivative gains
(losses) we recorded amortization of put premiums and other derivative costs, of
$12.2 million and $2.3 million during the three months ended March 31, 2009 and
2008, 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, 2009 reflects forward curve price movements during
the three-month period for commodities underlying the derivative
instruments.  The unrealized mark-to-market results for the three
months ended March 31, 2009 and 2008 had no impact on cash activities for
those periods, and as such, 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. Conversely, negative commodity price movements affecting our
revenues and costs are expected to be partially offset by our executed
derivative instruments.




General and Administrative
Expenses. General and administrative expenses increased by
$1.3 million from $11.2


36
 Table of Contents


million
for the three months ended March 31, 2008 to $12.5 million for the three
months ended March 31, 2009. This growth in general and administrative
expenses was mostly driven by increased headcount in our corporate office as a
result of our 2008 acquisitions and our recruiting efforts in accounting,
back-office, engineering, land and operations-related corporate personnel
associated with being a public partnership.  Corporate-office payroll
expenses increased by $3.3 million as a result of the increased
headcount.  Included within the increased corporate-office payroll
expenses was an increase of $1.1 million related to equity-based compensation,
included $0.4 million related to the allocation of expense from Eagle Rock
Holdings, L.P. due its issuance of Tier I units to one of our executive
employees.  Included in the three months ended March 31, 2009 was a
one time charge of $0.1 million for severance payments due to a reduction in
workforce due to the economic recession and slow down in activity by the energy
industry.   The Partnership expects to lower its overall general
and administrative expenses going forward in 2009 due to the reduction in
workforce actions taken in the three months ended March 31, 2009. Due to
increase in corporate-office headcount, contract labor and other outside
professional services decreased by $1.3 million during the three months ended
March 31, 2009 as compared to the three months ended March 31,
2008.




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 expense, which includes both realized and unrealized gains and
losses from our interest rate swaps, decreased to expense of $7.6 million for
the three months ended March 31, 2009, as compared to expense of $21.2 million
for the three months ended March 31, 2009.  During the three months
ended March 31, 2009, we incurred realized losses from our interest rate swaps
of $3.5 million, as compared to a realized loss of $0.1 million during the three
months ended March 31, 2008. We also incurred unrealized mark-to-market gains of
$3.1 million during the three months ended March 31, 2009, as compared to
unrealized mark-to-market losses of $13.7 million for the same period in
2008.  These unrealized mark-to-market losses did not have any impact
on cash activities for the period, and are excluded by definition from our
calculation of Adjusted EBITDA.




Interest
expense, net, decreased to $7.5 million for the three months ended March 31,
2009, as compared to $9.1 million during the same period in the prior
year.  Interest expense, net 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, net is due to lower
LIBOR rates during the three months ended March 31, 2009 as compared to the
three months ended March 31, 2008, partially offset by higher debt balances in
the 2009 period as a result of our acquisition made in 2008.





Income Tax (Benefit)
Provision. Income tax benefit recorded during the three months ended
March 31, 2009 reflects the Texas Margin Tax recorded during the current
year offset by the reduction of the deferred tax liability created by the
book/tax differences as a result of the acquisition of Redman Energy Corporation
in 2007 and Stanolind Oil and Gas Corp. in 2008.




Adjusted
EBITDA




Adjusted
EBITDA, as defined, decreased by $11.4 million from $52.5 million for the three
months ended March 31, 2008 to $41.1 million for the three months ended
March 31, 2009.




As
described above, for the three months ended March 31, 2009, revenues minus cost
of natural gas and natural gas liquids for the Midstream Segment (including the
Texas Panhandle, East Texas/Louisiana, South Texas and the Gulf of Mexico
Segment) declined by $22.3 million as compared to the three months ended
March 31, 2008. For the three months ended March 31, 2009, revenues for our
Upstream and Mineral Segments declined by $31.0 million (excluding non-cash
mark-to-market of product imbalances of $2.0 million), as compared to the same
period in the prior year.  Our Corporate Segment’s realized commodity
derivatives gain increased by $43.4 million as compared to the three months
ended March 31, 2008. This resulted in a decline of $10.0 million of total
incremental revenues minus cost of natural gas and natural gas liquids, adjusted
to exclude the impact of unrealized commodity derivatives not included in the
calculation of Adjusted EBITDA, as compared to the three months ended
March 31, 2008.




Operating
expenses (including taxes other than income), increased by $2.3 million for our
Midstream Segment with respect to the three months ended March 31, 2009,
while operating expenses for our Upstream and Minerals Segments decreased by
$1.0 million. This resulted in total incremental operating expenses of $1.4
million, as compared to the three months ended March 31, 2008.




General
and administrative expense, captured in the Corporate Segment, increased by $0.8
million adjusted to exclude non-cash compensation charges related to our LTIP
program.


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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 $9.9 million, operating
expenses increased by $1.3 million and general and administrative expenses
increased by $0.2 million, resulting in the decrease to Adjusted EBITDA during
the three months ended March 31, 2009, as compared to the three months
ended March 31, 2008.




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




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




In
connection with making the distribution decision for the first quarter of 2009,
the Board of Directors decided to  reduce the quarterly distribution
paid with respect to the first quarter of 2009 to $0.025 per common unit as
compared to $0.41 per common and subordinated unit paid for the fourth quarter
of 2008 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 for future
periods.  The cash not distributed will be used primarily to reduce
our outstanding debt under our revolving credit facility and to continue the
execution of our hedge strategy to maintain future cash flows.  We
anticipate that the Board of Directors will continue this strategy until such
time as the commodity prices impacting our business and the general economy
return to levels conducive to increasing the cash distributions to be paid to
the unitholders.




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 outstanding
indebtedness under our revolving credit facility in order to return to a ratio
of outstanding debt to Adjusted EBITDA, or “leverage ratio,” with respect to our
Midstream and Minerals Businesses of approximately 3.0 to 3.5, which we believe
to be appropriate in light of these more turbulent economic conditions and more
in-line with historical midstream industry standards.  Absent any
other adjustments or changes to our business or our expectations, to meet this
goal we anticipate that we may be required to reduce debt by as much as $200
million.  The actual amount and timing of our 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.  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, 2008 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.  The continued credit crisis and related turmoil in
the global financial system has caused restricted access to the capital markets,
particularly for non-investment grade companies like us.  If these
conditions continue, we expect our level of acquisition activity to be lower
going forward than that which we experienced in 2007 and 2008.  The
ratio of debt and equity issued and cash reserves, if any, will
be


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determined
by our management and our Board of Directors as deemed appropriate.




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, 2009, working capital was $94.7 million as compared to $57.3
million as of December 31, 2008.




The net
increase in working capital of $37.4 million from December 31, 2008 to
March 31, 2009, resulted primarily from the following factors:




•
            cash
      balances and marketable securities, net of due to affiliates, decreased
      overall by $15.3 million and was impacted primarily by the distributions
      paid on February 15, 2009 with respect to the fourth quarter of 2008
      financial results, the results of operations, timing of capital
      expenditures payments, and financing activities including our debt
      activities (the due to affiliate liability of $11.7 million as of
      March 31, 2009 is owed to Eagle Rock Energy G&P,
      LLC);




•
            trade
      accounts receivable decreased by $26.9 million primarily from the impact
      of lower commodity prices on our consolidated
  revenue;




•
            risk
      management net working capital balance increased by a net $31.3 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;




•
            accounts
      payable decreased by $40.4 million from December 31, 2008 primarily
      as a result of activities and timing of payments, including capital
      expenditures activities and lower commodity prices;
  and




•
            accrued
      liabilities decreased by $5.5 million primarily reflecting payment of
      employee benefit accruals and the timing of payment of unbilled
      expenditures related primarily to capital
  expenditures.




Cash
Flows Three Months Ended March 31, 2009 Compared to Three Months Ended
March 31, 2008




Cash Flow from Operating
Activities. Decrease of $37.8 million during the three months
ended March 31, 2009 as compared to the three months ended March 31,
2008 is the result of lower commodity prices across our three businesses and
reduced NGL equity volumes in the Midstream Business, changes in working
capital, as discussed above, and payments made for the resetting of commodity
hedges.




Cash Flows from Investing
Activities. Cash flows used for investing activities for the three
months ended March 31, 2009, as compared to the three months ended
March 31, 2008, increased by $5.1 million. The investing activities
for the current period reflect additions to property, plant and equipment
expenditures of $13.1 million versus $8.2 million for the prior year
period.





Cash Flows from Financing
Activities. Cash flows used for financing activities during the
three months ended March 31, 2009, increased by $51.6 million over the
three months ended March 31, 2008. Key differences between periods include
proceeds from our revolving credit facility of $38.0 million during the three
months ended March 31, 2009, as compared to a repayment of $10.1 million made
during the three months ended March 31, 2008.  Distributions to
members represented a cash outflow of $31.6 million during the three months
ended March 31, 2009, as compared to $28.5 million during the three
months ended March 31, 2008.




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
credit facility covenants and continue to execute on our distribution
objectives.  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.  During the three months ended March 31, 2009, as part of this
strategy, we executed a series of hedging transactions that involved the
unwinding of a portion of existing “in-the-money” 2011 and 2012 WTI crude oil
swaps and collars, and the unwinding of two “in-the-money” 2009 WTI crude oil
collars.  With these transactions, and an additional $13.9 million of
cash, we purchased a 2009 WTI crude oil swap on 60,000 barrels per month
beginning January 1, 2009 at $97 per barrel.


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Revolving
Credit Facility and Debt Covenants




On
December 13, 2007, we entered into a credit agreement with Wachovia Bank,
National Association, as administrative agent and swing line lender, Bank of
America, N.A., as syndication agent; HSH Nordbank AG, New York Branch; the Royal
Bank of Scotland, plc; and BNP Paribas, as co-documentation agents, and the
other lenders who are parties to the agreement with aggregate commitments of up
to $800 million.  During the year ended December 31, 2008, we
exercised $180 million of our $200 million accordion feature under the credit
facility, which increased the total commitment to $980
million.  Pursuant to the credit facility we may, at our request and
subject to the terms and conditions of the credit facility, increase our
commitments by an additional $20 million to an aggregate of
$1 billion.  As a result of Lehman Brothers’ bankruptcy filing,
the amount of available commitments was reduced by the unfunded portion of
Lehman Brothers’ commitment in an amount of approximately $9.1
million.   As of March 31, 2009, unused capacity available to us
under the new credit agreement, based on outstanding debt and compliance with
financial covenants as of that date, was approximately $134
million.  As of the date of this filing, our availability under the
credit agreement was approximately $100 million, representing a 26% reduction
that was a result of the reduction to our borrowing base that occurred as a
result of the scheduled redetermination in late April 2009, but was offset by
our payment of $17 million toward reducing our outstanding debt between March
31, 2009 and the date of this filing.  The credit agreement is
scheduled to mature on December 13, 2012.




Given the
current state of the banking industry worldwide, we are pleased with the degree
of diversification within our lender group. After the upsizing of our credit
facility as described above, our credit facility now includes the participation
of 20 financial institutions. As of today, all of our banks’ commitments, with
the exception of Lehman Brothers’ commitment, remain in place and have funded in
response to our borrowing notices.  A Lehman Brothers subsidiary has
an approximately 2.6% participation in the Partnership’s credit
facility.  Due to the continuing difficulties in the credit and
capital markets, we place a greater premium on liquidity.  As a
result, our Board has elected to create a cash reserve against available cash
and temporarily reduce quarterly distribution rate from $0.41 per unit to $0.025
per common unit (starting with the distribution for the first quarter of 2009)
in part to enable repayment of outstanding debt under our senior revolving
credit facility.  Pursuant to our partnership agreement, our general
partner will also receive a distribution of $0.025 per general partner
unit.




Our
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, 2009, we were in compliance with our
covenants under the credit facility. Our interest coverage ratio, as defined in
the credit agreement (i.e., Consolidated EBITDA divided by Consolidated Interest
Expense), was 6.0 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 4.0 as compared to a
maximum leverage ratio of 5.0 times (5.25 times until March 31, 2009 due to the
Millennium Acquisition).  As of March 31, 2009, the borrowing base for
our Upstream Business was $206 million.  Primarily as a result of
lower expected future commodity prices, our borrowing base was re-determined in
April 2009 to $135 million (which will result in a higher allocation of
indebtedness to our Midstream and Minerals Businesses and a rise in our leverage
ratio in future quarters).  The reduction in borrowing base was a
contributing factor to the decrease in our quarterly distribution, beginning
with the first quarter of 2009 (as discussed above).  It may also
contribute to our taking steps (e.g., further hedge resets) to reduce our
leverage and enhance our Adjusted Consolidated EBITDA, as defined in our credit
facility. Based on the distribution reduction and our intention to take further
steps to manage our Adjusted Consolidated EBITDA, we believe that we will remain
in covenant compliance for the remainder of 2009.




Capital
Requirements




We
anticipate that we will have sufficient liquidity and access to capital to grow,
maintain and commercially exploit the Midstream Business (all four segments),
Upstream Segment, and Mineral Segment assets.




As an
operator of upstream assets and as a working interest owner, our capital
requirements have increased to maintain those properties and to replace
depleting resources. We anticipate that we will meet these requirements through
cash generated from operations, equity issuances, or debt incurrence; however,
we cannot provide assurances that we will be able to obtain the necessary
capital under terms acceptable to us.




Our 2009
capital budget anticipates that we will spend approximately $40.0 million in
total for the year on our existing assets.  Our 2009 capital budget
anticipated that we would spend approximately $12.4 million in the three months
ended March 31, 2009 on our existing assets. We actually spent
approximately $14.8 million in total during that period as a result of
accelerating high return-on-investment projects.  We anticipate lower
capital spending during the remainder of 2009.




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:


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•
            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 and cash flow levels in the near
      future.




Since our
inception in 2002, we have made substantial growth capital expenditures. We
anticipate 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. That
said, we continually review opportunities for both organic growth projects and
acquisitions which will enhance our financial
performance.  De-levering our business and enhancing our liquidity
such that we once again have the ability to develop and maintain sources of
funds to meet our capital requirements is 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 (though
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 we do not anticipate converting it to a draw from our revolving
credit facility.




Off-Balance
Sheet Obligations




We have
no off-balance sheet transactions or obligations.




Recent
Accounting Pronouncements




In
December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS
No. 141R”), which replaces SFAS 141. SFAS 141R requires that all assets,
liabilities, contingent consideration, contingencies and in-process research and
development costs of an acquired business be recorded at fair value at the
acquisition date; that acquisition costs generally be expensed as incurred; that
restructuring costs generally be expensed in periods subsequent to the
acquisition date; and that changes in accounting for deferred tax asset
valuation allowances and acquired income tax uncertainties after the measurement
period impact income tax expense.  SFAS No. 141R is effective for
business combinations for which the acquisition date is on or after the
beginning of the first annual reporting period beginning on or after December
15, 2008, with the exception for the accounting for valuation allowances on
deferred tax assets and acquired tax contingencies associated with
acquisitions.  SFAS No. 141R amends SFAS No. 109, Accounting for Income Taxes,such that adjustments made to valuation allowances on deferred taxes and
acquired tax contingencies associated with acquisitions that closed prior to the
effective date of SFAS No. 141R would also apply the provisions of SFAS No.
141R.  SFAS No. 141R was effective for us as of January 1, 2009 but
the impact of the adoption on our consolidated financial statements will depend
on the nature and the extent of business combinations occurring after January 1,
2009.




In
December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in
Consolidated Financial Statements—an amendment of ARB No. 51” (“SFAS
No. 160”). SFAS No. 160 requires that accounting and reporting for
minority interests will be recharacterized as noncontrolling interests and
classified as a component of equity. SFAS 160 also establishes reporting
requirements that provide sufficient disclosures that clearly identify and
distinguish between the interests of the parent and the interests of the
noncontrolling owners.  SFAS No. 160 was effective for us as of
January 1, 2009 and did not have a material impact on our consolidated results
of operations or financial position.




In
February 2008, the FASB issued FASB Staff Position (“FSP”) No. FAS 157-2,
“Effective Date of FASB Statement No. 157” (“FSP FAS 157-2”), which delays
the effective date of SFAS 157 for all nonfinancial assets and nonfinancial
liabilities, except those that are recognized or disclosed at fair value in the
financial statements on at least an annual basis, until fiscal years beginning
after November 15, 2008.  FSP FAS 157-2 was effective for us as
of January 1, 2009 and did not have a material impact on our consolidated
results of operations or financial position.  Non-financial assets and
liabilities that we measure at fair value on a non-recurring basis consists
primarily of property, plant and equipment, intangible assets and asset
retirement obligations, which are subject to fair value adjustments in certain
circumstances (for example, when there is evidence of
impairment).


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 Table of Contents




In March
2008, the FASB issued Statement No. 161, Disclosures About Derivative
Instruments and Hedging Activities(“SFAS No. 161”). SFAS
No. 161 requires enhanced disclosures to help investors better understand
the effect of an entity’s derivative instruments and related hedging activities
on its financial position, financial performance, and cash
flows.  SFAS No. 161 was effective for us as of January 1,
2009.  See Note 11 to the Unaudited Condendsed Consolidated Financial
Statements for the additional disclosures required under FAS No. 161 related to
our derivative instruments.




In March
2008 the FASB approved EITF Issue No. 07-4, Application of the Two-Class Method
under FASB Statement No. 128, Earnings per Share, to Master Limited
Partnerships(“EITF 07-4”), which requires that master limited
partnerships use the two-class method of allocating earnings to calculate
earnings per unit.  EITF Issue No. 07-4 was effective for us as
of January 1, 2009 and the impact on our earnings per unit calculation has been
retrospectively applied to March 31, 2008 (see Note 16 to our unaudited
condensed consolidated financial statements).





In April
2008, the FASB issued FASB Staff Position (“FSP”) No. SFAS 142-3, Determination of the Useful Life of
Intangible Assets (“FSP SFAS 142-3”).  FSP SFAS 142-3 amends the
factors that should be considered in developing renewal or extension assumptions
used to determine the useful life of a recognized intangible asset under SFAS
No. 142, Goodwill and Other
Intangible Assets (“SFAS 142”).  The intent of FSP SFAS 142-3 is to
improve the consistency between the useful life of a recognized intangible asset
under SFAS 142 and the period of expected cash flows used to measure the fair
value of the asset under SFAS No. 141R (revised 2007), Business Combinations (“SFAS
141R”) and other applicable accounting literature.  FSP SFAS No. 142-3 was
effective for the Partnership as of January 1, 2009 but the impact of the
adoption on the Partnership’s consolidated financial statements will depend on
the nature and the extent of business combinations occurring after January 1,
2009.




In May
2008, the FASB issued SFAS No. 162, Hierarchy of Generally Accepted
Accounting Principles (“SFAS 162”).  This statement is intended to
improve financial reporting by identifying a consistent framework, or hierarchy,
for selecting accounting principles to be used in preparing financial statements
of nongovernmental entities that are presented in conformity with GAAP. 
This statement will be effective 60 days following the U.S. Securities and
Exchange Commission’s approval of the Public Company Accounting Oversight Board
amendment to AU Section 411, The Meaning of Present Fairly in
Conformity with Generally Accepted Accounting Principles.  The
adoption of SFAS 162 did not have a material impact on our consolidated
financial statements.




In June
2008, the FASB issued FSP No. EITF 03-6-1, Determining Whether Instruments
Granted in Share-Based Payment Transactions Are Participating Securities
(“FSP EITF 03-6-1”).  FSP EITF 03-6-1 affects entities that accrue
cash dividends on share-based payment awards during the awards’ service period
when dividends do not need to be returned if the employees forfeit the
awards.  Earnings-per-unit calculations will need to be adjusted
retroactively.  FSP EITF 03-6-1 was effective for the Partnership as
of January 1, 2009 and the impact on our earnings per unit calculation has
been retrospectively applied to March 31, 2008 (see Note 16 to our unaudited
consolidated financial statements).




In
December 2008, the SEC released Final Rule, Modernization of Oil and Gas
Reporting to revise the existing Regulation S-K and Regulation S-X reporting
requirements to align with current industry practices and technological
advances. The new disclosure requirements include provisions that permit the use
of new technologies to determine proved reserves if those technologies have been
demonstrated empirically to lead to reliable conclusions about reserve volumes.
In addition, the new disclosure requirements require a company to (a) disclose
its internal control over reserves estimation and report the independence and
qualification of its reserves preparer or auditor, (b) file reports when a third
party is relied upon to prepare reserves estimates or conducts a reserve audit
and (c) report oil and gas reserves using an average price based upon the prior
12-month period rather than period-end prices. The provisions of this final
ruling will become effective for disclosures in the Partnership’s Annual Report
on Form 10-K for the year ended December 31, 2009.





In April
2009, the FASB issued FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of
Other-Than-Temporary Impairments “FSP FAS 115-2 and FAS
124-2”).  FSP FAS 115-2 and FAS 124-2 amends the other-than-temporary
impairment guidance for debt securities to make the guidance more operational
and to improve the presentation and disclosure of other-than-temporary
impairments in the financial statements. The most significant change is a
revision to the amount of other-than-temporary loss of a debt security recorded
in earnings. FSP FAS 115-2 and FAS 124-2 is effective for interim and annual
reporting periods ending after June 15, 2009.  We do not believe that
the adoption of FSP FAS 115-2 and FAS 124-2 will have a material impact on our
consolidated financial statements.





In April
2009, the FASB issued FSP FAS 157-4, Determining Fair Value When the
Volume and Level of Activity for the Asset or Liability Have Significantly
Decreased and Identifying Transactions That Are Not Orderly(“FSP FAS
157-4”).  FSP FAS 157-4 provides additional guidance for estimating
fair value in accordance with FASB Statement No. 157, Fair Value Measurements, when
the volume and level of activity for the asset or liability have significantly
decreased.  FSP FAS


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157-4
also includes guidance on identifying circumstances that indicate a transaction
is not orderly and emphasizes that even if there has been a significant decrease
in the volume and level of activity for the asset or liability and regardless of
the valuation technique(s) used, the objective of a fair value measurement
remains the same. Fair value is the price that would be received to sell an
asset or paid to transfer a liability in an orderly transaction (that is, not a
forced liquidation or distressed sale) between market participants at the
measurement date under current market conditions.  FSP FAS 157-4 is
effective for interim and annual reporting periods ending after June 15, 2009,
and is applied prospectively.  We do not believe that the adoption of
FSP FAS 157-2 will have a material impact on our consolidated financial
statements.





In April
2009, the FASB issued FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value
of Financial Instruments(“FSP FAS 107-1 and APB 28-1”). FSP FAS 107-1 and APB 28-1
amends FASB Statement No. 107, Disclosures about Fair Value of
Financial Instruments, to require disclosures about fair value of
financial instruments for interim reporting periods of publicly traded companies
as well as in annual financial statements.  FSP FAS 107-1 and APB 28-1
also amends APB Opinion No. 28, Interim Financial Reporting,
to require those disclosures in summarized financial information at interim
reporting periods. FSP FAS 107-1 and APB 28-1 is effective for interim and
annual reporting periods ending after June 15, 2009.  We do not
believe that the adoption of FSP FAS 107-1 and APB 28-1 will have a material
impact on our consolidated financial statements.




Non-GAAP
Financial Measures




We
include in this filing the following non-GAAP financial measure, Adjusted
EBITDA. 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; and other (income) expense. Adjusted EBITDA is used as a
supplemental financial measure by external users of Eagle Rock’s financial
statements such as investors, commercial banks and research analysts. 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, by excluding unrealized derivative gains (losses),
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).




Adjusted
EBITDA should not be considered an alternative to net income, operating income,
cash flows from operating activities or any other measure of financial
performance presented in accordance with GAAP.




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







43
 Table of Contents





Three
      Months Ended
              March 31,2009
            
            
            2008Reconciliation of “Adjusted
      EBITDA” to net cash flows provided by operating activities and net
      loss
            
            ($
      in thousands)Net
      cash flows provided by operating activities
            
            $
            (4,617
            )
            
            $
            33,145Add
      (deduct):Depreciation,
      depletion, amortization and impairment
            
            
            (30,305
            )
            
            
            (25,745
            )Amortization
      of debt issuance costs
            
            
            (267
            )
            
            
            (217
            )Risk
      management portfolio value changes
            
            
            12,475
            
            
            
            (46,732
            )Net
      realized (loss) gain on derivatives
            
            
            4,317
            
            
            
            (2,278
            )Other
            
            
            730
            
            
            
            142Accounts
      receivables and other current assets
            
            
            (24,575
            )
            
            
            30,214Accounts
      payable, due to affiliates and accrued liabilities
            
            
            41,104
            
            
            
            (17,691
            )Other
      assets and liabilities
            
            
            (1,407
            )
            
            
            834Net
      loss
            
            
            (2,545
            )
            
            
            (28,328
            )Add
      (deduct):Interest
      (income) expense, net
            
            
            11,256
            
            
            
            9,119Depreciation,
      depletion and amortization
            
            
            30,305
            
            
            
            25,745Income
      tax (benefit) provision
            
            
            (2,730
            )
            
            
            (102
            )EBITDA
            
            
            36,286
            
            
            
            6,434Add
      (deduct):Unrealized
      risk management losses
            
            
            1,423
            
            
            
            46,732Equity-based
      compensation expense
            
            
            2,231
            
            
            
            1,159Non-cash
      mark-to-market of Upstream product imbalances
            
            
            2,231
            
            
            
            1,159Discontinued
      operations
            
            
            (307
            )
            
            
            (288
            )Other
      income
            
            
            (560
            )
            
            
            (1,547
            )ADJUSTED
      EBITDA
            
            $
            41,105
            
            
            $
            52,490




44
 Table of Contents


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 and other commodities as a result of our gathering, processing,
producing and marketing activities, which produce a naturally long position in
crude oil, NGLs 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.




We have
not designated our derivative contracts as accounting hedges under SFAS
No. 133, Accounting for
Derivative Instruments and Hedging Activities. 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,
2009, the Partnership recorded a gain on risk management instruments of $26.3
million representing a fair value (unrealized) gain of $7.6 million,
amortization of put premiums of $12.2 million and net (realized) settlement gain
of $30.8 million.  For the three months ended March 31, 2008, the
Partnership recorded a loss on risk management instruments of $45.6 million
representing a fair value (unrealized) loss of $30.8 million, amortization of
put premiums of $2.3 million and net (realized) settlement losses of
$12.6million.  As of March 31, 2009, the fair value asset of these
commodity contracts, including put premiums, totaled approximately $118.6
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 credit agreement. To mitigate its interest rate risk, the Partnership
has entered into various interest rate swaps. These swaps convert the
variable-rate term loan into a fixed-rate obligation. The purpose of entering
into this swap is to eliminate interest rate variability by converting
LIBOR-based variable-rate payments to fixed-rate payments through the end of
2010. 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 under SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities. 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, 2009, the
Partnership recorded a fair value (unrealized) gain of $3.1 million and a
realized loss of $3.5 million.  For the three months ended March 31,
2008, the Partnership recorded a fair value (unrealized) loss of $13.7 million
and a realized loss of $0.1 million.  As of March 31,
2009,




45
 Table of Contents


the fair
value liability of these interest rate contracts totaled approximately $36.8
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, Comerica Bank, Barclays Bank
PLC, The Royal Bank of Scotland plc and its agent Sempra Energy Trading LLC,
Bank of America N.A., J Aron and Company (an affiliate of Goldman Sachs) and
British Petroleum.






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 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 first quarter of fiscal year 2009 that have materially affected, or
are reasonably likely to materially affect, our internal control over financial
reporting.





































46
 Table of Contents




PART II.OTHER INFORMATION




Item 1.
            LegalProceedings.




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.




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




Subsequent
to December 31, 2008, we received additional Notices of Enforcement (“NOEs”) and
a Notice of Violation (“NOV”) from the TCEQ related to air compliance matters in
our Texas Panhandle Segment.  We expect to receive additional NOEs or
NOVs from the TCEQ from time to time throughout 2009.  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 us to date.






Item 1A.            Risk
Factors.




We
disclosed in our Form 8-K filed with the Securities and Exchange Commission on
April 29, 2009 additional risks relating to the ownership of common units of the
Partnership.  We disclosed these additional risks in light of the
distribution reduction we announced on April 29, 2009, for our distribution to
be paid on May 15, 2009 with respect to the first quarter of
2009.  These additional risks are as follows:




We
may not be able to pay the minimum quarterly distribution and any arrearages on
the common units.




Based on
current market conditions and the outlook for commodity prices, we recently
announced that quarterly distributions on our common units are being reduced
below the minimum quarterly distribution as defined in our partnership
agreement.  As described in the partnership agreement, during the
subordination period, our common units carry arrearage rights. Although the
common unitholders have arrearage rights, the unitholders are not entitled to
receive these arrearages, which may never be paid.  We can give no
assurances that the minimum quarterly distribution and any arrearages will ever
be paid on the common units.  However, we must first pay all
arrearages in addition to current minimum quarterly distributions before
distributions can be made to holders of our subordinated units and our incentive
distribution rights, and we generally must first pay all arrearages before
conversion of our subordinated units can occur.




Limited
partners may be required to pay taxes on their share of our income even if they
do not receive any cash distributions from us.




Because
our unitholders will be treated as partners to whom we will allocate taxable
income which could be different in amount than the cash we distribute, limited
partners will be required to pay any federal income taxes and, in some cases,
state and local income taxes on their share of our taxable income even if no
cash distributions were received from us.  Our taxable income for a
taxable year may include income without a corresponding receipt of cash by us,
such as accrual of future income, original issue discount or cancellation of
indebtedness income.  We may not pay cash distributions equal to a
limited partner’s share of our taxable income or even equal to the actual tax
liability that results from that income.




Except as
disclosed above, the risks previously disclosed in our annual report on
Form 10-K for the year ended




47
 Table of Contents


December 31,
2008 have not changed in any material respect.






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.
            Submission
      of Matters to a Vote of Security
Holders.




None.




Item 5.
            Other
      Information.




In
connections with our preparation of financial statements for the three months
ended March 31, 2009, management determined charges for impairments of
approximately $0.2 million for our Upstream Business, were required to be taken
based primarily on the decrease in natural gas prices.  It is not
expected that this impairment will result in future cash
expenditures.  The disclosure set forth in this Item 5 and elsewhere
in this report is included in this report in accordance with the instructions to
Item 2.06 of Form 8-K.




Item 6.
            Exhibits.




2.1
            Amendment
      No. 2 to the Partnership Interest Purchase Agreement dated February 9,
      2009 among Eagle Rock Energy Partners, L.P. and Millennium Midstream
      Partners, L.P. (incorporated by reference to Exhibit 2.9 of the
      registrant’s annual report on Form 10-K filed with the Commission on March
      13, 2009)2.2
            Amendment
      No. 3 to the Partnership Interest Purchase Agreement dated February 27,
      2009 among Eagle Rock Energy Partners, L.P. and Millennium Midstream
      Partners, L.P. (incorporated by reference to Exhibit 2.10 of the
      registrant’s annual report on Form 10-K filed with the Commission on March
      13, 2009)10.1
            Eagle
      Rock Energy G&P, LLC 2009 Short Term Incentive Bonus Plan effective
      February 4, 2009 (incorporated by reference to Exhibit 10.19 of the
      registrant’s current report on Form 8-K filed with the Commission on
      February 9, 2009)10.2
            Eagle
      Rock Energy Partners Long-Term Incentive Plan (Amended and Restated
      Effective February 4, 2009) (incorporated by reference to Exhibit 10.20 of
      the registrant’s annual report on Form 10-K filed with the Commission on
      March 13, 2009)31.1
            Certification
      by Joseph A. Mills pursuant to Section 302 of the Sarbanes-Oxley Act of
      200231.2
            Certification
      by Jeffrey P. Wood pursuant to Section 302 of the Sarbanes-Oxley Act of
      200232.1
            Certification
      by Joseph A. Mills pursuant to Section 906 of the Sarbanes-Oxley Act of
      2002 and 18 U.S.C. Section 135032.2
            Certification
      by Jeffrey P. Wood pursuant to Section 906 of the Sarbanes-Oxley Act of
      2002 and 18 U.S.C. Section 1350








48


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 8, 2009
            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.















































EAGLE
ROCK ENERGY PARTNERS, L.P.





EXHIBIT
INDEX







2.1
            Amendment
      No. 2 to the Partnership Interest Purchase Agreement dated February 9,
      2009 among Eagle Rock Energy Partners, L.P. and Millennium Midstream
      Partners, L.P. (incorporated by reference to Exhibit 2.9 of the
      registrant’s annual report on Form 10-K filed with the Commission on March
      13, 2009)2.2
            Amendment
      No. 3 to the Partnership Interest Purchase Agreement dated February 27,
      2009 among Eagle Rock Energy Partners, L.P. and Millennium Midstream
      Partners, L.P. (incorporated by reference to Exhibit 2.10 of the
      registrant’s annual report on Form 10-K filed with the Commission on March
      13, 2009)10.1
            Eagle
      Rock Energy G&P, LLC 2009 Short Term Incentive Bonus Plan effective
      February 4, 2009 (incorporated by reference to Exhibit 10.19 of the
      registrant’s current report on Form 8-K filed with the Commission on
      February 9, 2009)10.2
            Eagle
      Rock Energy Partners Long-Term Incentive Plan (Amended and Restated
      Effective February 4, 2009) (incorporated by reference to Exhibit 10.20 of
      the registrant’s annual report on Form 10-K filed with the Commission on
      March 13, 2009)31.1
            Certification
      by Joseph A. Mills pursuant to Section 302 of the Sarbanes-Oxley Act of
      200231.2
            Certification
      by Jeffrey P. Wood pursuant to Section 302 of the Sarbanes-Oxley Act of
      200232.1
            Certification
      by Joseph A. Mills pursuant to Section 906 of the Sarbanes-Oxley Act of
      2002 and 18 U.S.C. Section 135032.2
            Certification
      by Jeffrey P. Wood pursuant to Section 906 of the Sarbanes-Oxley Act of
      2002 and 18 U.S.C. Section 1350